NUREG-1839

Safety Evaluation Report

Related to the License Renewal of

the Point Beach Nuclear Plant,

Units 1 and 2

Docket Nos. 50-266 and 50-301

Nuclear Management Company, LLC.

U.S. Nuclear Regulatory Commission

Office of Nuclear Reactor Regulation

Washington, DC 20555-0001
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0

NUREG-1839

Safety Evaluation Report

Related to the License Renewal of

the Point Beach Nuclear Plant,

Units 1 and 2

Docket Nos. 50-266 and 50-301

Nuclear Management Company, LLC.

Manuscript Completed: October 2005

Date Published: December 2005

Prepared by

V. Rodriguez

Division of License Renewal

Office of Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001

:-..Mode I I
ABSTRACT

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

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

Regulatory Commission (NRC) (the staff). By letter dated February 25, 2004, Nuclear

Management Company, LLC (NMC or the applicant) submitted the LRA for PBNP in

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

is requesting renewal of the operating licenses for PBNP Units 1 and 2 (Facility Operating

License Numbers DPR-24 and DPR-27, respectively) for a period of 20 years beyond the

current expiration dates of midnight, October 5, 2010, for Unit 1 and midnight, March 8, 2013,

for Unit 2.

The PBNP units are located about 30 miles SE of Green Bay and about 90 miles NNE of

Milwaukee in east central Wisconsin (Manitowoc County) on the west shore of Lake Michigan.

The NRC issued the construction permit for PBNP Unit 1 on July 19, 1967, and for Unit 2 on

July 25,1968. The operating licenses were issued by the NRC on October 5,1970, for Unit 1

and March 8, 1973 for Unit 2. The PBNP consists of two Westinghouse pressurized light-water

moderated and cooled system units originally designed to generate 1518.5 megawatt thermal

(MWt), or approximately 523.8 megawatt electric (MWe). Each unit has undergone a low

pressure turbine retrofit modification which increases the unit design output to 537,960 kWe.

In 2003, a measurement uncertainty recapture power uprate was performed increasing each

unit's rated thermal power level to 1540 MWt.

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

August 23, 2005, the cutoff date for consideration in the SER. The staff identified open items

and confirmatory items that had to be resolved before the staff could make a final determination

on the application. Sections 1.5 and 1.6 of this report summarize these items and their

resolutions. Section 6 presents the staff's final conclusion on the review of the PBNP

application.

iii
TABLE OF CONTENTS

Abstract................................................................... iii

Table of Contents .................................. v

Abbreviations ............................ xiv

1 Introduction and General Discussion ............................ 1-1

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

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

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

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

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

1.5 Summary of Open Items ... ;1-9

1.6 Summary of Confirmatory Items .. 1-12

1.7 Summary of Proposed License Conditions .. 1-24

2 Structures-and Components Subject to Aging Management Review

2.1 Scoping and Screening Methodology .2-1

2.1.1 Introduction . 2-1

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

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

2.1.2.2 Screening Methodology ............................. 2-8

2.1.3 Staff Evaluation ................ ..... 2-10

2.1.3.1 Scoping Methodology ............................... 2-11

2.1.3.2 Screening Methodology ............ ................. 2-23

2.1.4 Conclusion ........... ...................... 2-26

2.2 Plant-Level Scoping Results . 2-26

2.2.1 Introduction .2-26

2.2.2 Summary of Technical Information in the Application ............. 2-27

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

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

2.3 System Scoping and Screening Results - Mechanical Systems ..... ....... 2-28

2.3.1 Reactor Vessel, Internals, and Reactor Coolant System ..... ..... 2-30

2.3.1.1 Class 1 Piping/Components System ....... ........... 2-30

2.3.1.2 Reactor Vessel ................................... 2-33

2.3.1.3 Reactor Vessel Internals ................. 2-35

- 2.3.1.4 Pressurizer ................. 2-37

2.3.1.5 Steam Generators 2-41

2.3.1.6 Non-Class 1 RCS Components System ...... ......... 2-43

2.3.2 Engineered Safety Features ............................. 2-44

2.3.2.1 Safety Injection System ... ................ 2-45

2.3.2.2 Containment Spray System ......................... 2-47

2.3.2.3 Residual Heat Removal System ............... ....... 2-48

2.3.2.4 Containment Isolation Components System ............ 2-50

v
2.3.3 Auxiliary Systems ............... I....... . 2-52

2.3.3.1 Chemical Volume and Control System . 2-52

2.3.3.2 Component Cooling Water System . 2-54

2.3.3.3 Spent Fuel Cooling System . 2-56

2.3.3.4 Waste Disposal System . 2-59

2.3.3.5 Service Water System ..................... . 2-63

2.3.3.6 Fire Protection System . ..................... 2-69

2.3.3.7 Heating Steam System .2-78

2.3.3.8 Emergency Power System .2-80

2.3.3.9 Containment Ventilation System .2-85

2.3.3.10 Essential Ventilation System . .2-87

2.3.3.11 Treated Water System .. 2-91

2.3.3.12 Circulating Water System . .2-94

2.3.3.13 Fuel Handling System .. 2-96

2.3.3.14 Plant Sampling System .................. 2-97

2.3.3.15 Plant Air System .2-98

2.3.3.16 Containment Hydrogen Detectors and Recombiner

System ... , 2-102

2.3.4 Steam and Power Conversion System .. 2-103

2.3.4.1 Main and Auxiliary Steam System .. 2-103

2.3.4.2 Feedwater and Condensate System .. t........... I ... 2-105

2.3.4.3 Auxiliary Feedwater System .2-110

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

Supports ................... . ............................... 2-113

2.4.1 Containment Units 1 and 2 Building Structure .. 2-115

2.4.1.1 Summary of Technical Information in the Application .... 2-115

2.4.1.2 Staff Evaluation .. 2-117

2.4.1.3 Conclusion .. 2-118

2.4.2 Control Building Structure .. 2-118

2.4.2.1 Summary of Technical Information in the Application .... 2-118

2.4.2.2 Staff Evaluation .. 2-120

2.4.2.3 Conclusion .. 2-121

2.4.3 Circulating Water Pumphouse Structure ...................... 2-121

2.4.3.1 Summary of Technical Information in the Application .... 2-121

2.4.3.2 Staff Evaluation .2-122

2.4.3.3 Conclusion .2-124

2.4.4 Diesel Generator Building Structure . .2-125

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

2.4.4.2 Staff Evaluation .2-126

2.4.4.3 Conclusion .2-126

2.4.5 Facade Units 1 and 2 Structure .2-126

2.4.5.1 Summary of Technical Information in the Application .... 2-126

2.4.5.2 Staff Evaluation .2-127

2.4.5.3 Conclusion .2-127

2.4.6 Primary Auxiliary Building Structure .2-128

2.4.6.1 Summary of Technical Information in the Application .... 2-128

2.4.6.2 Staff Evaluation .2-129

2.4.6.3 Conclusion .2-129

2.4.7 Turbine Building Units 1 and 2 Structure .2-130

vi
2.4.7.1 Summary of Technical Information in the Application .... 2-130

2.4.7.2 Staff Evaluation .......... I ....................... 2-131

2.4.7.3 Conclusion ............................ 2-131

2.4.8 Yard Structures .. 2-131

2.4.8.1 Summary of Technical Information in the Application .... 2-131

2.4.8.2 Staff Evaluation .2-132

2.4.8.3 Conclusion .2-134

2.4.9 Cranes, Hoists, and Lifting Devices .2-135

2.4.9.1 Summary of Technical Information in the Application .... 2-135

2.4.9.2 Staff Evaluation .2-135

2.4.9.3 Conclusion ....... ...... 2-137

2.4.10 Component Supports Commodity Group . . .2-137

2.4.10.1 Summary of Technical Information in the Application ... 2-137

2.4.10.2 Staff Evaluation ..................... 2-139

2.4.10.3 Conclusion. ..................... 2-139

2.4.11 Fire Barrier Commodity Group ..................... 2-139

2.4.11.1 Summary of Technical Information in the Application ... 2-139

2.4.11.2 Staff Evaluation ... 2-140

2.4.11.3 Conclusion ...................... 2-141

2.4.12 13.8 kV Switchgear Building Structure .. 2-142

2.4.12.1 Summary of Technical Information in the Application ... 2-142

2.4.12.2 Staff Evaluation ................ 2-142

2.4.12.3 Conclusion ............. -. - 2-143

2.4.13 Fuel Oil Pumphouse Structure .......................... 2-144

2.4.13.1 Summary of Technical Information in the Application ... 2-144

2.4.13.2 Staff Evaluation .2-144

2.4.13.3 Conclusion ..............-. 2-145

2.4.14 Gas Turbine Building Structure .... ... 2-145

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

2.4.14.2 Staff Evaluation ....... .............. 2-146

2.4.14.3 Conclusion ..................... 2-149

2.5 Scoping and Screening Results: Electrical and Instrumentation and Controls 2-149

2.5.1 Commodity Group Descriptions .. 2-151

2.5.1.1 Insulated Cables and Connections ........ .......... 2-152

2.5.1.2 Electrical Penetration Assemblies ....... ............ 2-153

2.5.1.3 Electrical Phase Bus ....... 2-154

2.5.1.4 Switchyard Bus. . .. I ... 2-155

2.5.1.5 Transmission Conductors . .2-156

2.5.1.6 High-Voltage Insulators .. 2-157

2.5.1.7 Uninsulated Ground Conductors . .2-158

2.5.1.8 Panels and Junction Boxes . .2-159

2.6 Conclusion for Scoping and Screening .............................. 2-160

3 Aging Management Review Results ............................ 3-1

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

3.0.1 Format of the LRA . . .3-2

3.0.1.1 Overview of Table 1 .3-3

3.0.1.2 Overview of Table 2.3-3

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

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

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

3.0.2.3 FSAR Supplement ............. .................... 3-6

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

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

3.0.3.1 AMPs That Are Consistent with the GALL Report .... ..... 3-9

3.0.3.2 AMPs That Are Consistent with the GALL Report with

Exceptions or Enhancements ....... ................ 3-10

3.0.3.3 AMPs That Are Not Consistent with or Not Addressed

in the GALL Report .3-117

3.0.4 Quality Assurance Program Attributes Integral to Aging

Management Programs .3-135

3.0.4.1 Summary of Technical Information .3-136

3.0.4.2 Staff Evaluation .3-137

3.0.4.3 Conclusion .3-137

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

System...................................................... 3-137

3.1.1 Summary of Technical Information in the Application ..... ....... 3-137

3.1.2 Staff Evaluation ............. ........................... 3-138

3.1.2.1 AMR Results That Are Consistent with the GALL Report,

for Which Further Evaluation is Not Recommended ..... 3-144

3.1.2.2 AMR Results That Are Consistent with the GALL Report,

for Which Further Evaluation is Recommended .... .... 3-147

3.1.2.3 AMR Results That Are Not Consistent with or Not

Addressed in the GALL Report ...... ............... 3-165

3.1.3 Conclusion ............................................ 3-176

3.2 Aging Management of Engineered Safety Features ..... ............... 3-176

3.2.1 Summary of Technical Information in the Application ..... ....... 3-176

3.2.2 Staff Evaluation ........... ............................. 3-176

3.2.2.1 AMR Results That Are Consistent with the GALL Report,

for Which Further Evaluation Is Not Recommended ..... 3-180

3.2.2.2 AMR Results That Are Consistent with the GALL Report,

for Which Further Evaluation Is Recommended .... .... 3-182

3.2.2.3 AMR Results That Are Not Consistent with or Not

Addressed in the GALL Report .. 3-187

3.2.3 Conclusion .. 3-194

3.3 Aging Management of Auxiliary Systems ...................... 3-195

3.3.1 Summary of Technical Information in the Application .... ........ 3-195

3.3.2 Staff Evaluation ........... ............................. 3-195

3.3.2.1 AMR Results That Are Consistent with the GALL Report,

for Which Further Evaluation is Not Recommended ..... 3-200

3.3.2.2 AMR Results That Are Consistent with the GALL Report,

for Which Further Evaluation is Recommended .... .... 3-202

3.3.2.3 AMR Results That Are Not Consistent with or Not

Addressed in the GALL Report ...... ............... 3-213

3.3.3 Conclusion ............. ............................... 3-244

3.4 Aging Management of Steam and Power Conversion Systems .... ....... 3-244

3.4.1 Summary of Technical Information in the Application .... ........ 3-244

3.4.2 Staff Evaluation ................. e ........................ 3-244

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

for Which Further Evaluation is Not Recommended ..... 3-248

3.4.2.2 AMR Results That Are Consistent with the GALL Report,

for Which Further Evaluation Is Recommended .... .... 3-250

3.4.2.3 AMR Results That Are Not Consistent with or Not

Addressed in the GALL Report ...... .............. 3-254

3.4.3 Conclusion ............. ..................... .. 3-260

3.5 Aging Management of Containments, Structures, and Components Supports 3-260

3.5.1 Summary of Technical Information in the Application .... ........ 3-261

3.5.2 Staff Evaluation .................. . 3-261

3.5.2.1 AMR Results That Are Consistent with the GALL Report,

for Which Further Evaluation is Not Recommended .. 3-266

3.5.2.2 AMR Results That Are Consistent with GALL Report,

for Which Further Evaluation Is Recommended .. 3-269

3.5.2.3 AMR Results That Are Not Consistent with or Not

Addressed in the GALL Report .. 3-296

3.5.3 Conclusion .. 3-307

3.6 Aging Management of Electrical Components . . . 3-307

3.6.1 Summary of Technical Information in the Application . . 3-307

3.6.2 Staff Evaluation .. 3-308

3.6.2.1 AMR Results That Are Consistent with the GALL Report,

for Which Further Evaluation is Not Recommended .. 3-310

3.6.2.2 AMR Results That Are Consistent with the GALL Report,

for Which Further Evaluation is Recommended .. 3-312

3.6.2.3 AMR Results That Are Not Consistent with or Not

Addressed in the GALL Report .. 3-313

3.6.3 Conclusion .......... 3-320

3.7 Conclusion for Aging Management Review Results .... 3-320

4 Time-Limited Aging Analyses . . . . 4-1

4.1 Identification of Time-Limited Aging Analyses 4-1

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

4.1.2 Staff Evaluation .4-2

4.1.3 Conclusion .4-3

4.2 Reactor Vessel Irradiation Embrittlement .4-3

4.2.1 Reactor Vessel Pressurized Thermal Shock .4-4

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

4.2.1.2 Staff Evaluation .4-5

4.2.1.3 FSAR Supplement ............................... 4-8

4.2.1.4 Conclusion . ............ ...... 4-8

4.2.2 Reactor Vessel Upper Shelf Energy ............. tl...... 4-8

4.2.2.1 Summary of Technical Information in the Application .4-9

4.2.2.2 Staff Evaluation ................. ...... 4-9

4.2.2.3 FSAR Supplement . . . - .. ... 4-10

4.2.2.4 Conclusion . .................. !- . 4-10

4.2.3 Reactor Vessel Pressure/Temperature Limits . . .................... 4-10

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

4.2.3.2 Staff Evaluation .... . ....... 4-11

4.2.3.3 FSAR Supplement .. 4-11

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

4.3 Metal Fatigue ....................... 4-11

4.3.1 Reactor Vessel Structural Integrity .......... .................. 4-12

4.3.1.1 Summary of Technical Information in the Application ..... 4-12

4.3.1.2 Staff Evaluation ................ 4-13

4.3.1.3 FSAR Supplement .. ................ 4-13

4.3.1.4 Conclusion ....................... 4-14

4.3.2 Reactor Vessel Internals Structural Integrity . . ......... 4-14

4.3.2.1 Summary of Technical Information in the Application ..... 4-14

4.3.2.2 Staff Evaluation .................. 4-14

4.3.2.3 FSAR Supplement .................. 4-15

4.3.2.4 Conclusion .. ................ 4-15

4.3.3 Control Rod Drive Mechanism Structural Integrity ..... .......... 4-16

4.3.3.1 Summary of Technical Information in the Application ..... 4-16

4.3.3.2 Staff Evaluation ............... ................... 4-16

4.3.3.3 FSAR Supplement .................... 4-17

4.3.3.4 Conclusion ........................ 4-17

4.3.4 Steam Generator Structural Integrity ............ ...... ....... 4-18

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

4.3.4.2 Staff Evaluation ....... ...... ................... 4-18

4.3.4.3 FSAR Supplement .................... 4-19

4.3.4.4 Conclusion ....................... 4-19

4.3.5 Pressurizer Structural Integrity ......................... 4-20

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

4.3.5.2 Staff Evaluation .. ............. 4-21

4.3.5.3 FSAR Supplement . ..................... 4-23

4.3.5.4 Conclusion ... I..................... 4-24

4.3.6 Reactor Coolant Pump Structural Integrity .... I...... 4-24

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

4.3.6.2 Staff Evaluation .............................. 4-25

4.3.6.3 FSAR Supplement ............ ..................... 4-26

4.3.6.4 Conclusion ....................................... 4-26

4.3.7 Pressurizer Surge Line Structural Integrity . .. . 4-26

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

4.3.7.2 Staff Evaluation ............. ..................... 4-27

4.3.7.3 FSAR Supplement ................................ 4-28

4.3.7.4 Conclusion ..................... 4-28

4.3.8 Pressurizer Spray Header Piping Structural Integrity . .......... 4-28

4.3.8.1 Summary of Technical Information in the Application ..... 4-28

4.3.8.2 Staff Evaluation ..... - 4-29

4.3.8.3 FSAR Supplement .................. 4-30

4.3.8.4 Conclusion .................. 4-30

4.3.9 USAS B31.1 Piping Structural Integrity . ............... 4-31

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

4.3.9.2 Staff Evaluation ........... ....................... 4-31

4.3.9.3 FSAR Supplement ................................ 4-32

4.3.9.4 Conclusion. ................... 4-32

4.3.10 Environmental Effects on Fatigue ................................ 4-32

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

x
4.3.10.2 Staff Evaluation ................... - . 4-35

4.3.10.3 FSAR Supplement. 4-37

4.3.10.4 Conclusion ............ 4........................ 4-38

4.3.11 Containment Liner Plate Fatigue Analysis ............... . 4-38

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

4.3.11.2 Staff Evaluation ............... ................... 4-39

4.3.11.3 FSAR Supplement ................................ 4-40

4.3.11.4 Conclusion ................... 4-40

4.3.12 Spent Fuel Pool Liner Fatigue Analysis . . 4-40

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

4.3.12.2 Staff Evaluation .4-40

4.3.12.3 FSAR Supplement ........................ 4-41

4.3.12.4 Conclusion .4-41

4.3.13 Crane Load Cycle Limit .. 4-41

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

4.3.13.2 Staff Evaluation . . . .4-42

4.3.13.3 FSAR Supplement .... 4-43

4.3.13.4 Conclusion . . ............................ 4-43

4.4 Fracture Mechanics Analysis . . .4-44

4.4.1 Reactor Vessel Underclad Cracking . . 4-44

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

4.4.1.2 Staff Evaluation .................. 4-44

4.4.1.3 FSAR Supplement .... 4-44

4.4.1.4 Conclusion . . . .4-45

4.4.2 Reactor Coolant Pump Flywheel Analysis . . .4-45

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

4.4.2.2 Staff Evaluation ....... ........... . 4-46

4.4.2.3 FSAR Supplement . . . ........... 4-47

4.4.2.4 Conclusion ... 4-47

4.4.3 Reactor Coolant Pump Casing Analysis (ASME Code Case N-481

Analysis). ............................................. 4-48

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

4.4.3.2 Staff Evaluation .. . . 4-48

4.4.3.3 FSAR Supplement .... 4-50

4.4.3.4 Conclusion .. . . 4-50

4.4.4 Reactor Coolant System Main Loop Piping Leak-Before-Break

Analysis .. 4-50

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

4.4.4.2 Staff Evaluation . 4-51

4.4.4.3 FSAR Supplement ................... 4-52

4.4.4.4 Conclusion .4-52

4.4.5 Pressurizer Surge Line Piping Leak-Before-Break Analysis ... 4-52

4.4.5.1 Summary of Technical Information in the Application . 4-52

4.4.5.2 Staff Evaluation .................. 4-53

4.4.5.3 FSAR Supplement .4-54

4.4.5.4 Conclusion .............. .................... 4-54

4.4.6 Class 1 Accumulator Injection Line Piping Leak-Before-Break

Analysis ..... - 4-54

4.4.6.1 Summary of Technical Information in the Application . 4-54

xi
4.4.6.2 Staff Evaluation ........ 4-55

4.4.6.3 FSAR Supplement . .4-56

4.4.6.4 Conclusion .. 4-56

4.4.7 Class 1 RHR Line Piping Leak-Before-Break Analysis . 4-56

4.4.7.1 Summary of Technical Information in the Application . 4-56

4.4.7.2 Staff Evaluation .. 4-57

4.4.7.3 FSAR Supplement . ... .4-58

4.4.7.4 Conclusion . .4-58

4.4.8 Component / Piping Subsurface Indication Analysis . ... 4-58

4.4.8.1 Summary of Technical Information in the Application . 4-58

4.4.8.2 Staff Evaluation .. 4-58

4.4.8.3 FSAR Supplement.. . .4-58

4.4.8.4 Conclusion .. 4-59

4.4.9 Reactor Vessel Head Penetration Analysis . ... 4-59

4.4.9.1- Summary of Technical Information in the Application . 4-59

4.4.9.2 Staff Evaluation .. 4-59

4.4.9.3 FSAR Supplement .. 4-60

4.4.9.4 Conclusion .. 4-60

4.5 Loss of Preload .. 4-61

4.5.1 Containment Tendon Loss of Prestress Analysis . . 4-61

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

4.5.1.2 Staff Evaluation .. 4-61

4.5.1.3 FSAR Supplement . . 4-64

4.5.1.4 Conclusion . 4-64

4.6 Neutron Absorber ........... .. ...... 4-65

4.6.1 Spent Fuel Pool Storage Rack Boraflex .. 4-65

4.6.1.1 Summary of Technical Information in the Application . 4-65

4.6.1.2 Staff Evaluation . 4-65

4.6.1.3 FSAR Supplement . 4-68

4.6.1.4 Conclusion ............ - 4-68

4.7 Wear ........................................................ 4-68

4.7.1 Bottom Mounted Instrumentation Thimble Tube Wear . 4-68

4.7.1.1 Summary of Technical Information in the Application . 4-68

4.7.1.2 Staff Evaluation . 4-69

4.7.1.3 FSAR Supplement . 4-69

4.7.1.4 Conclusion . 4-69

4.7.2 Containment Accident Recirculation Heat Exchanger Tube Wear . . . 4-69

4.7.2.1 Summary of Technical Information in the Application . 4-69

4.7.2.2 Staff Evaluation . 4-69

4.7.2.3 FSAR Supplement . .. 4-69

4.7.2.4 Conclusion . 4-70

4.8 Environmental Qualification .. . . 4-70

4.8.1 Environmental Qualification of Electrical Equipment . . 4-70

4.8.1.1 Summary of Technical Information in the Application . 4-71

4.8.1.2 Staff Evaluation . 4-73

4.8.1.3 FSAR Supplement . 4-73

4.8.1.4 Conclusion . 4-73

4.9 Conclusion for Time-Limited Aging Analyses .......................... 4-74

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

6 Conclusion ................................... 6-1

Appendices

Appendix A: Commitments for License Renewal ................................. A-1

Appendix B: Chronology ................................ B-1

Appendix C: Requests for Additional Information ................................. CAppendix D: Principal Contributors ........... ..................... D-A

Appendix E: References ................................ E-1

Figures

Figure 4.5-1 Unit 2 Hoop Tendons, Projected Pre-Stressing Force Trend ..... ........ 4-63

Tables

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

Table 3.0.3-1 PBNP's Aging Management Programs .............................. 3-7

Table 3.0.3.2-1 Relationship of Parameters Monitored or Inspected and Aging Effect .... 3-76

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

Components in the GALL Report ..................... ......... 3-139

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

GALL Report................................. I ..................... 3-177

Table 3.3-1 Staff Evaluation for Auxiliary System Components in the GALL Report .... 3-196

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

Report........................................................... 3-245

Table 3.5-1 Staff Evaluation for Containments, Structures, and Component Supports

System Components in the GALL Report ... .......... ......... 3-262

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

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

Table 3.6-2 Electrical Component Types, Materials, and Environments Without

AMPs .............................. 3-313

Table 4.5-1 Projected Prestressing Forces ................ ............. 4-64

xiii
ABBREVIATIONS

MC alternate alternating current

AC alternating current

ACI American Concrete Institute

ACSR aluminum conductor steel reinforced

AEC Atomic Energy Commission

AFW auxiliary feedwater

AFWP auxiliary feedwater pump

AISC American Institute of Steel Construction

AL action level

AMP aging management program

AMR aging management review

AMSAC ATWS migrating system actuation circuit

ANSI American National Standards Institute

APPR Appendix R Drawing

AQ augmented quality

AR action request

ASME American Society of Mechanical Engineers

ASA American Standards Association

ASTM American Society for Testing of Materials

ATWS anticipated transient without scram

ATWT anticipated transient without trip

AUX auxiliary

B&W Babcock and Wilcox

BDE blowdown evaporator

BMI bottom-mounted instrument

BOP balance of plant

BS boron recycle

BTP branch technical position

BWR boiling water reactor

BWOG Babcock & Wilcox Owners Group

CARDS cable and raceway data system

CASS cast austenitic stainless steel

CB control building

CBD class boundary diagram

CC component cooling

CCCW closed-cycle cooling water

CCW component cooling water

CD-ROM compact disk-read only memory

CE condition evaluation

CFR Code of Federal Regulations

CHAMPS computerized history and maintenance planning system

CIV containment isolation valve

CLB current licensing basis

CLRT containment leak rate test

xiv
CMM Crane Manufacturers Association of America

CMS Consumers Energy

CPCI containment pressure condensate isolation

CR condition report, control room, count rate, cryogenic

CRD control rod drive

CRDM control rod drive mechanism

CS carbon steel, containment spray, or condensate system

CSR cable spreading room

CST condensate storage tank

CSUP component supports commodity group

CUF cumulative usage factors

CV containment vacuum or containment vessel

CVCS chemical and volume control system

CW circulating water

CWPH circulating water pump house

DAM data acquisition modules

DBA design-basis accident

DBD design-basis document

DBE design-basis event

DC direct current

DG diesel generator or design guide

DGB diesel generator building

DGR diesel generator room

Dl demineralized water

DNB departure from nucleate boiling

DNBR departure from nucleate boiling ratio

EBA emergency breathing air

ECCS emergency core cooling system

ECT eddy current testing

EDG emergency diesel generator

EFPY effective full power years

EIC Energy Information Center

EIN equipment identification number

EL elevation

EMPA Swiss Federal Testing Station

EOCI Electric Overhead Crane Institute

EOEL end of extended life

EOL end of life

EPA electrical penetration assemblies

EPDM ethylene propylene diene monomer

EPR ethylene propylene rubber

EPRI Electric Power Research Institute

EQ environmental qualification

EQML environmental qualification master list

EQSS environmental qualification summary sheets

ESF engineered safety feature

ESFAS engineered safety features actuation system

xv
F fahrenheit

FAC flow-accelerated corrosion

FE flow element

FERC Federal Energy Regulatory Commission

FHAR fire hazards analysis report

FPER fire protection evaluation report

FM frequency modulation

FOA forced oil-air

FSAR final safety analysis report

FSER final safety evaluation report

F/L full length

GALL Generic Aging Lessons Learned

GDC general design criterion

GEIS generic environmental impact statement

GL generic letter

GLD green line drawing

GSI generic safety issues

GT gas turbine, guide tube

GTG gas turbine generator

GTR generic technical report

HA hydrazine addition

HAZ heat-affected zone

HELB high-energy line break

HEPA high efficiency particulate filter

HMWPE high molecular weight polyethylene

Hr hour

HVAC heating, ventilation and air conditioning

HVSAT high voltage station auxiliary transformer

HX heat exchanger

I&C instrumentation & controls

I/P current to pressure converter

IA instrument air

IASCC irradiation assisted stress corrosion cracking

ICMS Insulation Consultants Management Services, Inc.

ID identification

IE inspection and enforcement

IEB inspection and enforcement bulletin

IEEE Institute of Electrical and Electronics Engineers, Inc.

IF intended function

IGA intergranular attack

IGSCC intergranular stress corrosion cracking

ILRT integrated leak rate test

IN information notice

INEL Idaho National Engineering Laboratories

INPO Institute of Nuclear Power Operations

IPA integrated plant assessment

xvi
IR insulation resistance or inspection report

ISG interim staff guidance

ISI inservice inspection

ITG issues task group

IWB requirements for Class 1 components of light-water cooled power plants

IWC requirements for Class 2 components of light-water cooled power plants

IWD requirements for Class 3 components of light-water cooled power plants

IWE requirements for Class MC and metallic liners of Class CC components if

light-water cooler power plants

IWF requirements for Class 1, 2, 3, and MC component supports of light-water

cooled power plants

IWL requirements for Class CC concrete components of light-water cooled

power plants

Kic reference stress intensity factor as a function of the metal temperature

(T) and the metal references nil-ductility temperature (RTNDT)

KIP 1000 Ib; or 1 kilo-pound

KIR ASME fracture toughness curve

Ksi one KIP per square inch, 1000 psi

K VAC kilovolts alternating current

KWe kilowatt electric

Lb pound

LBB leak-before-break

LEFM leading edge flow meter

LER licensee event report

LLC limited liability company

LO lube oil

LOCA loss-of-coolant accident

LR license renewal

LRA license renewal application

LRDB license renewal database

LRPMS license renewal project management system

LRPP license renewal project procedures LTOP low-temperature overpressure protection

LVSAT low voltage station auxiliary transformer

LWR light water reactor

Mat'l material

MIC microbiologically induced corrosion

MIRVP master integrated reactor vessel surveillance program

Misc. miscellaneous

MOP modified operating procedures

MRP materials reliability program

MRR metering, relaying and regulation

MRV minimum required prestressing force or value

MRule Maintenance Rule

MS main steam

MSIV main steam isolation valve

xvii
MSLB

MT

MW

MWD

MWe

MWt

main steam line break

magnetic particle test

megawatts

megawatt-day

megawatt electric

megawatt thermal

N

NA or N/A

NaOH

NCR

NDE

NE

NEI

NEPA

NES

NFPA

NMC

NNE

Non-VSR

NP

NPS

NQAP

NRC

NSAC

NSP

NSR

NSSS

NUMARC

NUREG

OCCW

ODSCC

OEM

01

north

not applicable

sodium hydroxide

non-conformance report

non-destructive examination

northeast

Nuclear Energy Institute

National Environmental Policy Act

Nuclear Engineering Services

National Fire Protection Association

Nuclear Management Company

north-north east

non-vital switchgear room

nuclear procedure

nominal pipe size

Nuclear Quality Assurance Program

Nuclear Regulatory Commission

Nuclear Safety Analysis Center

Northem States Power

nonsafety-related

nuclear steam supply system

Nuclear Utility Management and Resource Council

nuclear regulation document

open-cycle cooling water program

outside diameter stress corrosion cracking

original equipment manufacturer

open item

P&ID

P-T

PAB

PACV

PBNP

PDI

PLL

PM

PORV

PPB

PPCS

PRT

PS

piping and instrument diagram

pressure temperature

primary auxiliary building

post-accident containment ventilation system

Point Beach Nuclear Plant

performance demonstration initiative

predicted lower limit

preventive maintenance

power-operated relief valve

parts per billion

plant process computers system

pressurizer relief tank

pipe support

xviii
PSI pounds per square inch

PSIG pounds per square inch gauge

PSS plant sampling system

PSPM periodic surveillance and preventive maintenance

PT penetrant testing

PTLR pressure and temperature limits report

PTS pressurized thermal shock

PVC polyvinyl chloride

PW potable water

PWR pressurized water reactor

PWSCC primary water stress corrosion cracking

PZR pressurizer

P/L part length

0-List quality list

QA quality assurance

RAI request for additional information

RC reactor coolant

RCCA rod control cluster assembly

RCP reactor coolant pump

RCPB reactor coolant pressure boundary

RCS reactor coolant system

RG regulatory guide

RH residual heat

RHR residual heat removal

RH/SI residual heat/safety injection

RI-ISI risk informed inservice inspection program

RM radiation monitoring

RMW reactor makeup water

RPS reactor protection system

RPV reactor pressure vessel

RSG replacement steam generator

RTD resistance temperature detectors

RTNDT reference temperature for nil ductility transition

RTpm reference temperature for pressurized thermal shock

RV reactor vessel or relief valve

RVH reactor vessel head

RVI reactor vessel internals

RWST refueling water storage tank

S&PC steam and power conversion

SA service air

SBCC site boundary control center

SBO station blackout

SC structure and component

SCBA self-contained breathing apparatus

SCC stress corrosion cracking

SE south east

xix
SER safety evaluation report

SF spent fuel

SFP spent fuel pool

SG steam generator

SGRP steam generator replacement project

SGBD steam generator blowdown

SGTR steam generator tube rupture

Si safety injection

SOC statement of considerations

SOER significant operating event report

SOV solenoid operated valve

SPING system-level particulate, iodine, and Nobel gas monitor

SR safety-related

SRP standard review plan

SRP-LR standard review plan for license renewal

SS stainless steel or sampling system

SSAR safe shutdown analysis report

SSC system, structure, or component

SSEL safe shutdown equipment list

STP sewage treatment plant

SW service water

t thickness

T temperature

TAC Training Advisory Committee

TAVG RCS average temperature

TB turbine building

TID total integrated dose

TLAA time-limited aging analysis

TR technical report

TRM training requirements manual

TS technical specifications

TSC technical support center

Ul Unit I

U2 Unit 2

U.S. United States

USC upper support column

USAS United States of America Standards

USE upper shelf energy

USI unresolved safety issue

UT ultrasonic testing

UTS ultimate tensile strength

UV ultraviolet

VAC volts-altemating current

VCT volume control tank

VDC volts-direct current

VHP vessel head penetration

xx
VNBI PAB battery and inverter room ventilation system

VNCC containment cooling system

VNCF containment clean-up system

VNCOMP computer room ventilation system

VNCR control room ventilation system

VNCRD control rod drive cooling system

VNCSR cable spreading room ventilation system

VNDG diesel generator building ventilation system

VNDRM drumming area ventilation subsystem

VNPAB primary auxiliary ventilation subsystem

VNPH circulating water pumphouse ventilation subsystem

VNPSE containment purge supply and exhaust subsystem

VNRAD radwaste ventilation subsystem

VNRC reactor cavity cooling subsystem

VNRF refueling cavity ventilation subsystem

Vol. volume

VPNPD Vice President Nuclear Power Department

VSR vital switchgear room

VT visual examination

WCAP Westinghouse Commercial Atomic Power

WD waste disposal

WE Wisconsin Electric

WEC Wisconsin Energy Corporation

WEPCo Wisconsin Electric Power Company

WL waste liquid

WPS Wisconsin Public Service

WO work order

WOG Westinghouse Owners Group

WT water treatment

XLPE cross-linked polyethylene

YARD yard structures

Zn zinc

xxi
SECTION 1

INTRODUCTION AND GENERAL DISCUSSION

1.1 Introduction

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

Point Beach Nuclear Plant (PBNP) Units 1 and 2, as filed by Nuclear Management Company,

LLC (NMC or the applicant). By letter dated February 25, 2004, NMC submitted its application

to the U.S. Nuclear Regulatory Commission (NRC or the Commission) for renewal of the PBNP

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 application 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 PBNP license renewal review was Mr. Michael Morgan.

Currently, Mr. Gregory Suber and Ms. Veronica Rodriguez are acting project managers for the

PBNP license renewal review. Mr. Suber can be contacted by telephone at 301-415-1124 or

electronic mail at axs@nrc.aov. Ms. Rodriguez can be contacted by telephone at

301-415-3703 or electronic mail at vmrl @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: Mr. Suber and/or Ms. Rodriguez, Mail Stop 011-F1lIn its February 25, 2004, submittal letter, the applicant requested renewal of the operating

licenses issued under Section 104(b) of the Atomic Energy Act of 1954, as amended, for PBNP

Units 1 and 2 (Facility Operating License Numbers DPR-24 and DPR-27, respectively), for a

period of 20 years beyond the current license expiration dates of midnight, October 5,2010, for

Unit 1 and March 8, 2013, for Unit 2. The PBNP units are located about 30 miles SE of Green'

Bay and about 90 miles NNE of Milwaukee in east central Wisconsin (Manitowoc County) on

the west shore of Lake Michigan. The NRC issued the construction permits for PBNP Units 1

and 2 on July 19, 1967, and July 25, 1968, respectively. The NRC issued the operating

licenses on October 5, 1970, for Unit 1 and March 8, 1973, for Unit 2. PBNP consists of two

Westinghouse pressurized light-water moderated and cooled system units, both designed to

generate 1518.5 megawatt thermal (MWt), or approximately 523.8 megawatt electric (MWe).

Each unit has undergone a low pressure turbine retrofit modification which increases the unit

design output to 537,960 KWe. In 2003, a measurement uncertainty recapture power uprate

was performed, increasing each unit's rated thermal power level to 1540 MWt. 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 review. The NRC regulations found in 10 CFR Parts 54 and 51,

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

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

the staff's requests for additional Information (RAls). The applicant supplemented its responses

1-1
to the LRA and RAls in audits, meetings, and docketed correspondence. Unless otherwise

noted, the staff reviewed and considered information submitted through August 23, 2005. 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 information. The public may

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, MD, 20852-2738 (301-415-4737/800-397-4209), and at the Lester

Public Library, 1001 Adams Street, Two Rivers, Wisconsin, 54241. In addition, the public may

find the PBNP 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 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-1800,

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

(SRP-LR), dated July 2001.

SER Sections 2 through 4 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 provides the conclusion

of this report.

SER Appendix A 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 RAIs and the applicant's responses. Appendix D is

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

during the course of the review.

In accordance with i0 CFR Part 51, the staff prepared a plant-specific supplement to the

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

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

NRC staff issued NUREG-1 437, Supplement 23, "Generic Environmental Impact Statement for

License Renewal of Nuclear Plants: Regarding Point Beach Nuclear Plant, Units 1 and 2 Final

Report," on August 12, 2005.

1.2 License Renewal Backaround

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

1-2
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

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

and to gain experience necessary to develop implementation guidance. To establish a scope of

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

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

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

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

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

result, the NRC amended the license renewal rule in 1995. The amended 10 CFR Part 54

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 an

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

license renewal and to fulfill the NRC's responsibilities under the National Environmental Policy

Act of 1969 (NEPA).

1.2.1 Safety Review

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

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

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

exception of the detrimental effects of aging on the functionality of certain 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 these two principles, 10 CFR 54.4 defines the scope of license renewal as

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

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

protection (FP), environmental qualification (EQ), pressurized thermal shock (PTS), anticipated

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

1-3
Pursuant to 10 CFR 54.21 (a), an applicant for a renewed license must review all SSCs that are

within the 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

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 are expected to be identified and corrected through routine surveillance, performance

monitoring, and maintenance activities. The surveillance and maintenance activities 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 FSAR. This

FSAR supplement must contain a summary description of the applicant's programs and

activities for managing the effects of aging and an evaluation of time-limited aging analyses

(TLAAs) for the period of extended operation.

License renewal also requires the identification and updating of the TLAAs. During the design

phase for a plant, certain assumptions are made about the length of time the plant will operate.

These assumptions are incorporated into design calculations for several of the plant's SSCs. In

accordance with 10 CFR 54.21 (c)(1), the applicant must either show that these calculafions 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.

In the LRA, PBNP fully utilizes the process defined in NUREG-1 801, "Generic Aging Lessons

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

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

that are subject to an AMR. If an applicant commits to implementing these staff-approved

AMPs, the time, effort, and resources used to review an applicant's LRA can 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.

1-4
1.2.2 Environmental Review

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" (NUREG-1437) to document its

evaluation of the possible environmental impacts associated with renewing licenses of nuclear

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

findings that are applicable to all nuclear power plants (i.e., Category 1 issues). 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 requirements of 10 CFR Part 51, the NRC performed a

plant-specific 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 June 15, 2004. in Mishicot (Fox Hills), Wisconsin, to

identify environmental issues specific to the plant. The NRC's draft plant-specific

Supplement 23 to the GEIS regarding PBNP Units 1 and 2 was issued on January 13, 2005.

The NRC held another public meeting on March 3, 2005, in Mishicot (Fox Hills), Wisconsin, to

discuss the draft plant-specific Supplement 23 to the GEIS regarding PBNP Units I and 2. The

NRC's final plant-specific Supplement 23 to the GEIS regarding PBNP Units 1 and 2, which

was issued on August 12, 2005, documents the results of the environmental review and

includes a recommendation with respect to the license renewal action.

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 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 certain

general irnformation. The applicant provided this general information in LRA Section 1 for

PBNP, Units 1 and 2, which it submitted to the NRC by letter dated February 25, 2004. The

staff reviewed LRA Section 1 and found that the applicant submitted the information required by

10 CFR 54.19(a).

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 requirements at 10 CFR 54.19(b) state that license renewal applications must

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

1-5
current indemnity agreement No. B-41 for PBNP Units I and 2 states, in Article VII, that

the agreement shall terminate at the time of expiration of that license specified in Item 3

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

to the indemnity agreement, as revised by Amendment No. 14, lists DPR 24 and

DPR 27 as the applicable license numbers. Should the license numbers be changed

upon issuance of the renewed licenses, NMC requests that conforming changes be

made to Item 3 of the attachment, and any other sections of the indemnity agreement as

appropriate.

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

licenses, i approved. 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 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) an FSAR supplement. LRA Sections 3 and 4 and Appendix B address the

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

FSAR supplement, as required by 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 letters dated February 23 and June 29, 2005,

which summarized the changes to the CLB that have occurred at PBNP Units 1 and 2 during

the staff's review of the LRA. This adequately addresses the requirement specified in

10 CFR 54.21 (b).

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

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

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

any TS changes necessary to support issuance of the renewed operating licenses for PBNP

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. SER Sections 2,

3, and 4 document the staff's evaluation of the technical information contained in the LRA.

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. SER Section 5 incorporates the ACRS interim report;

its final report will be included once it is issued. SER Section 6 documents the findings required

by 10 CFR 54.29.

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

environmental information required by 10 CFR 54.23 and specifies the considerations related to

renewing the licenses for PBNP Units 1 and 2. The staff prepared this supplement separately

from this SER.

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1.4 Interim Staff Guidance

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

interested stakeholders gain experience and develop lessons learned with each renewed

license. The lessons learned address the NRC's performance goals of maintaining safety,

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

confidence. Interim staff guidance (ISG) is documented for use by the NRC staff, industry, and

other interested stakeholders until it is incorporated into license renewal guidance documents

such as the SRP-LR and GALL Report.

The following table provides the current set of ISGs issued by the staff, as well as the SER

sections in which the issues are addressed by the staff.

Table 1.4-1 Interim Staff Guidance

ISG Isu upos JSER Secltion

(prvedl "ISO No.)l______________

GALL Report presents one acceptable way This ISG clarified that the GALL Report N/A

to manage aging effects contains one acceptable way, and not

(ISG-1) the only way to manage aging for license

renewal.

Station Blackout Scoping (SBO) The license renewal rule

(ISG-2) 10 CFR 54.4(a)(3) includes 2.1.2.1.1

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

The SBO rule requires that a plant must

withstand and recover from an SBO

event. The recovery time for offsite

power is much faster than that of EDGs.

The offsite power system should be

included within the scope of license

renewal.

Concrete Aging Management Program Lessons learned from the GALL 3.5.2.2.1

(ISG-3) demonstration project indicated that

GALL is not clear whether concrete

requires an AMP.

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I1SG Issue Purpose ectioni -(Approved ISG ~No)I______________

Fire Protection (FP) System Piping This ISG clarifies the staff position for 3.0.3.2.10

(ISG-4) wall thinning of FP piping system in 3.3.2.3.7

GALL AMPs XL.M26 and XL.M27.

The staff's new position is that there is

no need to disassemble FP piping;

disassembly can introduce oxygen into

the FP piping, which can accelerate

corrosion. Instead, a non-intrusive

method, such as volumetric inspection,

can be used.

Testing of sprinkler heads should be

performed at year 50 of sprinkler system

service life, and every 10 years

thereafter.

This ISG eliminates the Halordcarbon

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.

Identification and Treatment of Electrical This ISG includes fuse holders AMR and 2.1.3.2.3

Fuse Holders AMP (ie., same as terminal blocks and

(ISG-5) other electrical connections).

The position includes only fuse holders

that are not inside the enclosure of

active components (e.g., inside of

switchgears, and inverters).

Operating experience finds that metallic

clamps (spring-loaded clips) have a

history of age-related failures from aging

stressors such as vibration, thermal

cycling, mechanical stress, corrosion,

and chemical contamination.

The staff finds that visual inspection of

fuse clips is not sufficient to detect the

aging effects from fatigue, mechanical

stress, and vibration.

The ISG Process This ISG updates and provides N/A

(ISG-8) clarification to the ISG process on

Improved Ucense Renewal Guidance

Documents.

Standardized Format for Ucense Renewal The purpose of this ISG is to provide a NIA

Applications standardized license renewal application

(ISG-10) format for the 2003 applicants.

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1.5 Summary of Open Items

As a result of its review of the LRA for PBNP Units 1 and 2, including additional information

submitted to the NRC through March 31, 2005, the staff identified five items that remained open

at the time the SER with open Items was published. An issue was considered open if the

applicant had not presented a sufficient basis for resolution. Each open item (01) had been

assigned a unique identifying number. By letters dated April 8,-April 29, June 10, July 5, July 8,

and July 19, 2005, the applicant responded to these Ols. The staff reviewed these responses

and closed each of the Ols. The basis for closing the Ols is as follows:

01 B2.1 (Sections 3.0.3.2.1 and 3.0.3.2.2 - ASME Section Xl Inspection Programs)

Relief requests are approved by the NRC as described in 10 CFR 50.55a, Codes and

Standards. Relief requests only apply to the CLB and are time-limited. Consequently, citing

approved requests cannot be used as'a basis for taking exception to the GALL Report since

they may not be renewed. Each exception to the GALL Report must be evaluated for NRC

approval based on the technical bases that are associated with aging management regardless

of whether there is an approved related relief request. Citing a relief request does not provide

an acceptable basis to take an exception to the GALL Report.

In RAI B2.1, dated March 30, 2005, the staff requested the applicant to provide its technical

bases, as they relate to aging management, and without referencing any relief requests, for the

exceptions taken to ASME Code Section Xi, Subsections IWB, IWC, and IWD Inservice

Inspection Program and ASME Code Section Xl, Subsections IWE and IWL Inservice

Inspection Program. This was identified as open item (01) B2.1.

In its response to 01 B2.1, by letter dated July 5, 2005, the applicant withdrew most of the

alternatives, initially credited as exceptions. The applicant clarified in its letter that these

alternatives are not exceptions to the GALL Report as they are either administrative and did not

affect aging management or the aging effect was managed by another aging management

program cited in the LRA. For the remaining alternatives, the applicant provided technical

justifications and commitments in support of the exceptions. The staff found each of the bases

provided in the applicant's RAI response acceptable. The staff's concerns with respect to the

exceptions to ASME Section Xl, Subsections IWB, IWC, and IWD, Subsections IWE and IWL,

and Subsection IWF are resolved. Therefore, 01 B2.1 is closed.

01 B2.1.4-2 (Section 3.0.3.2.4 - Bolting Integrity Program)

The GALL Report relies on industry recommendations for comprehensive bolting maintenance,

as delineated in EPRI TR-104213 for pressure-retaining bolting and structural bolting. The

applicant indicated that enhancements to the existing plant implementation documents dealing

with bolted joints will be made to incorporate recommendations as deemed appropriate based

upon review of NUREG-1 339, EPRI NP-5769, and EPRI TR-1 04213. The applicant has not

identified exceptions to these NUREG and EPRI documents.

In RAI 2.1.4-2, dated February 7, 2005, the staff requested the applicant to provide specific

exceptions to the Bolting Integrity Program. The staff should be informed of, and approve

specific exceptions to the bolting recommendations in these NUREG and EPRI documents.

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The applicant should provide this information for staff review and approval prior to issuance of

the extended license. This was identified as open item (01) B2.1.4-2.

The staff's concern was referred to the Region IlIl staff, which performed its AMR/AMP onsite

inspection during the weeks of March 7 and 21, 2005. In its response to 01 B2.1.4-2, by letter

dated April 8, 2005, the applicant provided specific exceptions to EPRI NP-5769. The

applicant's discussion and technical justifications were evaluated and accepted by the staff.

The staff's concern is resolved; therefore, 01 B2.1.4-2 is closed.

013.1.1-3 (Section 3.1.2.3.6 - Steam Generators - Aging Management Evaluation -

Table 3.1.2-5)

LRA Table 3.1.2-5 identifies Notes H, 21 and J, 5 for loss of material in stainless steel, carbon

steel clad with stainless steel and Alloy 600/690 materials. For these AMRs only the Water

Chemistry Control Program is identified as the applicable AMP. PBNP personnel have

indicated that the basis for using only the mitigative Water Chemistry Control Program is that

the program does not require lack of aging effect validation if the flow is moderate or high. The

staff considers this a misinterpretation of the GALL AMP. The GALL Report identifies stagnant

or low flow conditions as an example of when it would be appropriate to validate the

effectiveness of the Water Chemistry Control Program. The GALL Report utilizes this example

to demonstrate when a validation of aging management program is appropriate, but does not

define, by default, when a validation should not be used. In conditions of moderate or high flow,

SSCs could have crevices or other locations of low or stagnant flow. Furthermore, all systems

are shut down and flow is reduced to stagnant conditions at some point in its service life.

Therefore, this was identified as open item (01) 3.1.1-3.

In its response to 01 3.1.1-3, by letter-dated June 10, 2005, the applicant stated that for steam

generator (SG) components in contact with primary water; the same material types in the same

environments exist in the reactor vessel, the vessel internals, the pressurizer, and the Class 1

piping and components. In all of these systems and components, loss of material is proposed

to be managed with the Water Chemistry Control Program. The primary side of the SG are

stainless steel and nickel alloy which are corrosion-resistant materials. For these materials,

industry and plant-specific operating experience has shown that loss of material is not an active

degradation mechanism on primary side components, primarily due to the strict water chemistry

controls used in PWRs. Other components in this same environment are routinely inspected

(i.e., SG tubes) and these inspections would provide leading indications to the susceptibility of

these materials to loss of material.

The staff reviewed the applicant's characterization and reevaluated the GALL Report for loss of

material in stainless steel, carbon steel clad with stainless steel and Alloy 600/690 materials

and concluded that the applicant's response is acceptable. The staff's concern is resolved;

therefore, 01 3.1.1-3 is closed.

013.3-7 (Section 3.3.2.3.3 - Component Cooling Water System - Aging Management

Evaluation - Table 3.3.2-2)

In LRA Table 3.3.2-2, the applicant proposed to manage cracking due to

intergranular attack/intergranular stress corrosion cracking (IGA/IGSCC) of stainless steel

material for heat exchanger components exposed to primary treated water with temperature

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greater than 480 OF using the Water Chemistry Control Program. This line item cites Note 35,

which states: "Component/materiaVenvironment is not addressed in the corresponding

NUREG-1 801 Chapter, but the component/materiaVenvironment is addressed in another

NUREG-1801 Chapter." This line item references AMR line item 3.1.1-36, which provides the

following discussion:

Crack initiation growth due to SCC and flaw growth are identified as aging effects

requiring management for the reactor vessel nozzle safe ends, CRD housing, and RCS

components. Aging management programs credited for managing these effects are the

Water Chemistry Program and ASME Section Xl, Subsections IWB, IWC, and IWD

Inservice Inspection Program.

The Note implies that ASME Section Xl, Subsections IWB, IWC, and IWD Inservice Inspection

Program should have also been applied to LRA Table 3.3.2-2. In RAI 3.3-7, dated

March 31, 2005, the staff requested the applicant to explain this discrepancy or make a

commitment to revise the line item in LRA Table 3.3.2-2 to include the Inservice Inspection

Program. This was identified as open item (01) 3.3-7.

In its response to 01 3.3-7, by letter dated June 10, 2005, the applicant committed to use the

One-Time Inspection Program in conjunction with the Water Chemistry Control Program to

manage IGA/IGSCC aging mechanisms. The staff found the applicant's response to RAI 3.3-7

and the addition of the One-Time Inspection Program is an acceptable approach to manage the

aging effects. The staff's concern is resolved; therefore, 01 3.3-7 is closed.

01 3.5-4 (Section 3.5.2.2.1 - PWR Containments)

The discussion column of LRA Item 3.5.1-12 refers to LRA Section 3.5.2.2.1.4 for further

evaluation. In the discussion, the applicant noted that the liner corrosion was identified in both

units due to borated water leakage, and that ASME Code Subsection IWE inspections would be

performed in these areas. In RAI 3.5-4, dated July 27,2004, the staff requested the applicant

to provide a quantitative summary of the extent of liner corrosion found in each unit, and the

corrective actions taken. The applicant was also requested to include a discussion of

acceptable liner plate corrosion.

In its response, dated August 26,2004, the applicant stated that the areas of concern include

(1) the bottom containment liner plate (floor), which is covered by an eighteen-inch-thick

concrete floor, and (2) SW and CCW penetrations. The penetrations have detectable pitting in

the flued head region. On occasions, spilled borated water has seeped into the liner plate floor

crevice. The liner plate floor receives UT measurements at selected locations.

During a meeting on February 15, 2005, the staff indicated and the applicant agreed, that this

response required further clarification. The staff requested the applicant to clarify the corrective

actions taken, including procedural descriptions, when loss of material is identified.

In its response, a clarification letter dated March 15, 2005, the applicant summarized that the

necessity for repair has been determined on a case-by-case basis. The table provided with the

response showed the liner plate base thickness reduction was as high as 46%. The response

indicated that such degradation was found acceptable without'repair. As this process will be

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continued during the period of extended operation, the staff requested additional information

regarding the basic criteria used in the engineering evaluation. Specifically, the staff requested

the applicant to provide a summary of the engineering evaluations performed for CAP 22754

and CAP 13912 (designated in the applicant's response table), including the type of corrosion,

loads considered in the evaluation, acceptable liner strains, and strain concentration factors

considered, if applicable. The applicant was also requested to provide the procedure

describing the "as left" condition of the degradation. This was identified as open item

(01) 3.5-4.

In its response to 01 3.54, by letter dated June 10, 2005, the applicant provided the condition

reports and the engineering evaluations (CR 01-1517 and CR 01-1220) prepared for the two

events. Subsequently, the staff indicated that, according to the numbers provided in

CR-01 -1517, the applicant would have to monitor the affected area(s) under augmented

inspection (WE-1241) and set a limit on acceptable liner corrosion. With respect to

CR-01 -1220 the staff stated that the report statement 'under normal operating condition, the

liner experiences no strain, is incorrect. The staff believes that although the liner is not

accounted for in structural calculations, by virtue of its being anchored to the concrete, it

experiences compressive strains due to dead load, prestressing and creep of concrete. The

staff indicated that unless an analysis is performed to show that with the reduced thickness of

0.116 inches, the liner will be able to withstand the postulated loads without giving rise to

different mode of failure, such corrosion without corrective action is not acceptable. By letter

dated July 8, 2005, the applicant made the following commitments:

(1) An evaluation, repair or replacement requirement discussion will be included in the

Acceptance Criteria element of the ASME Section Xl, Subsections IWE and IWL

Inservice Inspection Program of the LRA prior to the period of extended operation. If

localized area thickness of the containment liner base metal is reduced by 50% or more

of the nominal plate thickness, then every attempt should be made to correct by repair

or replacement. If the repair or replacement option is impractical, an acceptance by

engineering evaluation option may be pursued.

(2) If localized area thickness of the base metal is reduced by approximately 50 percent or

more of the nominal plate thickness, then the reexaminations required by IWE 2420(b)

will be continued in the succeeding inspection periods and the provisions of

IWE-2420(c) will not be applied.

Based on the applicant's responses to RAI 3.5-4, the description of the process and the

commitments discussed above, the staff found the overall approach in detecting and correcting

the flaws and degradation in the containment liner plates acceptable. The staff's concerns are

resolved; therefore, 01 3.5-4 is closed.

1.6 Summary of Confirmatory Items

As a result of its review of the LRA for PBNP Units 1 and 2, including additional information and

clarifications submitted to the NRC through March 31, 2005, the staff identified the following

confirmatory items. An issue was considered confirmatory if the staff and the applicant have

reached a satisfactory resolution, but the resolution has not yet been formally submitted to the

staff. Each confirmatory item (Cl) had been assigned a unique identifying number. By letters

dated April 1, April 8, April 29, June 9, June 10, June 29, and July 19, 2005, the applicant

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responded to these CIs. The staff reviewed these responses and closed each of the Cis. The

basis for closing the Cis is as follows:

CI 2.1-1 (Section 2.1.2.1.2 - Application of the Scoping Criteria In 10 CFR 54.4(a))

In RAI 2.1-1, dated November 16, 2004, the staff requested additional information regarding the

scoping methodology associated with the 10 CFR 54.4(a)(2) evaluation. The staff requested

the applicant to adequately define short term exposure duration as it relates to the evaluation of

low and moderate energy piping failures that could affect safety related electrical equipment.

Since this equipment may not be environmentally qualified, it could fail due to

10 CFR 54.4(a)(2) piping failures

In its response, dated January 31, 2005, the applicant stated that for the purpose of license

renewal, the term "exposure duration" will be removed from LRA Section 2.1.2.1.2 and it will

provide a technical justification as to why the safety-related SSCs are capable of withstanding

the effects of spray and leakage. The applicant also stated that it will include a technical

justification in the LRA annual update under the section "Components Qualified/Designed for

Environment".

During a meeting on February 15, 2005, the staff indicated and the applicant agreed, that this

response required further clarification. -In its response, a clarification letter dated

March 15, 2005, the applicant committed to provide details of the 10 CFR 54.4(a)(2) scoping

methodology changes, including specific exceptions, and how these will impact the LRA. The

staff agreed with the applicant's proposed methodology changes. However, the applicant

committed to provide detailed information with regard to these changes by the end of

April 2005. This was identified as confirmatory item (Cl) 2.1-1.

In its response to Cl 2.1-1, by letter dated April 29, 2005, the applicant provided additional

information regarding its scoping methodology changes. This revised methodology invokes a

plant spaces approach that assumes a spatial interaction can occur if safety-related and

nonsafety-related system or component (SC) are located within the same space. For purposes

of the process, a space is defined by the room in which the safety-related and nonsafety-related

components are located. This revised methodology evaluates the effect of sprays and leaks on

mechanical and electrical safety-related SCs, with no limitation on duration of the sprays/leaks. The applicant thus considers all liquid or steam bearing nonsafety-related SCs to be within the

scope of license renewal pursuant to 10 CFR 54.4(a)(2), provided that the nonsafety-related

SCs are located in the same space as a safety-related SC and that the nonsafety-related SCs

are in proximity where spray or leakage from nonsafety-related SC could contact a

safety-related SC.

Based on this revised 10 CFR 54.4(a)(2) methodology, the applicant re-evaluated SCs to

identify configurations where the failure of nonsafety-related SCs could result in the loss of an

intended function of the safety-related SCs within the space and, were therefore, considered

within the scope of license renewal. This re-evaluation led to the expansion of scope for some

systems, to the addition of component groups and line items to several tables in the LRA. The

applicant noted that the results of the review using the new methodology discovered no new

aging effects/mechanisms and aging management program assignments are consistent with

those previously identified in the LRA.

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Based on the above discussion, the staff found the applicant's response to RAI 2.1-1

acceptable. The staff's concern is resolved; therefore, Cl 2.1-1 is closed.

CI 2.1-2 (Section 2.1.3.1.1 - Application of the Scoping Criteria in 10 CFR 54.4(a))

In RAI 2.1-2, dated November 16, 2004, the staff requested additional information regarding the

scoping methodology associated with the 10 CFR 54.4(a)(2) evaluation. The staff requested

the applicant to define first equivalent anchor as it relates to the evaluation of nonsafety-related

piping directly connected to safety-related piping. The staff also requested the applicant to

describe the methodology of its application. Additionally, in cases where plant equipment

credited with providing support to nonsafety-related piping may be equivalent to an associated

piping anchor as described in NUREG-1 800, the staff requested the applicant to provide

justification for not including this plant equipment within the scope of license renewal.

In its response, dated January 31, 2005, the applicant stated that PBNP has included all the

connected nonsafety-related piping and supports, up to and including the first equivalent anchor

beyond the safety/nonsafety interface, within the scope of license renewal. The applicant also

stated that nonsafety-related pipe supports will be managed in a commodity spaces" approach

wherein all supports in the areas of concern are included within the scope of license renewal.

The directly connected nonsafety-related piping will be age-managed using the same programs

that manage the safety-related piping. This process conforms to the requirements for the

nonsafety-related SSCs connected to safety-related SSCs pursuant to 10 CFR 54.4(a)(2) and

the guidance of draft ISG-09. This was identified as confirmatory item (Cl) 2.1-2.

Further in its response, the applicant described what is meant by first equivalent anchor and

also described the analysis techniques used for evaluating the piping stress analysis

boundaries for identifying the first equivalent anchor point for scoping purposes.

Based on the above discussion, the staff found the applicant's response to RAI 2.1-2

acceptable. The staff's concern is resolved; therefore, Cl 2.1-2 is closed.

CI 2.1-3 (Section 2.1.2.1.2 - Flow-Accelerated Corrosion Effect on Piping Section Scoping in

10 CFR 54.4(a)(2))

In RAI 2.1-3, dated November 16, 2004, the staff requested additional information regarding the

scoping methodology associated with the 10 CFR 54.4(a)(2) evaluation. The staff requested

the applicant to describe how the falling of piping sections is not considered credible and why

the piping section itself would not be within the scope of license renewal pursuant to

10 CFR 54.4(a)(2) due to physical impact hazard. The staff also requested the applicant to

describe how the management of flow-accelerated corrosion (FAC) relates to the scoping and

screening of 10 CFR 54.4(a)(2) seismic I1/I piping systems that could cause these types of

failures.

In its response, dated January 31, 2005, the applicant stated that for the purpose of license

renewal, the nonsafety-related pipe segments, for the Criterion 2 scoping, have essentially

three potential modes: (1) for nonsafety-related low or moderate energy piping, managing of

the nonsafety-related supports will ensure that these supports remain intact and will not fall on

safety-related components, (2) for nonsafety-related high energy piping segments, FAC failure

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for components in proximity to safety-related components would be considered within the scope

of license renewal as long as failure is considered credible, and (3) nonsafety-related piping

sections that could have spray, leakage, or harsh environment effects on vulnerable

safety-related equipment are considered within the scope of license renewal.

During a meeting on February 15, 2005, the staff indicated and the applicant agreed, that this

response required further clarification. In its response, a clarification letter dated

March 15, 2005, the applicant committed to remove from the response the phrase 'as long as a

FAC failure is considered credible." This was identified as confirmatory item (CI) 2.1-3.

In its response, a clarification letter dated March 15, 2005, the applicant removed the phrase

"as long as a FAC failure in that line and impact in safety-related components is considered

credible from its original response to RAI 2.1-3.

Based on the above discussion, the staff found the applicant's response to RAI 2.1-3

acceptable. The staff's concern is resolved; therefore, Cl 2.1-3 is closed.

Cl 2.4-2 (Section 2.4.8 - Yard Structures)

LRA Section 2.4 does not appear to contain information about tanks and their foundations. In

RAI 2.4-2, dated January 26, 2005, the staff requested the applicant to provide a list of all tanks

and their foundations for each unit. Additionally, the staff requested the applicant to:

(1) identify the tanks and their foundations that are in-scope and define their intended functions,

(2) identify the tanks and their foundations that are not in-scope and the basis for their

exclusion, and (3) specify where the AMR for each in-scope tank and tank foundation is located

in the LRA.

In its response, dated February 25, 2005, the applicant stated that tanks are associated with

the system in which they reside. They are addressed and scoped in the mechanical section of

the LRA; Section 2.3. The tables In LRA Section 2.3 have a component group, nTanks." The

license renewal drawings for the systems are listed and tanks that are in-scope are highlighted

on the drawings. Tank foundations are scoped in LRA Section 2.4 and are typically constructed

of concrete or steel. Tanks foundations and intended functions are typically presented in LRA

Sections 2.4.8 and 2.4.10, or individual section for the building. Tank and tank foundation AMR

information is contained in the corresponding LRA Sections 3.1 through 3.5.

Based on its review, the staff finds the applicant's response to RAI 2.4-2 acceptable in that

tanks are addressed and scoped in the mechanical section, LRA Section 2.3. However, the

staff finds unacceptable the omission of tank foundations from LRA Section 2.4. The applicant

should identify the tank foundations that are within the scope of license renewal. This was

identified as confirmatory item (Cl) 2.4-2.

In its response to Cl 2.4-2, by letter dated June 10, 2005, the applicant identified individual

tanks and their foundations that are within the scope of license renewal. Subsequently, the

applicant submitted a letter, dated June 29, 2005, to clarify the intended functions and AMR

information of those tank foundations that are within the scope of license renewal. This letter

stated that the intended function for tank foundations is either a safety-related or a

nonsafety-related support and that the AMR information is contained within the corresponding

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LRA Section 3.5. Since tank foundations are not stated under the column of component types

in buildings of LRA Section 3.5, the applicant uses examples to illustrate that the tank

foundations within the scope of license renewal are included in either concrete or steel

component types, and further stated that every in-scoped tank foundation within a building or in

yard structures would be captured by those component items.

With all in-scoped tanks and their foundations identified, intended functions stated, and the

AMR information clarified, the staff concluded that the applicant has properly documented the

necessary information related to the tanks and their foundations and considers the applicant's

response to RAI 2.4-2 to be acceptable. The staff's concern is resolved; therefore, Cl 2.4-2 is

closed.

CI B2.1.4-3 (Section 3.0.3.2.4 - Bolting Integrity Program)

In RAI B2.1.4-3, dated February 7, 2005, the staff requested the applicant to provide data that

demonstrate that the bolting, loaded with the maximum shear stress, would not be susceptible

to SCC. Additionally, the staff requested the applicant to identify the inspection history for its

bolts that demonstrate that they are not susceptible to SCC.

In its response, dated March 4, 2005, the applicant stated, in part, that the Boric Acid Program

takes a critical look at bolting. Whenever boric acid is found, the requirement is to look at the

flow path of where the boric acid has traveled. If boric acid is found on bolting, the boric acid

will be removed and a visual examination performed on the fasteners to determine if any

degradation has occurred. NMC will follow plant procedures for repair or replacement if the

evaluation determines the bolting is not acceptable.

The inspection history results are reported in the applicant's response to RAI B2.1.4-3. Since

1991, reactor coolant pump supports and SG supports have been inspected on numerous

occasions. No recordable indications have been observed. The Region IlIl staff, on its

AMR/AMP onsite inspection during the weeks of March 7 and 21, 2005, will confirm that there

were no failure of high strength bolts. This was identified as confirmatory item (Cl) B2.1.4-3.

The inspection history for high strength bolts was verified by the Region III staff, during their

AMR/AMP onsite inspection. Section D.1 of the DRS Aging Management Inspection Report,

dated May 2, 2005, states the following:

The inspectors requested specific searches of the plant specific operating experience

and verified that the applicant performed adequate historic reviews to determine aging

effects. The inspectors determined that the licensee did not have any documented

occurrences of failure in high strength structural bolting. During plant walkdowns, the

inspectors specifically looked for cases where structural bolting appeared loose, missing

or failed; no problems were identified. Following submittal of the LRA, the licensee did

identify two cases where component bolts were replaced. In one case, the licensee

discovered a longitudinal crack in a reactor coolant pump seal package bolt. The

licensee replaced the bolt and sent the cracked bolt off for laboratory analysis. The

crack was determined to be a manufacturing defect and not related to aging

degradation. The second case was replacement of all the bolting on the Unit 2

pressurizer after indications were identified during the inservice inspection. The

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indication disposition report and a subsequent corrective action procedure (CAP)

document analyzed the indications and determined that the majority of the indications

were minor, appeared most likely due to normal installation and

removal of the bolts, and did not affect the integrity of the bolting. However, one bolt

had two minor "crack like" indications. The licensee did not determine the cause of

these indications; however as the bolts were replaced and no pressurizer leakage had

occurred during the previous operating cycle, the inspectors concluded that the

licensee's inservice inspection program had adequately addressed the issue.

The staff found this acceptable since the inspectors confirmed that the applicant did not have

any documented occurrences of failure in high strength structural bolting. The staff's concern is

resolved; therefore, Cl B2.1.4-3 is closed.

CI B2.1.11-1 (Section 3.0.3.2.11 - Flow-Accelerated Corrosion Prograrnm

During the audit, the staff noted that for the "acceptance criteria" program element, it is unclear

how the applicant calculates the minimum permitted wall thickness and how it is used in its

analysis for flow-accelerated corrosion. In RAI B2.1.11-1, dated March 30, 2005, the staff

requested the applicant to clarify its wall thickness calculation and its uses.

The staff's concern was referred to the Region IlIl staff, which performed its AMR/AMP onsite

inspection during the weeks of March 7 and 21, 2005. The applicant clarified its methodology.

The applicant stated that the minimum wall calculations are performed using the design

pressure, which is greater than the operating pressure and demonstrates that the actual

measured wall thickness is greater than the minimum thickness required by the maximum hoop

stress. If degradation is detected such that the wall thickness is less than or equal to 87.5

percent of nominal wall thickness for safety-related piping or 60 percent of nominal wall

thickness for nonsafety-related piping, additional examinations will be performed in adjacent

areas to bound the thinning and assure that the actual minimum wall is measured. In addition,

the applicant will provide its justification and confirmation that the minimum wall thickness will

be maintained for the period of extended operation. This was identified as confirmatory item

(Cl) 132.1.1 I1-1 .

In its response to Cl B2.1.1-11, by letter dated June 9, 2005, the applicant stated that during

the Region IlIl AMR/AMP onsite inspection, a detailed review of the Fow-Accelerated Corrosion

Program was completed. As a result of that review and discussions between the Region III

staff, the License Renewal Branch, and Division of Engineering personnel, PBNP provided a

clarification to LRA Section B2.1.1.1 1, "Flow-Accelerated Corrosion Program," by letter dated

April 8, 2005. -Based upon discussions with the NRC staff on May 3, 2005, a revision to the

April 8, 2005, letter was identified to clarify the intent of the sample expansion criterion. By

letter dated June 9, 2005, the applicant provided a modified text to clarify its program. The

revised text replaced the discussion under the program element "Monitoring and Trending" in

LRA Section B2.1.11 as follows:

If degradation is detected such that the wall thickness is less than or equal to 87.5% of

nominal wall thickness for safety-related piping, additional examinations will be

performed in adjacent areas to bound the thinning. For both safety-related and

non-safety related piping, additional examinations will be performed in adjacent areas to

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bound the thinning if the remaining service life, based on the code minimum allowable

wall thickness, is less than one operating cvcle. The sample size will also be expanded

for non-safety related piping if degradation is detected such that the wall thickness is

less than or equal to 60% of nominal wall thickness. This covers situations where the

code minimum allowable wall thickness may be less than 60% of nominal wall thickness

for non-safety related piping. The expansion of the sample size should include a

minimum of the next two most susceptible components in that CHECWORKS line, any

component within two pipe diameters downstream (upstream if expander), or like

components in parallel trains. If the initial expansion finds additional components with

significant loss of material due to FAC, the examination scope is expanded further.

This element includes exceptions to the corresponding NUREG-1801 aging

management program element. NUREG-1801 states: "If degradation is detected such

that the wall thickness is less than the minimum predicted thickness, additional

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

interpretation of this sample expansion criteria is not practical in many cases. If very

little degradation is predicted, measured wall thickness may be less than the predicted

thickness even though the calculated life of the affected component may exceed the

operating life of the plant. In this case, sample expansion would not be warranted.

The FAC program at PBNP implements the EPRI guidelines in NSAC-202L-R2, which

recommends increasing the sample size when inspections of the sample detect

significant FAC wear. In the PBNP FAC program, significant FAC wear is defined as

FAC resulting in a wall thickness of less than or equal to 87.5% of nominal wall

thickness for safety related piping. For both safety related and non-safety related

piping, additional examinations will be performed in adjacent areas to bound the thinning

if the remaining service life, based on the code minimum allowable wall thickness, is

less than one operating cycle. The sample size will also be expanded for non-safety

related piping if degradation is detected such that the wall thickness is less than or equal

to 60% of nominal wall thickness. This covers situations where the code minimum

allowable wall thickness may be less than 60% of nominal wall thickness for non-safety

related piping. This criterion for sample expansion is acceptable because it specifies a

wall thickness criterion and requires projection of inspection results to the next

inspection opportunity consistent with industry guidance. Therefore, PBNP meets the

intent of this NUREG-1801 aging management program element.

The staff reviewed the responses to RAI B2.1.1-11, the exception to the GALL Report and the

final text to be included in the AMP and concluded that the applicant had appropriately defined

the program and demonstrated that the program as defined provides reasonable assurance

that structural integrity will be maintained. The staff's concern is resolved; therefore,

Cl B2.1.1-11 is closed.

Cl 3.1.1-1 (Section 3.1.2.1.1 - Loss of Fracture Toughness Due to Thermal Aging

Embrittlement)

The staff finds that the use of leak-before-break evaluation method is not equivalent to a flaw

tolerance methodology; it assumes through-wall leakage and, therefore, does not assure the

safety function of pressure boundary integrity. In RAI 3.1.1-1, dated March 30, 2005, the staff

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requested the applicant to clarify how it manages the aging effect of loss of fracture toughness

due to thermal aging embrittlement for CASS primary loop elbows. During a telephone

conference, the applicant agreed to revise its position and perform flaw tolerance evaluations.

This was identified as confirmatory item (Cl) 3.1.1-1.

In its response to Cl 3.1.1 -1, by letter dated June 9, 2005, the applicant stated that PBNP will

follow the recommendation of GALL AMP XL.M12 and that it will use enhanced volumetric

examination or a flaw tolerance evaluation to demonstrate that CASS primary loop elbows,

potentially susceptible to thermal embrittlement, have adequate fracture toughness.

The staff found the applicant's response to RAI 3.1.1-1 acceptable as it results in the actions

being consistent with the GALL Report recommendations. The staff's concern is resolved;

therefore, Cl 3.1.1-1 is closed.

CI 3.1.1-2 (Section 3.1.2.2.10 - Loss of Section Thickness Due to Erosion)

In RAI 3.1.1-2, dated March 30, 2005, the staff requested the applicant to justify why the SG

feedrings and associated J-tubes are outside the scope of license renewal. During a telephone

conference, the applicant agreed to add the SG feedrings and J-tubes to the scope of license

renewal and manage the associated aging effects. This was identified as confirmatory item

(Cl) 3.1.1-2.

In its response to Cl 3.1.1-2, by letter dated June 9, 2005, the applicant stated that J-nozzles,

feedrings, and feedring supports have been added to the scope of license renewal to address a

potential issue, where failures of nonsafety-related components could affect the safety-related

SG tubing. Therefore, the aging management programs for these components need to ensure

that the feedring components stay in-place and not fall on the SG tubes. The applicant will

age-manage the SG feedrings, J-nozzles, and feedring supports using the Water Chemistry

Control Program and the Steam Generator Integrity Program. The Steam Generator Integrity

Program provides for-various inspections of the secondary side of the SGs, which will provide

verification that aging effects are not progressing, thereby ensuring that the feedring and

J-nozzles remain in-place.

The staff found the applicant's response to RAI 3.1.1-2 acceptable because it brought the

J-nozzles, feedrings, and feedring supports Into the scope of license renewal and appropriately

manages the aging effects to assure that the component will not prevent safety-related

components from performing its associated safety functions. The staff's concern is resolved;

therefore, Cl 3.1.1-2 is closed.

CI 3.5-12 (Section 3.5.2.2.1 - PWR Containments - Cracking Due to Cyclic Loading and Stress

Corrosion Cracking (SCC))

In LRA Section 3.5.2.2.1.7, the applicant stated that SCC is not an applicable aging mechanism

for penetration sleeves, bellows, and dissimilar metal welds. Therefore, the applicant did not

address cracking due to cyclic loading. In RAI 3.5-12, dated March 30, 2005, the staff

requested the applicant to address the difference between its position and the GALL Report

recommendation of enhanced inspection methods. The staff noted that the TLAA in LRA

Section 4.3.11 does not detect and manage cracking due to cyclic loading. The applicant was

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requested to provide further clarification for crediting this specific line item to manage cracking

due to cyclic loading.

During a telephone conference, the applicant indicated that this is a TLAA and will provide

information to confirm that this is adequately addressed in LRA Section 4.3.11. The staff

agreed with the applicant's statement. This was identified as confirmatory item (Cl) 3.5-12.

In its response to Cl 3.5-12, by letter dated June 9, 2005, the applicant clarified its basis for

concluding that the use of a fatigue analysis as the basis for managing fatigue is consistent with

the positions stated in the GALL Report (NUREG-1 801 Vol. 1, Table 5, Items 3.5.1 -1

and 3.5.1-2). In addition, the applicant stated that SCC is not an applicable aging effect due to

the lack of an aggressive chemical environment. Further, the applicant clarified that aging

management of the containment penetration sleeves is addressed by the ASME Section Xl,

Subsection IWE and IWL Inservice Inspection Program and the Boric Acid Corrosion Program.

Lastly, the applicant stated that PBNP does not have any penetration bellows in the scope of

license renewal.

The staff found the applicant's response to RAI 3.5-12, the categorization of aging effects and

its aging management, appropriate and consistent with the guidance of the GALL Report. The

staff's concern is resolved; therefore, Cl 3.5-12 is closed.

Cl 3.5-13 (Section 3.5.2.2.1 - PWR Containments - Aggressive chemical attack)

In LRA Section 3.5.2.2.1.1, the applicant stated that concrete degradation in air due to

aggressive rainwater is insignificant and that the below-grade/lake water environment is

nonaggressive. In RAI 3.5-13, dated March 30,2005, the staff requested the applicant to

provide sufficient data to support this statement.

Furthermore, during the review, the staff was unable to identify how the LRA addresses the

items described in ISG-03. The staff requested the applicant to provide detailed information

with regard to how its AMRs address all the items described in ISG-03.

During a telephone conference, the applicant described how it will satisfy the ISG-03 criteria

and agreed to provide its most recent data with respect to the below-grade/lake water. The

applicant committed to provide a formal response, including a table detailing how it satisfies all

the items described in ISG-03. This was identified as confirmatory item (Cl) 3.5-13.

In its response to Cl 3.5-13, by letter dated June 9, 2005, the applicant provided its ground

water environment monitoring data and an explanation of where the LRA addresses each of the

provisions of ISG-03. In addition, the applicant clarified the percentage of entrapped air in the

containment concrete. As part of the response, the applicant committed to monitoring ground

water chemistry (pH, chlorides, sulfates) at least once every 5 years.

The staff found the applicant's response to RAI 3.5-13 and its commitment to be consisted with

the guidance of the GALL Report and ISG-03. The staff's concerns are resolved; therefore,

Cl 3.5-13 is closed.

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Cl 3.5-14 (Section 3.5.2.2.3 - Component Supports - Aging of Supports Not Covered by the

Structures Monitoring Program)

In LRA Table 3.5.1, Item 3.5.1-33, the applicant stated that the Bolting Integrity Program

includes the use of Inservice Inspection to evaluate and monitor crack initiation and growth due

to SCC, if present, in high strength low-alloy steel bolts used in NSSS component supports. In

LRA Tables 3.5.2-1 through 3.5.2-14, the applicant does not address Group B1.1, high strength

low-alloy bolts. In LRA Section B2.1.4, the applicant indicated that high strength component

support bolting is used in pinned connections associated with steam, reactor coolant pumps

and reactor vessel supports and is loaded only in shear with no preload stress.

In RAI 3.5-14, dated March 31, 2005, the staff requested the applicant to identify how aging will

be managed for the Group B1.1, high strength low-alloy bolts. During a telephone conference,

the applicant stated that this RAI is similar to one previously issued for the Bolting Integrity

Program, RAI B2.1.4-3. The staff reviewed the applicant's response to this RAI and found it

acceptable. .The applicant proposed how to manage aging and credited the Boric Corrosion

Program and it plant procedures. The applicant also acknowledged that PBNP have some

torqued high-strength bolts. The applicant will supplement its response to reflect this

statement. This was identified as confirmatory item (Cl) 3.5-14.

In its response to Cl 3.5-14, by letter dated April 29, 2005, the applicant stated that the aging

effect mechanism associated with line item 3.5.1-33 is crack initiation and growth due to SCCO

and that it had evaluated SCC as not being an applicable aging effect requiring management at

PBNP. The aging effects requiring management for Group B1.1 bolting include line

item 3.5.1-31, loss of material due to boric acid wastage, and line item 3.5.1-32, loss of material

due to general corrosion. These aging effects are depicted in LRA Table 3.5.2-10, which

addresses Group B1.1 bolting. The intent of the Discussion column for line item 3.5.1-33 was

that Nif present," cracking may be detected during ISI inspections that would evaluate any noted

non-conformance.

The staff evaluated the applicant's response to RAI 3.5-14 and the technical basis provided and

agreed that SCC is not an active aging mechanism requiring management in this situation. The

staff's concern is resolved; therefore, Cl 3.5-14 is closed.

Cl 4.6.1-1.1 (Section 4.6.1 - Spent Fuel Pool Storage Rack Boraflex)

The surveillance frequency of once every 5 years for blackness testing was approved in an

NRC letter dated February 21, 1990. Based on industry operating experience indicating the

varying degree to which the Boraflex panels degrade, the staff requested a justification for

continuing the 5-year frequency for areal density testing into the period of extended operation.

In RAI 4.6.1-1, dated March 29, 2005, the staff requested the applicant to provide the most

recent blackness test and SFP silica level measurements, and use this data to demonstrate that

the current rate of degradation will not exceed the acceptance criteria.

During conversations with the staff, the applicant committed to enhance the Boraflex Monitoring

Program, and agreed to provide the requested data to the Region IlIl staff at their AMR/AMP

onsite inspection during the weeks of March 7 and 21, 2005. The applicant's data and the

Boraflex Monitoring Program enhancements are expected to ensure that the neutron absorbing

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material will continue to perform its intended function during the period of extended operation.

This was identified as confirmatory item (Cl) 4.6.1-1.1.

In response to Cls 4.6.1-1.1 and 4.6.1-1.2, by letter dated April 1, 2005, the applicant

committed to create a new procedure to schedule and perform blackness testing and areal

density testing every 2 years during the period of extended operation on certain accelerated

Boraflex panels. These actions are consistent with the recommendations in the August 2001

Boraflex degradation analyses reviewed by the Region IlIl staff during the March 2005

inspection and as documented in its inspection report dated May 2, 2005. The staff found the

applicant's response to RAI 4.6.1-1 and its commitment acceptable because these actions

ensure that the neutron absorbing material will continue to perform its intended function in

maintaining SFP subcriticality. The staff's concerns are resolved; therefore, Cl 4.6.1-1.1 is

closed.

Cl 4.6.1-1.2 (Section 4.6.1 - Spent Fuel Pool Storage Rack Boraflex)

Additionally, in RAI 4.6.1-1, dated March 29, 2005, the staff requested the applicant to provide

justification for the 5-year frequency for areal density testing. During conversations with the

staff, the applicant committed to perform areal density and blackness tests on certain

accelerated Boraflex panels once every 2 years during the period of extended operation. The

applicant will revise its response to reflect this statement. This was identified as confirmatory

item (Cl) 4.6.1-1.2.

In response to Cis 4.6.1-1.1 and 4.6.1-1.2, by letter dated April 1,2005, the applicant

committed to create a new procedure to schedule and perform blackness testing and areal

density testing every 2 years during the period of extended operation on certain accelerated

Boraflex panels. These actions are consistent with the recommendations in the August 2001

Boraflex degradation analyses reviewed by the Region IlIl staff during the March 2005

inspection and as documented in its inspection report dated May 2,2005. The staff found the

applicant's response to RAI 4.6.1-1 and its commitment acceptable because these actions

ensure that the neutron absorbing material will continue to perform its intended function in

maintaining SFP subcriticality. The staff's concerns are resolved; therefore, Cl 4.6.1-1.2 is

closed.

Cl 4.6.1-2 (Section 4.6.1 - Spent Fuel Pool Storage Rack Boraflex)

The applicant indicated that a predictive code, UEPRI RACKLIFE or its equivalent," will be used

to determine which panels will be subjected to full-length testing and to trend and analyze SFP

silica level measurement results. The input to the predictive code includes areal density and

SFP silica level measurements. The staff is unclear on the ability of the predictive code to

project panel degradation if the first areal density test is completed after the beginning of the

extended operation period. In RAI 4.6.1-2, dated March 29, 2005, the staff requested the

applicant to provide justification regarding the ability of the predictive code to accurately project

the condition of the panels to ensure the degradation does not exceed the acceptance criteria

with one set of data. In addition, if this justification cannot be made, the staff requested that the

applicant commit to conducting a baseline areal density test prior to entering the period of

extended operation.

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During conversations with the staff, the applicant committed to perform a baseline areal density

inspection of the Boraflex panels prior to entering the period of extended operation for

predictive code purposes. The applicant will revise its response to reflect this statement. This

was identified as confirmatory item (Cl) 4.6.1-2.

In its response to Cl 4.6.1-2, by letter dated April 1, 2005, the applicant committed to perform a

baseline areal density inspection of the Boraflex panels prior to entering the period of extended

operation to support the use of a predictive code for projecting the condition of the panels

between surveillance tests. In addition, the applicant committed to perform an evaluation within

its corrective actions program should silica sampling and areal density trend to a value less

than the acceptance criteria. The corrective actions also include an increase in the frequency

of blackness testing and areal density testing. The staff found the applicant's response to

RAI 4.6.1-2 acceptable and the associated commitments appropriate because these actions

ensure that the predictive code will have the appropriate data for projecting the degradation of

Boraflex into the period of extended operation without exceeding the acceptance criteria. The

staff's concern is resolved; therefore, Cl 4.6.1-2 is closed.

Cl 4.6.1-3 (Section 4.6.1 - Spent Fuel Pool Storage Rack Boraflex)

For the acceptance criteria element, the applicant stated that this element is consistent with the

GALL Report. The applicant committed to making appropriate changes to the program if any of

the test results indicate that program improvements should be made. However, the staff finds

this discussion insufficient for ensuring adequate management of Boraflex degradation. In

RAI 4.6.1-3, dated March 29, 2005, the staff requested the applicant to provide more

information regarding the Boraflex Monitoring Program's acceptance criteria. Additionally, the

staff requested the applicant to provide a discussion regarding the specific corrective actions

that will be taken if trends indicate the acceptance criteria may not be met.

During conversations with the staff, the applicant committed to complete an evaluation, within

its corrective action program, and increase the frequency of blackness and areal density testing

if the silica sample and the areal density trend to a value less than 5 percent subcriticality

margin, or the acceptance criteria. The applicant committed to provide specific details of the

corrective actions that will take place if the acceptance criteria cannot be maintained. The

applicant's enhancements to the program and corrective actions are expected to ensure

continued material performance. The applicant will revise its response to reflect this statement.

This was identified as confirmatory item (Cl) 4.6.1-3.

In response to Cl 4.6.1-3, by letter dated April 1, 2005, the applicant committed to complete an

evaluation within its corrective action program if silica sampling and areal density trend to a

value less than the acceptance criteria. In addition, the frequency of blackness testing and

areal density testing will be increased. Specifically, corrective actions will be initiated if the test

results find that the 5-percent subcriticality margin cannot be maintained because of current or

projected future Boraflex degradation. These corrective actions may include, but are not limited

to, reanalysis, and repair and/or replacement of the neutron absorbing material. The staff

found the applicant's response to RAI 4.6.1-3 acceptable because the corrective actions ensure

continued material performance, consistent with the acceptance criteria, into the period of

extended operation. The staff's concerns are resolved; therefore, Cl 4.6.1-3 is closed.

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1.7 Summary of Proposed License Conditions

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

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

conditions.

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

10 CFR 54.21 (d) in the next FSAR update, 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 be completed prior to entering the period of extended operation; excluding those

actions agreed to be performed after entering the period of extended operation in order to meet

the requirements established in 10 CFR 50.61.

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 50, Appendix H.

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SECTION 2

STRUCTURES AND COMPONENTS SUBJECT TO AGING

MANAGEMENT REVIEW

2.1 Scoping and Screening Methodoloay

2.1.1 Introduction

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

Renewal of Operating Licenses for Nuclear Power Plants," Section 54.4, "Scope," requires each

application to determine plant systems, structures, and components (SSCs) within the scope of

license renewal. Section 54.21, "Contents of Application - Technical Information," requires each application to contain an integrated plant assessment (IPA). The IPA must list and

identify those SSCs that are within the scope of license renewal in accordance with

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

In LRA Section 2.1, the applicant described the scoping and screening methodology used to

identify the SSCs at the Point Beach Nuclear Plant (PBNP) that are within the scope of license

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

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

AMR screening requirements stated in 10 CFR 54.21.

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

requirements of 10 CFR Part 54, the statements of consideration (SOCs) related to the license

renewal rule, and the guidance provided by the Nuclear Energy Institute (NEI) in NEI 95-10,

Revision 3, March 2001, "Industry Guideline for Implementing the Requirements of

10 CFR Part 54 - The License Renewal Rule." The applicant also considered the NRC staff's

license renewal interim staff guidance (ISG) documents and related correspondence.

2.1.2 Summary of Technical Information In the Application

In LRA Sections 2.0 and 3.0, the applicant provided the technical information required by 10 CFR 54.21(a). In LRA Section 2.1, "Scoping and Screening Methodology," the applicant

described the process used to identify the SSCs that meet the license renewal scoping criteria

under 10 CFR 54.4(a), as well as the process used to identify the structures and components (SCs) that are subject to an AMR as required by 10 CFR 54.21 (a)(1). Additionally, LRA

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

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

and Component Supports;" and Section 2.5, "Scoping and Screening Results: Electrical and

Instrumentation and Controls," provide the results of the process used to identify the SCs that

are subject to an AMR.

LRA Section 3.0, "Aging Management Review Results," contains the following information:

* Section 3.1, "Aging Management of the Reactor Coolant System"

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

2-1
* 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 Containments, Structures and Component

Supports"

* Section 3.6, "Aging Management of Electrical and Instrumentation and Controls"

LRA Section 4.0, "Time-Limited Aging Analyses," contains the applicant's identification and

evaluation of time-limited aging analyses (TLAAs).

2.1.2.1 Scoplng Methodology

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

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

of the 10 CFR 54.4(a) scoping criteria. The applicant's scoping methodology, as described in

the LRA, is discussed in the sections below.

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

In LRA Section 2.1.2.1, the applicant described the general approach to scoping safety-related,

nonsafety-related, and SSCs credited with demonstrating compliance with certain regulated

events. The scoping approaches specific to each of the three 10 CFR 54.4(a) scoping criteria

are described below.

Safety-Related Criteria Pursuant to 10 CFR 54.4(a)(1). In LRA Section 2.1.2.1.1, the-applicant

described the scoping methodology required by 10 CFR 54.4 as it relates to safety-related

criteria in accordance with 10 CFR 54.4(a)(1). With respect to the safety-related criteria, the

applicant stated that the first scoping category in 10 CFR 54.4 involves safety-related SSCs.

The license renewal criteria for safety-related SSCs is consistent with the FSAR and

safety-related classification criteria.

The applicant relied on the computerized history and maintenance planning system (CHAMPS)

database and controlled drawings as the starting point for identifying systems within the scope

of the Rule. Other document sources include the FSAR, technical specifications, and

documents related to scoping for implementation of 10 CFR 50.65. Additional information

sources include docketed licensing correspondence and design information related to various

plant systems and technical position papers.

Nonsafety-Related Criteria Pursuant to 10 CFR 54.4(a)(2). In LRA Section 2.1.2.1.2, the

applicant described the scoping methodology as related to the nonsafety-related criteria in

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

stated that the staff issued its draft ISG, License Renewal Issue: Scoping of seismic 11/I Piping

Systems," dated December 3, 2001, and clarified it with its March 21, 2002, letter on the same

topic. PBNP used the draft industry guidance document on Criterion 2 (which is based on the

ISG and other applicants' responses to Criterion 2 requests for additional information (RAls)), to

develop its methodology for Criterion 2 scoping. This methodology is expected to meet the

intent of the draft ISG. With respect to scoping of SSCs pursuant to 10 CFR 54.4(a)(2), the

applicant performed a review of plant information sources, such as the current licensing basis

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(CLB) (which includes the FSAR, technical specifications and licensing commitments),

design-basis events (DBEs), design-basis documents (DBDs), Q-Iist safety classifications,

CHAMPS equipment database, and drawings.

Components meeting the scoping criterion of 10 CFR 54.4(a)(2) generally fall into three

categories.

* nonsafety-related SSCs identified in the CLB

* nonsafety-related SSCs directly connected to safety-related SSCs

* nonsafety-related SSCs that are not directly connected to safety-related SSCs

Category 1 nonsafety-related SSCs identified in the CLB include events such as high-energy

line break (HELB), intemraVexternal flooding, internal/extemal missiles, and heavy load lifting

equipment per NUREG-0612, "Control of Heavy Loads of Nuclear Power Plants." For

Category 2 nonsafety-related SSCs, directly connected safety-related SSCs, the

nonsafety-related piping and supports, up to and including the first equivalent anchor beyond

the safety/non-safety interface, are considered within the scope of license renewal pursuant to

10 CFR 54.4(a)(2). For Category 3 nonsafety-related SSCs not directly connected to

safety-related SSCs, or connected downstream of the first equivalent anchor, the applicant

concluded that the nonsafety-related SSC can be within the scope of license renewal if its

failure could prevent the performance of a safety-related function. Two options exist to

determine which nonsafety-related SSCs may be included within scope: a mitigative option and

a preventive option. The methodology for determining mitigative or preventive components is

described in LRA Section 2.1.2.1.2.

The applicant's review identified that all nonsafety-related supports for non-seismic 11/I piping

with a potential for spatial interaction with safety-related SSCs will be included within the scope

of license renewal pursuant to 10 CFR 54.4(a)(2). It further stated that these supports will be

addressed in a commodity fashion within the civil structural review area.

Concerning exposure duration, the applicant concluded that long-term exposure to conditions

resulting from a failed nonsafety-related SSC (such as leakage or spray) is not considered:

credible. The basis for this conclusion is that leakage/spray would be quickly identified by plant

personnel via walkdowns, sump-level trends, or system parameter monitors and alarms. Once

identified, appropriate corrective actions would be taken. Therefore, only nonsafety-related

SSCs whose failure could result in a failure of a safety-related SSC due to short-term exposure

would need to be considered within the scope of license renewal pursuant to

10 CFR 54.4(a)(2).

Other Scoping Pursuant to 10 CFR 54.4(a)(3). In LRA Section 2.1.2.1.3, the applicant

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

with 10 CFR 54.4(a)(3). The SSCs that used safety analyses or plant evaluations to perform an

intended function demonstrating compliance with NRC regulations for fire protection (FP),

environmental qualification (EQ), pressurized thermal shock (PTS), anticipated transients

without a scram (ATWS), and station blackout (SBO) are included within the scope of license

renewal.

The applicant used technical reports and equipment lists to provide input to the scoping process

for each of the five applicable- regulated events. The technical reports and equipment lists for

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FP include: (1) Fire Protection Evaluation Report, (2) Safety Shutdown Analysis Report,

(3) Safe Shutdown Equipment List, and (4) Fire Hazards Analysis Report.

Using the information sources described above, the components in the license renewal

database (LRDB) were reviewed to determine which are required to support the FP functions

for license renewal. The scoping of FP equipment also meets the intent of the ISG on this

subject.

For EQ, the applicant determined the electrical equipment required and identified the

equipment in the EQ master list (EQML). All electrical equipment identified on the EQML was

verified as being identified as such in the EQ fields of the computerized CHAMPS equipment

database.

The applicant determined that the PTS requirement was addressed in LRA Section 4.2.1. The

only component within the scope of license renewal for this criterion was the reactor vessel.

For mitigating ATWS events, the applicant stated that this was described in detail in FSAR

Section 7.4.1. If an ATWS were detected, the affected unit could be automatically shut down

and the auxiliary feedwater (AFW) system initiated. A quality assurance (QA) code was used in

CHAMPS to identify any components that support this event. All components associated with

the ATWS QA code are considered to be within the scope of license renewal.

For the SBO regulated event, the 13.8k VAC power system has direct connection to the onsite

gas turbine and provides one of the sources of alternating current (AC) power for recovery from

an SBO event. The scoping process determined that the circuit switchers between the unit

high-voltage station auxiliary transformers and the main switch yard bus are boundary

equipment meeting ISG-02 criteria. The 345k VAC circuit switchers are the last components in

the connection to offsite power. They are controlled by the PBNP operators and establish the

boundary for the SBO event. The components determined to be within the scope of license

renewal for supporting SBO are listed in LRA Table 2.1.2.1.3-1.

2.1.2.1.2 Documentation Sources Used for Scoping and Screening

In LRA Section 2.1.1.1, the applicant reviewed the following information sources during the

license renewal scoping and screening process:

* final safety analysis report (FSAR)

* CLB information, including technical specifications, and docketed licensing

correspondence

* safety (0-list) and augmented quality assurance (AQA) classifications in the CHAMPS

equipment database

* DBDs

* ISG applicable to scoping and screening methodology

* Maintenance Rule (MRule) summary reports and scoping information

* LRDB and boundary drawings

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

systems and structures. These functions were then compared to the scoping criteria in

10 CFR 54.4(a)(1), (2), and (3) to determine if the associated plant system or structure

performed a license renewal intended function. These sources were also used 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 2.1.2.2, the applicant described the scoping methodology for systems,

structures and commodity groups that are safety-related or nonsafety-related. The applicant

also described the scoping methodology for equipment relied upon to perform a function for any

of the five regulated events described in 10 CFR 54.4(a)(3). The scoping methodology used by

the applicant is consistent with guidance in NUREG-1800 and NEI 95-10. Existing plant

documentation used for this review included the CLB documents, controlled drawings, and the

CHAMPS database. Individual buildings/structures listed in CHAMPS as individual assets

within a system were placed into the LRDB. The CHAMPS plant systems and components

were sorted and tracked within CHAMPS using system identifiers. These identifiers support

plant needs with respect to the maintenance work and also provide definition of license renewal

system functional boundaries in a manner that is consistent with the system descriptions in the

FSAR. All of this information was entered into the LRDB. In LRA Table 2.2-1, the applicant

listed all major SSCs that are within the scope of license renewal.

PBNP system-level function information was obtained from numerous sources, including the

FSAR, docketed correspondence with the NRC, MRule documents, and DBDs.i This function

information was used to create a system function list in the LRDB. CLB references were added

to each system function. In LRA Section 2.1.2.3, the applicant described the application of all

three 10 CFR 54.4 criteria used to generate the list of SSCs that were considered within the

scope of license renewal. Some components within the system or structure are not within the

scope of license renewal because not all of their components support the system's intended

function(s). Therefore, where possible, boundaries are depicted on drawings with color

(magenta) overlays to indicate those SSCs within the scope of license renewal.

2.1.2.1.4 Component Level Scoping

After the applicant Identified the Intended functions of systems or structures that were within the

scope of license renewal, a review was performed to determine which components of each

in-scope system and structure support license renewal intended functions. The components

that support intended functions were considered within the scope of license renewal and

screened to determine if an aging management review (AMR) was required. During this stage

of the scoping methodology, the applicant considered three component classifications:

(1) mechanical, (2) civil and structural, and (3) electrical and instrumentation & controls (I&C).

The scoping methodology for each of these component classifications is discussed below.

Mechanical Component ScoDina. In LRA Section, 2.1.2.4, the applicant discussed the methods

used to identify components in a system or structure that are within the scope of license

renewal. The license renewal system boundaries were initially based on the associated

CHAMPS system boundaries. CHAMPS component data were used with and compared to the

green line drawings (GLDs) to ensure that system boundaries and flow paths were accurately

identified within the LRDB. Some components within a system were moved to commodity

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groups. For example, system pipe supports were moved to the component supports

commodity group (CSUP). Within most systems, new assets or subcomponents were created

within the LRDB in order to ensure that all necessary assets/components could be accurately

described and addressed in the license renewal process. Some of these decisions were based

on knowing what would be needed for screening and AMR. Examples of new subcomponents

or assets include:

* manifold subcomponents for instruments

* bolting for carbon/low-alloy steel and stainless steel

* heat exchanger subcomponents

* piping assets created to identify combinations of materiaVenvironments

* carbon steel components that come in contact with boric acid

In some instances, components were reviewed as part of another interfacing system in order to

more accurately portray system functional boundaries or to streamline the license renewal

process. Additionally, in some cases, all in-scope components for a single system were

reviewed as part of another interfacing system. An example of this is the plant sampling

system (PSS) where only a few of the components were determined to be within the scope of

license renewal. These components included three reactor coolant system (RCS) sample lines

which are part of PBNP's Class 1 piping boundary. A few remaining in-scope components were

found in associated interfacing systems such as the residual heat removal (RHR) sample line

and valves, chemical and volume control system (CVCS) sample line and valves, and

component cooling (CC) supplied heat exchanger. All in-scope PSS component reviews were

completed with interfacing systems. These PSS components were described in the systems for

which the component reviews were completed.

CiviVStructural Component Scopina. In LRA Section 2.1.2.5, the applicant described systems,

structures and commodity groups under the purview of the civil/structural discipline. This

includes plant structures; crane, hoist, and lifting device systems; the CSUP; and the fire barrier

commodity group. The information sources included the FSAR, CLB documentation, DBDs,

training material, CHAMPS database, drawings, specifications, codes/standards, design

changes, plant procedures, and walkdowns of plant buildings. The applicable license renewal

information was integrated into the LRDB.

The crane, hoist, and lifting device systems are associated with the civil/structural discipline.

This system includes the containment polar cranes, the auxiliary building main crane and the

turbine building main crane. All portions of the fuel handling system that were determined to be

within the scope of license renewal were moved to the spent fuel cooling system, the

containment Units 1 and 2 building structure, or the primary auxiliary building (PAB) structure.

LRA Table 2.2-1 provides a list of civilstructural in-scope and out-of-scope systems, structures,

and commodity groups.

The evaluation for a structure that was determined to not be within the scope of license renewal

was documented in the LRDB either individually, by the structure's name, or grouped under the

miscellaneous "Nonsafety-related Building and Structures System." Additionally, a structure's

evaluation was individually documented when the structure's attributes, such as its functions or

location, warranted an in-depth explanation.

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Electrical and l&C Component Sconin_. In LRA Section 2.1.2.6, the applicant described the

electrical and instrumentation & control (I&C) systems' applicability to license renewal

requirements. These systems are identified at specific voltage levels (i.e., 13.8k VAC,

480 VAC, 125 VDC) or within functional performance related systems (e.g., radiation

monitoring, engineered safety feature actuation, reactor protection) for electrical power or l&C,

respectively. Since some electrical components are contained in generic systems in the

CHAMPS database, these components were identified and transferred within the LRDB into

their specific electrical systems.

During the scoping process, an evaluation boundary was established for each system or

commodity group in order to identify the functions associated with the system or commodity

being evaluated. For power cables to equipment (e.g., motors, valves), the system interfaces

were assumed to be at the protective device (breaker or fuse) and the cable associated with the

equipment. For interfaces between systems at different voltage levels, the interconnecting

transformers were the interface and they were included in the system as identified in CHAMPS

and the system drawings.

Commodity Groups Scooing. In LRA Section 2.1.2.2, the applicant stated that commodity

groups were formed when component evaluations were better performed by component type

than as a system or structure. Commodity groups were formed from components that were

constructed from similar materials, exposed to similar environments, and performed similar

intended functions regardless of the specific system or structure to which they are assigned.

Each commodity group was evaluated as a separate, individual system. One exception to this

was when the only in-scope portion of the system consisted of components that would receive a

commodity group evaluation (e.g., fire barrier, equipment supports). In this case, the applicant

stated that it was acceptable to identify the system and structure as not being within the scope

of license renewal; however, the basis for that determination is clearly identified. For example,

the non-essential ventilation system contains components that act as fire barriers (fire

dampers).

In LRA Section 2.1.2.4, the applicant discussed some components within a mechanical system

that were moved to commodity groups. For example, system pipe supports were moved to the

CSUP.

In LRA Section 2.1.2.5, the applicant discussed two civilstructural commodity groups which

include component supports and fire barriers. The CSUP includes component and equipment

supports, fasteners and anchorages used with the support, pipe restraints, electrical raceways,

and electrical enclosures. The fire barrier commodity group includes fire wraps, fire penetration

seals, fire damper housings, and cable tray fire stops. Fire doors and structural walls that also

serve as fire barriers were not included with this commodity group since they were evaluated

within the associated structure.

In LRA Section 2.1.2.6, for electrical and l&C commodity groups, the types of components that

defined the commodity were determined to identify their appropriate scoping criteria and

system-level functions. Junction boxes, panels, and cabinets were identified in the "PANELN

commodity and electrical penetration assemblies in the "EPA" commodity in the CHAMPS

equipment database. The individual cables for the cable commodity are not in CHAMPS and

were tracked using the cable and raceway data system (CARDS). Information regarding

systems and commodities was identified through review of the FSAR, CHAMPS, CLB,

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documentation, DBDs, plant databases and documents, procedures, drawings, specifications,

codes/standards, and system walkdowns.

2.12.2 Screening Methodology

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

implemented a process for determining which structures and components would be subject to

an AMR in accordance with the requirements of 10 CFR 54.21 (a)(1). In LRA Section 2.1.3, the

applicant discussed these screening activities as related to the SCs that are within the scope of

license renewal. The screening process evaluated these in-scope SSCs to determine which

ones were long-lived, passive and, therefore, subject to an AMR. LRA Sections 2.3, 2.4,

and 2.5, provide the results of the process used to identify the SCs that are subject to an AMR.

This methodology included:

* active/passive determinations

* screening of stored equipment

* screening of thermal insulation

* identification of short-lived components and consumables

* identification of component intended functions

2.1.2.2.1 Mechanical Component Screening

Following system-level scoping, the applicant performed screening to identify SCs that are

within the scope of license renewal. The screening process evaluated these in-scope SSCs to

determine which were long-lived, passive and, therefore, subject to an AMR. The intended

functions, developed using the documentation sources discussed in SER Section 2.1.2.1.2,

were used as input to the screening process to identify the passive components within the

scope of license renewal. Passive component determinations were made in accordance with

10 CFR 54.21(a)(1)(i) and NEI 95-10.

Scoping also identified the evaluation boundaries for the in-scope systems or structures. The

evaluation boundaries identify which components within an in-scope system or structure are

within the scope of license renewal. The evaluation boundaries are depicted on the license

renewal boundary drawings for mechanical systems. Not all components within an in-scope

system or structure were determined to be within the scope of license renewal. The screening

process took the in-scope components and performed an active/passive evaluation and a

long-lived evaluation. The component function of those components subject to an AMR was

also documented. The screening process was performed in accordance with LRPP 2-1,

uScoping and Screening for License Renewal." The screening process evaluations were

performed and documented in the license renewal process management system (LRPMS)

database.

The results of the major components screening for mechanical systems are presented in LRA

Sections 2.3.1, 2.3.2, 2.3.3, and 2.3.4.

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2.1.2.2.2 CivilStructural Component Screening

The civil/structural engineering discipline was responsible for performing the screening

evaluations on the in-scope structures, crane, hoist, and lifting device systems, as well as the

component supports and fire barrier groups. The boundaries for in-scope systems, structures,

and commodity groups were defined to determine the components that would need screening.

Additionally, all structural components within the evaluation boundaries, with the exception of

snubbers that supported a component-level intended function, were assumed to be long-lived,

passive, and subject to an AMR.

The individual structure components are represented by generic components that identify the

materials of construction and environmental exposure. Materials were placed in groups that

would experience the same type of aging mechanism and effects and would, therefore, need

the same type of aging management. Evaluation boundaries for the structures and

components determined where substructures were assigned for evaluation and dictated the

type of generic components that were to be a part of a structure or commodity. The screening

process confirmed the boundary and generic component identification process and verified that

all components were evaluated.

The screening process results were provided in database output reports sorted by system,

structure, and commodity group. These reports were independently prepared, reviewed, and

approved.

2.1.2.2.3 Electrical/I&C Component Screening

The applicant performed screening to identify those electrical and l&C components that were

within the scope of license renewal. The screening process evaluated those in-scope

components to determine which ones were passive, long-lived and, therefore, subject to an

AMR. The applicant addressed the following electrical and l&C systems and commodity groups

in LRA Section 2.5:

* 120 VAC vital instrument power system

* 125 VDC power system

* 4160 VAC power system

* 480 VAC power system

* control rod drive and indication and nuclear process instrumentation system

* miscellaneous AC power and lighting system

* offsite power system

* reactor protection system, including anticipated transient without scram

* engineered safety features actuation system

* plant communications system

* 13.8k VAC power system

* radiation monitoring system

The screening results are in the individual system scoping and screening reports. Boundary

definitions excluded nonsafety-related electrical components whose failure did not prevent a

safety-related system from performing its safety-related function and components that did not

support a license renewal required regulated event. When the remaining components were

examined and screened for active or passive functions, the majority of the components were

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determined to be active in accordance with NEI 95-1 0, Appendix B and screened out of the

scope of license renewal. The LRA categorizes the remaining components into the following

passive commodities:

* electrical portions of non-EQ electrical and l&C penetration assemblies

* phase bus

* -switchyard bus

* transmission conductors

* high-voltage insulators

* uninsulated ground conductors

* panels and junction boxes-

* non-EQ power, instrumentation, control and communication insulated cables and

connections

The LRA uses the scoping and screening process of the integrated plant assessment as

required by 10 CFR 54.21 (a) and applies it to PBNP electrical power, communications, and I&C

systems. The applicant developed the electrical and l&C component screening methodology

and results using procedure guidance in LRPP 2-1, Revision 4, "Scoping and Screening for

License Renewal," and LR-TR-508, Revision 1, "Integrated Plant Assessment Methodology

Report." The screening methodology and results are documented in LRA Section 2.5.

2.1.3 Staff Evaluation

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

guidance contained in "Standard Review Plan for Review of License Renewal Applications for

Nuclear Power Plants" (NUREG-1 800), Section 2.1, "Scoping and Screening Methodology."

The acceptance criteria for the scoping and screening methodology review are based on the

following regulations:

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

Rule

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

determined to be within the scope of the Rule

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

identify plant structures and components subject to an AMR

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

the activities described in the following LRA sections using the guidance contained in

NUREG-1 800:

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

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

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

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Structures;" and Section 2.5, uScoping and Screening Results: Electrical," to verify that

the applicant described a process for determining structural, mechanical, and electrical

components 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 onsite audit during the

week of June 21, 2004. The focus of the audit was to verify 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 staff reviewed implementation procedures and engineering reports which describe

the scoping and screening methodology implemented by the applicant. The staff also

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

staff further reviewed a sample of system scoping and screening result reports for the main

steam and emergency power systems to ensure the methodology outlined in the administrative

controls was appropriately implemented and the results are consistent with the CLB.

2.1.3.1 Scoplng Methodology

The staff reviewed PBNP implementation procedures, technical basis documents and reports,

engineering reports, and license renewal project procedures (LRPP) which describe the

scoping and screening methodology implemented by the applicant. The staff found that the

scoping and screening methodology instructions were consistent with LRA Section 2.1 and

were of sufficient detail to provide the applicant with clear guidance on the scoping and

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

implementing procedures, the staff reviewed supplemental design information including system

functional descriptions, system drawings, and selected licensing documentation, which were

relied upon by the applicant during the scoping and screening phases of the review. The staff

found these design documentation sources useful to ensure that the initial scope of SSCs

identified by the applicant are consistent with the Units 1 and 2 CLBs. The staff also reviewed

the scoping process to verify that the applicant's methodology is consistent with NUREG-1 800

and other documented staff positions and adequately identified SSCs within the scope of

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

_. . ,. * . __. ._ . .
The applicant relied on CHAMPS and controlled drawings as the starting point for identifying

systems within the scope of the Rule. Other document sources included License Renewal

Project Management System (LRPMS), the FSAR, technical specifications, documents related

to scoping for implementation of 10 CFR 50.65. Additional information sources included

docketed licensing correspondence, and design information related to various plant systems

and technical position papers.

PBNP License Renewal Project Document LR-TR-508, Revision 1, "Integrated Plant

Assessment Methodology Report," provides a detailed explanation of the decision-making

criteria used to determine and document the results of the PBNP license renewal process. The

document describes the scoping process for the entire plant in terms of major systems and

structures, and identifies their system-level functions. The determination of intended functions

for systems is based on the design and licensing basis documentation. The staff review of the

main steam and emergency power systems verified that even if only a portion of a system,

structure, or commodity fulfilled a scoping criterion, it was identified as within the scope of

license renewal.

The staff verified that the 10 CFR 54.4 criteria for safety-related SSCs is consistent with

PBNP's safety-related classification criteria and with the FSAR. Additionally, the staff verified

that SSCs that had a safety-related designation in the CHAMPS (Q-list) system for main steam

and emergency power were considered as within the scope of license renewal. The staff also

reviewed a sample of the 10 CFR 54.4(a)(1) scoping results from the LRDB and held

discussions with the applicant's technical staff regarding safety-related criteria determinations.

Conclusion. The staff reviewed the applicant's methodology for identifying systems and

structures meeting the scoping criteria of 10 CFR 54.4(a)(1). The staff also reviewed a sample

of the LRDB 10 CFR 54.4(a)(1) scoping results, 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 staff verified that the applicant identified and

used pertinent engineering and licensing information in order to determine the SSCs required to

be within scope in accordance with the 10 CFR 54.4(a)(1) criteria. On the basis of this review,

the staff concluded that the applicant's methodology for identifying systems and structures

meeting the scoping criteria of 10 CFR 54.4(a)(1) is adequate.

Application of the Scoping Criteria in 10 CFR 54.4(a)(2). Pursuant to 10 CFR 54.4(a)(2), the

applicant must consider all nonsafety-related SSCs whose failure could prevent satisfactory

accomplishment of any of the functions identified in paragraphs 10 CFR 54.4(a)(1)(i), (ii), and

(iii), to be within the scope of license renewal. By letters dated December 3, 2001, and

March 15, 2002, the NRC issued a staff position to NEI which provides staff expectations for

determining which SSCs meet the 10 CFR 54.4(a)(2) criterion.

The December 3,2001, letter (ML01 3380013) provides specific examples of operating

experience that identified pipe failure events (summarized in NRC Information Notice (IN)

2001-09, "Main Feedwater System Degradation in Safety-Related ASME Code Class 2 Piping

Inside the Containment of a Pressurized Water Reactor") and the approaches the NRC

considers acceptable for determining which piping systems should be included as within scope,

based on the 10 CFR 54.4(a)(2) criterion. The March 15, 2002, letter (ML020770026) further

describes the staff's expectations for the evaluation of non-piping SSCs to determine which

additional nonsafety-related SSCs are within the scope of license renewal. The position states

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that applicants should not consider hypothetical failures, but rather should base their evaluation

on the plant's CLB, engineering judgment and analyses, and relevant operating experience.

The paper further describes operating experience as all documented plant-specific and

industry-wide experience that can be used to determine if a failure is possible. Documentation

includes NRC generic communications and event reports, plant-specific condition reports,

industry reports such as significant operating event reports (SOERs), and engineering

evaluations.

The applicant's methodology for performing 10 CFR 54.4(a)(2) scoping of nonsafety-related

SSCs is documented in PBNP License Renewal Process Document LR-TR-508, "Integrated

Plant Assessment Methodology Report," and LR-TR-514, "Criterion 2 Scoping Methodology and

Results." These documents describe the current regulations 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. In

keeping with the NEI draft position on nonsafety-related SSCs that could adversely affect

safety-related SSCs, the applicant developed guidance for interpreting and applying the

10 CFR 54.4(a)(2) criteria, including nonsafety-related SSCs spatially oriented near

safety-related components, seismic 11/I components, nonsafety-related piping connected to

safety-related piping, intemal/extemal flooding, internal/external missiles, HELB, and heavy

load lifting equipment.

Nonsafety-related SSCs identified in the CLB included HELBs, internal/external flooding,

intemaVextemal missiles, and heavy load lifting equipment. For systems and components

containing air/gas (non-liquids), the applicant identified neither any spray or leakage concerns

nor any industry operating experience indicating a loss of safety function for systems containing

air/gas. Also, nonsafety-related non-liquid-containing components are not within scope for

10 CFR 54.4(a)(2) unless related to a seismic 11/I concern or nonsafety-related SSCs connected

to safety-related SSCs. For systems containing liquids or steam, the applicant considered a

"high energy" state if conditions exceeded 275 psig or 200 OF.

For nonsafety-related SSCs directly connected to safety-related SSCs, the applicant concluded

that the nonsafety-related piping and supports, up to and including the first equivalent anchor

beyond the safety/non-safety interface, are within the scope of license renewal pursuant to

10 CFR 54.4(a)(2). The piping segments are not uniquely identified on the license renewal

boundary drawings, but the applicable aging effects on these segments are managed along

with the adjoining piping.

For the nonsafety-related SSCs not directly connected to safety-related SSCs, or that are

connected downstream of the first equivalent anchor, the nonsafety-related SSCs may be

considered in-scope if their failure could prevent the performance of the system safety function

for which the safety-related SSC is required. To determine which nonsafety-related SSC is

in-scope, the applicant used either the mitigative or the preventive approach. A mitigative

approach means that the effects of failures of a nonsafety-related SSC are mitigated by other

SSCs. If the mitigative approach is used, the mitigative features are included within the scope

of license renewal pursuant 10 CFR 54.4(a)(2) and the non-safety system can be excluded

from the scope of license renewal. These mitigative factors are typically associated with the

structure and are addressed in the civilstructural review.

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If the mitigative features are not installed, or cannot be shown to adequately protect the

safety-related SSCs, then the preventive option is used. It is a concern that age-related

degradation of nonsafety-related SSCs could lead to interactions with safety-related SSCs that

were not previously considered. The applicant provided guidance for system/component

applicability for system components containing air/gas (non-liquid), high-energy systems,

low/moderate energy systems, and piping supports.

As part of the methodology for determining mitigative or preventive components, the applicant

determined and identified vulnerable safety-related equipment housed in plant structures. A

safety-related SSC was considered vulnerable if there were nonsafety-related SSCs in the

vicinity whose failure could prevent accomplishment of the safety-related SSC's safety function.

Consideration for exposure duration, fail-safe components, and components qualified/designed

for the' environment was also used in determining vulnerable safety-related equipment. The

applicant identified the safety-related switchgear, batteries, pump motors, panels, and complex

equipment (i.e., diesel generators) as the only vulnerable equipment.

The staff's review of LRA Section 2.1 identified areas in which additional information was

necessary to complete the screening and methodology evaluation. The applicant responded to

the staff's RAls as discussed below.

RAI 2.1-1. The LRA and page 13 of LR-TR-514 did not adequately define short-term exposure

duration for low and moderate energy piping failures covered under 10 CFR 54.4(a)(2) that

could affect safety-related electrical equipment under the scope of 10 CFR 54.4(a)(1).

Specifically, the staff found that some safety-related electrical equipment may exist in the

turbine building or other parts of the plant and may be subject to harsh environments from low

or moderate energy pipe breaks but are not environmentally qualified. Since this equipment

may not be environmentally qualified, it could fail due to 10 CFR 54.4(a)(2) piping failures.

In RAI 2.1-1, dated November 16, 2004, the staff requested the applicant to adequately define

short-term exposure duration for low and moderate energy piping failures and how it relates to

scoping and screening of 10 CFR 54.4(a)(2) piping that could cause these types of failures.

In its response, dated January 31, 2005, the applicant stated that for the purpose of license

renewal, the term "exposure duration" will be removed from LRA Section 2.1.2.1.2 and provide

a technical justification for why the safety-related SSCs are capable of withstanding the effects

of spray and leakage. The applicant also stated that it will include a technical justification in the

LRA annual update under the section "Components Qualified/Designed for Environment."

During a meeting on February 15, 2005, the staff indicated and the applicant agreed, that this

response required further clarification. In its response, a clarification letter dated

March 15, 2005, the applicant committed to provide details of the 10 CFR 54.4(a)(2) scoping

methodology changes, including specific exceptions, and how these will impact the LRA. The

applicant committed to provide the staff this information by the end of April 2005. This was

identified as confirmatory item (Cl) 2.1-1.

In its response to Cl 2.1-1, by letter dated April 29, 2005, the applicant provided additional

information regarding its scoping methodology changes. This revised methodology invokes a

plant spaces approach that assumes a spatial interaction can occur if safety-related and

nonsafety-related systems or components (SCs) are located within the same space. For

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purposes of the process, a space Is defined by the room in which the safety-related and

nonsafety-related components are located. This revised methodology evaluates the effect of

sprays and leaks on mechanical and electrical safety-related SCs, with no limitation on duration

of the sprays/leaks. The applicant thus considers all liquid- or steam-bearing nonsafety-related

SCs to be within the scope of license renewal pursuant to 10 CFR 54.4(a)(2), provided that the

nonsafety-related SCs are located in the same space as a safety-related SC and in such

proximity that spray or leakage from the nonsafety-related SC could contact the safety-related

SC.

Based on this revised 10 CFR 54.4(a)(2) methodology, the applicant re-evaluated SCs to

identify configurations where the failure of nonsafety-related SCs could result in the loss of an

intended function of the safety-related SCs within the space and, therefore, be considered

within the scope of license renewal. This re-evaluation led to the expansion of scope for some

systems, to the addition of component groups and line items to several tables in the LRA, and

to the addition of new tables for the plant sampling system. The plant sampling system had

already been included within the scope of license renewal and described in the LRA, but the

previously identified In-scope SCs were addressed within other systems, and new tables were

required. The applicant noted that the results of the review using the new methodology

discovered no new aging effects/mechanisms and; therefore, the aging management program

assignments are consistent with those previously identified in the LRA.

The applicant's re-evaluation using the new scoping methodology also identified a number of

configurations where the failure of nonsafety-related SCs would not result in the loss of

intended functions of safety-related SCs located in the same space. These configurations were

identified as exceptions in the April 29, 2005, letter. The basis was clearly documented for

each of the identified exceptions; however, the staff requested some clarifications. By letter,

dated July 19, 2005, the applicant responded to the staff's concerns. Further discussion on this

subject is documented in SER Section 2.3.

Based on the above discussion, the staff found the applicant's response to RAI 2.1-1

acceptable. The staff's concern is resolved; therefore, Cl 2.1-1 is closed.

RAI 2.1-2. LRA Section 2.1.2.1.2, page 2-19, states that "For NSR SSCs directly connected to

safety-related SSCs (typically piping systems), the NSR piping and supports, up to and

including the first equivalent anchor beyond the safety/non-safety interface, are within the scope

of license renewal pursuant to 10 CFR 54.4(a)(2). Although these piping segments are not

uniquely identified on the license renewal boundary drawing, applicable aging effects on these

piping segments are managed along with the adjoining SR piping."

In RAI 2.1-2, dated November 16, 2004, the staff requested the applicant to describe and

define what is meant by the first equivalent anchor and how it relates to the scoping and

screening of 10 CFR 54.4(a)(2) nonsafety-related piping and supports.

In its response, dated January 31, 2005, the applicant stated that PBNP has included all the

connected nonsafety-related piping and supports, up to and including the first equivalent anchor

beyond the safety/non-safety interface, within the scope of license renewal pursuant to

10 CFR 54.4(a)(2). The applicant also stated that nonsafety-related pipe supports will be

managed in a commodity "spaces" approach wherein all supports in the areas of concern are

included within the scope of license renewal. The connected nonsafety-related piping will be

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managed using the same programs that manage the safety-related piping. This process

conforms to the requirements for the nonsafety-related SSCs connected to safety-related SSCs

pursuant to 10 CFR 54.4(a)(2) and draft ISG-09. This was identified as confirmatory item

(Cl) 2.1-2.

Further in its response, the applicant described what is meant by first equivalent anchor and

also described the analysis techniques used for evaluating the piping stress analysis

boundaries for identifying the first equivalent anchor point for scoping purposes.

Based on the above discussion, the staff found the applicant's response to RAI 2.1-2

acceptable. The staff's concern is resolved; therefore, Cl 2.1-2 is closed.

RAI 2.1-3. LRA Section 2.1.2.1.2, pages 2-20 and 2-21, states that "AII nonsafety-related

supports for non-seismic or seismic 11/l piping systems with a potential for spatial interaction

with safety-related SSC, will be included within the scope of license renewal pursuant to

10 CFR 54.4(a)(2). These supports will be addressed in a commodity fashion, within the

civil/structural area review. As long as the effects of aging on the supports for these piping

systems are managed, falling of piping sections, except for flow-accelerated corrosion (FAC)

failures, is not considered credible. The piping section itself would not be in-scope for

10 CFR 54.4(a)(2) due to physical impact hazard (although the leakage or spray may still

apply)."

In RAI 2.1-3, dated November 16, 2004, the staff requested the applicant to describe how the

falling of piping sections is not considered credible and why the piping section itself would not

be in-scope for 10 CFR 54.4(a)(2) due to physical impact hazard. The staff also requested the

applicant to describe how the management of FAC relates to the scoping and screening of

10 CFR 54.4(a)(2) seismic 11/I piping systems that could cause these types of failures.

In its response, dated January 31, 2005, the applicant stated that for the purpose of license

renewal Criterion 2 scoping, nonsafety-related pipe segments have essentially three potential

failure modes: (1) for nonsafety-related low or moderate energy piping, all nonsafety-related

supports with any potential spatial interaction with safety-related SSCs will be included within

the scope of license renewal and age managed. Managing of the nonsafety-related supports

will ensure that these supports remain intact and will not fall on safety-related components,

(2) for nonsafety-related high energy piping segments, a FAC failure for components in

proximity of safety-related components would be considered within the scope of license renewal

as long as a FAC failure in that line and impact on safety-related components is considered

credible, and (3) for nonsafety-related piping (either high, moderate or low energy) that could

fail and result in leakage or spray on nearby safety-related components or high energy piping

that has the potential of creating harsh environment (high humidity and high temperature)

effects on vulnerable safety-related equipment, are considered within the scope of license

renewal.

During a meeting on February 15,2005, the staff indicated and the applicant agreed, that this

response required further clarification. The applicant stated that the phrase "as long as the

FAC failure is considered credible" will be removed from the LRA. This was identified as

confirmatory item (Cl) 2.1-3.

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In its response, a clarification letter dated March 15, 2005; the applicant removed the phrase

"as long as a FAC failure in that line and impact on safety-related components is considered

credible" from its original response to RAI 2.1-3.

Based on the above discussion, the staff found the applicant's response to RAI 2.1-3

acceptable. The staff's concern is resolved; therefore, Cl 2.1-3 is closed.

Conclusion. The staff reviewed the applicant's methodology for identifying systems and

structures meeting the scoping criteria of 10 CFR 54.4(a)(2). The staff also reviewed a sample

of the license renewal database 10 CFR 54.4(a)(2) scoping results, 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 staff verified that the applicant

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

SSCs required to be in-scope in accordance with the 10 CFR 54.4(a)(2) criteria. On the basis

of this review, and review of the applicant's revised scoping process, the staff concluded that

the applicant's methodology for identifying systems and structures meeting the scoping criteria

of 10 CFR 54.4(a)(2) is adequate.

ADplication of the Scoping Criteria in 10 CFR 54.4(a)(3). Paragraph (a)(3) of 10 CFR 54.4

requires, in part, that the applicant consider all SSCs relied on in safety analyses or plant

evaluations to perform a function that demonstrates compliance with the NRC's regulations for

FP, EQ, PTS, ATWS, and SBO, to be within the scope of license renewal.

The staff reviewed technical report LR-TR-509, Revision 0, "Regulated Events Functional

Requirements Report," which described the methodology used to determine how SSCs support

the regulated events for license renewal. The methodology considers the following:

* Fire Protection (10 CFR 50.48) - Systems and functions of those systems relied upon to

support the Fire Protection Program at PBNP are described in the Fire Hazard Analysis

Report (FHAR) and/or the Safe Shutdown Analysis Report (SSAR). The applicant

performed a detailed review of these system descriptions to identify specific system

requirements.

* Environmental Qualification (10 CFR 50.49) - The applicant stated that the only system

functional requirement for EQ is to maintain the function of electrical components. The

specific electrical equipment requirement for the EQ program was identified in the

Equipment Qualification Master List (EQML). Each system containing equipment from

the EQML was identified with an EQ functional requirement. EQ summary sheets;

(EQSS) were also prepared and include an evaluation of the worst-case environmental

parameters the equipment may be exposed to and the environmental parameters the

equipment is qualified to operate in.

* Pressurized Thermal Shock (10 CFR 50.61) - The event programmatic requirements for

operation and inspection of equipment to minimize and monitor pressurized thermal

transients to pressurized vessels are described in the License Renewal Aging

Management Program documents. The only system relied on for PTS is the reactor

vessel.

* Anticipated Transient Without Scram (10 CFR 50.62) - The systems and functions of the

systems relied upon to support the ATWS event were described in FSAR Section 7.4.

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The event of concern was a loss of feedwater without a unit trip. A review of the

components in CHAMPS database was performed to identify components that

supported the event.

* Station Blackout (10 CFR 50.63) - FSAR Appendix A.1 provides the licensing criteria

that comprise the CLB for SBO. The SBO rule at PBNP is satisfied by providing an

alternate AC source in the form of a gas turbine generator (GTG) capable of supplying

either or both units. The components identified in the CHAMPS database were

reviewed to determine which were required to support the coping duration and

subsequent starting and loading of the GTG for an SBO event.

As part of the review of the applicant's scoping methodology, the staff reviewed a sample of the

license renewal database 10 CFR 54.4(a)(3) scoping results, 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.

Conclusion. The staff reviewed the applicant's methodology for identifying systems and

structures meeting the scoping criteria of 10 CFR 54.4(a)(3). The staff also reviewed a sample

of the license renewal database 10 CFR 54.4(a)(3) scoping results, 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 staff verified that the applicant

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

SSCs required to be in-scope in accordance with the 10 CFR 54.4(a)(3) criteria. On the basis

of this sample review, the staff concluded that the applicant's methodology for identifying

systems and structures meeting the scoping criteria of 10 CFR 54.4(a)(3) is adequate.

2.1.3.1.2 Plant Level Scoping of Systems and Structures

The applicant's methodology for performing the scoping of systems and structures in

accordance with 10 CFR 54.4(a) is documented in PBNP License Renewal Project Document

LR-TR-508, Revision 1, "Integrated Plant Assessment Methodology Report." The approach

used by the applicant for system and structure scoping is consistent with the methodology

described in LRA Sections 2.1.1, 2.1.2.4, 2.1.2.5, and 2.1.2.6. Specifically, the technical report

states that 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 and structures included the FSAR, DBDs, system descriptions,

CHAMPS database, MRule information, and plant drawings. After the preliminary identification

of potential in-scope systems/structures, the screening process reviewed each potential

in-scope system/structure in detail to confirm the preliminary determinations made during the

scoping process. The applicant first identified all plant systems using the CLB, CHAMPS, and

plant drawings and then evaluated them against the scoping criteria of 10 CFR 54.4(a)(1), (2),

and (3) to identify those systems that perform one or more intended functions. A system or

structure was presumed to be within the scope of license renewal if it performed one or more

safety-related functions or met other scoping criteria per the Rule, as determined by CLB review

and walkdown by engineering personnel. Identified system or structure functions were then

compared to a list of scoping criteria to determine the functions which met the scoping criteria

of 10 CFR 54.4(a). The applicant documented the results of the scoping process in LR-TR-508

Attachments 2 through 7, which include descriptions, 10 CFR 54.4(a) scoping criteria met by

the system or structure, and references. The staff reviewed a sampling of the applicant's

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scoping documentation and concluded that they contained an appropriate level of detail to

document the scoping process.

Conclusion. The staff reviewed the applicant's methodology for identifying systems and

structures meeting plant-level scoping criteria as defined in the Rule. The staff also reviewed a

sample of the scoping methodology implementation procedures and results and discussed the

methodology and results with the applicant. The staff verified that the applicant identified and

used pertinent engineering and licensing information in order to determine the SSCs required to'

be in-scope in accordance with the 10 CFR 54.4(a) criteria. On the basis of this sample review,

the staff concluded that the applicant's methodology for identifying plant level systems and

structures meeting the scoping criteria of 10 CFR 54.4(a) is adequate.

2.1.3.1.3 Component Level Scoping

The staff reviewed license renewal procedures LRPP 1-1, Revision 0, "License Renewal Project

Procedure," and LRPP 2-1, Revision 2, uScoping and Screening for License Renewal." In these

and other procedures referenced in this section, the applicant identified the intended functions

of SSCs within the scope of license renewal and performed a review to determine which

components of each in-scope system and structure supported license renewal intended

functions. The components that support intended functions were considered within the scope

of license renewal and screened to determine if an AMR was required. During this stage of the

scoping methodology, the applicant considered three component classifications: mechanical,

civil and structural, and electrical. The scoping methodology for each of these component

classifications is discussed below.

Mechanical Scopina. LRA Section 2.1.2.4 describes the methods used to identify mechanical

components in a system or structure that are within the scope of license renewal. All of the

mechanical systems contain some electrical and structural components. The license renewal

system boundaries were initially based on the associated CHAMPS system boundaries. The

plant systems were identified within CHAMPS using system identifiers. Different system

boundaries are defined for license renewal, some containing multiple CHAMPS systems.

License renewal systems account for and contain all of the CHAMPS systems and do so in a

manner that is consistent with the system descriptions in the FSAR.

The staff reviewed the mechanical scoping methodology as described in Section 2.3 of PBNP

License Renewal Process Document, LR-TR-508, Integrated Plant Assessment Methodology,

Revision 1, dated January 26, 2004. The mechanical scoping methodology describes four

scoping methods used to complete mechanical system component scoping:

(1) discipline-specific scoping process, (2) system/commodity groups, (3) evaluation

boundaries, and (4) system-level functions.

The discipline-specific scoping process describes how the CHAMPS component data were

used with and compared to the plant drawings to ensure that system boundaries and flow paths

are accurately identified in the LRDB. Components were moved to commodity groups, as

applicable. Within most systems, new assets or subcomponents were created in the LRDB in

order to ensure that all components were adequately addressed within the license renewal

process. System/commodity groups examples used in mechanical scoping are described

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above in SER Section 2.1.2.1.4. All new subcomponents or assets were assigned a license

renewal scoping criterion equal to their parent asset's criterion.

For evaluation boundaries, the applicant described instances where components were reviewed

as part of another interfacing system in order to describe the system function boundaries or to

streamline the license renewal process.

System-level functions where components were reassigned to commodity groups or generic

systems are also described. The system functions associated with those components would

also move to the new commodity system and that function would be deleted from the original

system. Using this method, some systems were de-populated of in-scope functions and,

therefore, shown to be out-of-scope.

The main and auxiliary steam system transport the steam produced in the steam generator to

the main turbine for the production of electricity. The system also provides heat removal from

the RCS during normal, accident, and post-accident conditions. In addition, it provides steam to

the turbine-driven auxiliary feedwater pumps.

The main steam system contains seven intended functions that are within the scope of license

renewal. These intended functions include:

* performs its primary design system function as detecting, initiating, and actuating

automatic safety functions

* provides emergency heat removal from the RCS using secondary heat removal

capability

* provides a primary containment boundary

* nonsafety-related SSCs whose failure could prevent satisfactory accomplishment of a

safety-related function

* SSCs relied upon in safety analyses or plant evaluations to perform a function that

demonstrates compliance with the regulations for fire protection (10 CFR 50.48)

* SSCs relied upon in safety analyses or plant evaluations to perform a function that

demonstrates compliance with the regulations for environmental qualification

(10 CFR 50.49)

* SSCs relied upon in safety analyses or plant evaluations to perform a function that

demonstrates compliance with the regulations for station blackout (10 CFR 50.63).

The staff reviewed and evaluated documents describing these scoping methods for the main

steam system. The documents reviewed included the main steam system DBDs, CLB, and

license renewal implementation procedures. A complete list of documents reviewed is

contained in Appendix B of this report.

Conclusion. The staff reviewed the applicant's methodology for identifying systems and

structures meeting mechanical scoping criteria as defined in the Rule. The staff also reviewed

a sample of the scoping methodology implementation procedures and discussed the

methodology and results with the applicant. The staff verified that the applicant identified and

used pertinent engineering and licensing information in order to determine the SSCs required to

2-20
be within the scope of license renewal in accordance with the 10 CFR 54.4(a) criteria. On the

basis of this sample review, the staff concluded that the applicant's methodology for identifying

mechanical systems and structures meeting the scoping criteria of 10 CFR 54.4(a) is adequate.

CiviVStructural Sconina. The applicant's methodology for performing the scoping of systems

and structures in accordance with 10 CFR 54.4(a) was documented in license renewal

Technical Report LR-TR-508, Revision 1, integrated Plant Methodology Assessment Report,"

and LRA Section 2.4. The approach used by the applicant for system and structure scoping is

consistent with the methodology described in LRA Section 2.1.2.5. Specifically, LR-TR-508

states that personnel performing license renewal scoping use CLB documents and list allfunctions that the system or structure is required to accomplish. Sources of information

regarding the CLB include the FSAR, system descriptions, CHAMPS database, MRule

information, training materials, walkdowns of plant buildings, and plant drawings.

The systems, structures, and commodity groups within license renewal under the purview of the

civillstructural discipline include all plant structures; the crane, hoist, and lifting device systems;

and the component supports and fire barriers commodity groups. The applicant identified plant

systems, structures and commodity group components in the attachments of LR-TR-508, then

evaluated them against the scoping criteria of 10 CFR 54.4(a)(1), (2), and (3) to identify those

systems, structures and components in the commodity groups, that perform one or more

intended functions. A system, structure or commodity group component was presumed to be

within the scope of license renewal if it performed one or more safety-related functions or met

other scoping criteria per the Rule as determined by CLB review and walkdown by technical

personnel. Identified functions were then compared to a list of scoping questions to determine

the functions which met the scoping criteria of 10 CFR 54.4(a). A structure's evaluation that

was determined to be not within the scope of license renewal was individually documented in

the license renewal database with an in-depth explanation. A scoping matrix for each system,

structure, and commodity group listed the specific scoping group, screening group, and AMR

group, as applicable.

The staff found, in reviewing commodity group classifications, that similar component types

were dispositioned to one commodity group with a single aging management review. The basis

for the grouping was determined by similar design and material construction considerations.

The OSUP included component and equipment supports, fasteners and anchors used in

supports, and electrical enclosures. -The fire barriers group included fire wraps, fire penetration

seals, and cable tray fire stops. The staff reviewed a sample of the components identified by

the scoping process as listed in LR-TR-508, Attachment 8.

The staff also reviewed LR-TR-508, Section 2.6, which summarizes the results of the structure

evaluations performed for the scoping process. The results were provided in separate

database output reports by system, structure, and commodity group. Additionally, the reports

contain system and boundary descriptions, system-level functions, references, and comments.

The staff also found that the reports were independently prepared, reviewed, and approved.

Conclusion. The staff reviewed the applicant's methodology for identifying systems and

structures meeting civil/structural scoping criteria as defined in the Rule. The staff also

reviewed a sample of the scoping methodology implementation procedures and results and

discussed the methodology and results with the applicant. The staff verified that the applicant

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

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SSCs required to be in-scope in accordance with the 10 CFR 54.4(a) criteria. On the basis of

this sample review, the staff concluded that the applicant's methodology for identifying

civil/structural systems and structures meeting the scoping criteria of 10 CFR 54.4(a) is

adequate.

Electrical and l&C Scoping. The staff reviewed the Scoping Output Process Report which

documented the results of the scoping process at the system or structure level for electrical and

l&C scoping. The plant systems were identified within CHAMPS using system identifiers.

Different system boundaries were defined for-license renewal, with some containing multiple

CHAMPS systems. The scoping process was performed in accordance with LRPP 2-1,

'Scoping and Screening for License Renewal." The systems were identified at specific voltage

levels for electrical (e.g., 1 3k VAC, 480 VAC) or within functional performance-related systems

(e.g., reactor protection, radiation monitoring) for instrumentation and control. The staff also

reviewed LR-TR-508, uUcense Renewal Technical Report," Attachment 3, which lists the

systems within the scope of license renewal and the commodity groups that were created for

the common components within the scope of license renewal.

The staff reviewed specific documentation for the emergency power system. The emergency

power system consists of four emergency diesel generators (EDGs) and a GTG. The normal

source of power to safety-related 4160 VAC and 480 VAC buses is from offsite power through

the station low-voltage auxiliary transformers. In the unlikely event of a loss of offsite power,

the GTG can power required loads until the EDG or offsite power is restored. The 125 VDC,

480 VAC and 13.8k VAC power systems interface with the offsite power supply. The

emergency power system also contains components credited for use in safe shutdown following

SBO events and some plant fires.

The staff reviewed LR-SCOPE-631, which identifies the emergency power system scoping

functions. The Scoping Output Report, Attachment 6.1, "Emergency Power," provides all the

system functions within the scope of license renewal for the emergency power system. The

emergency power system functions include:

* senses or provides process conditions and generate signal for reactor trip and

engineered safety features actuation

* provides electrical power to safety Class 1, 2, and 3 components

* provides signals for RG 1.97 Type D post-accident monitoring variables during

accidents

* nonsafety-related SSCs whose failure could prevent satisfactory accomplishment of

safety-related functions

* SSCs relied upon in safety analysis in regulated events

The staff reviewed the identified functions in the emergency power system DBDs and the

methodology used in LR-SCOPE-631 to identify other electricaVl&C components within the

scope of license renewal. The staff found that LR-SCOPE-631 identifies all the in-scope

emergency power system functions for license renewal and is consistent with the DBDs and the

LRA.

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Conclusion. The staff reviewed the applicant's methodology for identifying systems and -

structures meeting the electrical and l&C scoping criteria as defined in the Rule. The staff also

reviewed a sample of the scoping methodology implementation procedures and discussed the

methodology and results with the applicant. The staff verified that the applicant identified and

used pertinent engineering and licensing information in order to determine the SSCs required to

be in-scope in accordance with the 10 CFR 54.4(a) criteria. On the basis of this sample review,

the staff concluded that the applicant's methodology for identifying electrical and l&C systems

and structures meeting the scoping criteria of 10 CFR 54.4(a) is adequate.

2.1.3.2 Screening Methodology

The staff reviewed the screening methodology used by the applicant to determine if mechanical

systems, structures, and electricalI&C components within the scope of license renewal would

be subject to an AMR. The applicant described the screening process in LRA Section 2.1.3.

The initial scoping effort described in LRA Section 2.1.1 identifies the plant systems and

structures that are candidates for inclusion within the scope of license renewal. Screening was

performed in accordance with the guidance provided in NEI 95-10, Revision 3, and applicable

ISG.

The applicant implemented a process for determining which structures and components would

be subject to an AMR in accordance with the requirements of 10 CFR 54.21 (a)(1). In LRA

Section 2.1.3, the applicant discussed these screening activities as they related to the SCs that

are within the scope of license renewal. The screening process evaluated these in-scope SSCs

to determine which were passive, long-lived and, therefore, subject to an AMR. LRA

Sections 2.3, 2.4, and 2.5, provided the results of the process used to identify the SCs that are

subject to an AMR. Specific methodology for mechanical, electrical, and structural component

screening is discussed below.

2.1.3.2.1 Mechanical Component Screening

The staff reviewed the methodology used by the applicant to determine if mechanical systems,

identified within the scope of license renewal, were screened to determine the in-scope

boundary and the passive components that would be subject to further AMR. LRA

Section 2.1.3, described the screening methodology used to make these determinations.

Additionally,-LR-TR-508, Revision 1, Section 3.2, "Integrated Plant Assessment Methodology

Report," provided detailed guidance on mechanical screening methodology.

The nechanical screening discipline-specific methodology included guidance on components

that are screened into the license renewal program and subject to an AMR. This includes

guidance on evaluation boundaries and components that were uniquely screened as active

(e.g.* temperature elements, solenoid valves) or passive (e.g., valve bodies, pipe fittings).

LR-TIR-508 Section 3.2 also includes guidance on screening of stored equipment, screening of

thermal insulation, and assigning of component-level intended functions. For mechanical

components, a screening process was applied to determine the types of mechanical component

commodities within the scope of license renewal, and the various materials and environments to

be considered in the AMR. As discussed previously in SER Section 2.1.2.2.1, valuation

boundaries were established for the various plant mechanical components in order to further

identify individual mechanical components for review. Information sources included design and

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licensing basis documents, plant drawings, license renewal technical reports, and discussion

with license renewal system engineers.

The staff also reviewed LR-SCRN-714, "License Renewal Screening Report, Main and Auxiliary

Steam," Revision 0, dated August 6, 2003, for the main steam system. LR-SCRN-714 and the

LRPMS database identified a total of 3259 components in the main and auxiliary steam system.

LR-SCRN-714 and the LRPMS database included 549 components within the scope of license

renewal. LR-SCRN-714 and the LRPMS database also. determined that 318 components in the

main and auxiliary steam system were screened into the license renewal program and subject

to an AMR. The database screened out 231 active, periodically replaced, and other in-scope

components with no license renewal intended function.

Conclusion. The staff reviewed and evaluated the overall mechanical component screening

methodology as described and documented in the license renewal application and

implementation procedures. The staff concluded that the screening methodology is consistent

with the requirements of the Rule; that implementation of the methodology identified

mechanical components that met the screening criteria of 10 CFR 54.21 (a)(1); that the

applicant's mechanical component screening methodology is consistent with the guidance

contained in NUREG-1 800; and that the methodology is capable of identifying those passive,

long-lived components within the scope of license renewal that are subject to an AMR.

2.1.3.2.2 Structural Component Screening

The staff reviewed LR-TR-508, Revision 1, Integrated Plant Assessment Methodology Report,"

which describes the screening methodology that the applicant used to determine the

discipline-specific screening process for structural components. The civilstructural engineering

discipline was responsible for performing the screening evaluations on the in-scope structures;

crane, hoist, and lifting device systems; as well as the component supports and fire barrier

commodity groups. The boundaries for in-scope systems, structures, and commodity groups

were defined to determine the components that would need screening. The staff reviewed the

attachments to LR-TR-508 which describe the screening process results and found the

screening methodology described in LRA Section 2.1.3 adequate to identify structural

components subject to an AMR.

Additionally, the staff found that the methodology used to screen structural components within

evaluation boundaries, with the exception of snubbers that supported a component-level

intended function, were assumed to be long-lived and passive and, therefore, would require an

AMR. Individual structure components are represented by generic components that identify the

materials of construction and environmental exposure. Materials were placed in groups that

would be expected to experience the same type of aging mechanism and effects and would,

therefore, need the same type of aging management. Evaluation boundaries for the SCs

determined where substructures were assigned for evaluation and dictated the type of generic

components that were to be a part of a structure or commodity group. The screening process

that confirmed the boundary and generic component identification process and verified all

components was evaluated. The staff reviewed a sample of boundary, substructure, and

generic component determinations and found them to be adequate and in accordance with the

process described in the LRA.

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The staff also reviewed a sample of the screening process results which were listed in database.

output reports sorted by system, structure, and commodity group, and were independently

prepared, reviewed and approved. The staff found the results of the sample reviewed to be

adequate to identify structural components subject to an AMR.

Conclusion. The staff reviewed and evaluated the civil/structural component screening

methodology as described in the license renewal application and implementation procedures.-

The staff concluded that the screening methodology is consistent with the requirements of the

Rule; that implementation of the methodology for civil/structural components meets the

screening criteria of 10 CFR 54.21 (a)(1); that the applicant's structural component screening

methodology is consistent with the guidance contained in NUREG-1 800, and that the

methodology is capable of identifying those passive, long-lived components within the scope of

license renewal that are subject to an AMR.

2.1.3.2.3 Electrical and I&C Component Screening

The staff reviewed LR-TR-508, Revision 1, "Integrated Plant Assessment Methodology Report,"

which describes the screening methodology that the applicant used to determine the

discipline-specific screening process for electrical and l&C components. The applicant's

license renewal project electrical engineers were responsible for performing the screening

evaluation on the in-scope electrical and l&C system components. The LRA identifies three

commodity groups for passive, long-lived components subject to an AMR. Specifically, (1)

panels, racks, cabinets, and junctions boxes were placed into the "PANEL" commodity group;

(2) the electrical penetration assemblies were placed into the "EPA" commodity group; and (3)

cables and connections were placed into the "CABLE" commodity group.

The applicant used the LRDB sorting capabilities and active component types identified in

NEI 95-10, Appendix B, to identify components that screened out of license renewal and were

not subject to an AMR pursuant to 10 CFR 54.21 (a)(1). The passive components remaining in

the systems were transferred into one of the three commodity groups. Since some electrical

components are contained in generic systems within the database, or were not uniquely

identified in CHAMPS, specific generic components were developed to represent and track

these items in the LRDB. These generic components included non-EQ low- and

medium-voltage cables, splices, fuse holders, terminal blocks, low- and medium-voltage phase buses, switchgear buses, high voltage insulators and transmission conductors. The staff found

this screening methodology acceptable for identifying passive and long-lived electrical

components that were screened into license renewal and subject to an AMR, as required by- ,

10 CFR 54.21 (a)(1).

The staff also reviewed screening documents related to the emergency power system, which

included LR-SCRN-722, "License Renewal Screening Report Emergency Power," and the

Screening Output Report, Attachment 6.1, "Emergency Power." The staff found that the

emergency power system components which were passive and long-lived were determined by

the applicant to be subject to an AMR. The screening process was performed in accordance

with LRPP 2-1, "Scoping and Screening for License Renewal." The screening process

evaluations were performed and documented in the LRPMS database. LRPP 1-1, "License

Renewal Project Procedure," discussed the use of the LRPMS database. In addition,

LR-TR-508 documented that the emergency power system was considered within the license

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renewal scope because it contained components from the original CHAMPS system codes for

the diesel generator (DG), diesel starting air (DA), gas turbine (GT), and fuel oil components.

LR-SCRN-722, Attachment 6.1 was a copy of the output document from the LRPMS which

documented the results of the screening process performed at the component level. The

subsystems and components in the attachment were part of the mechanical and electrical

component scoping and screening methodology for the LRA. Additionally, in LR-SCRN-722,

Attachment 6.1, the staff found that the applicant scoped and screened in passive and

long-lived mechanical components that are subject to an AMR, including: air motors, flame

arresters, instrumentation, sight glasses, and turbo-chargers.

The staff also noted that report LR-SCRN-722, Attachment 6.1, included emergency power

system components such as motors, pumps, engines, circuit breakers, batteries, and relays

which were screened-out active components not subject to an- AMR.

Conclusion. The staff reviewed and evaluated the electrical and I&C component screening

methodology as described and documented in the LRA and implementation procedures. The

staff concluded that the screening methodology is consistent with the requirements of the Rule;

that implementation of the methodology identified electrical and l&C components meets the

screening criteria of 10 CFR 54.21 (a)(1); that the applicant's electrical and I&C component

screening methodology is consistent with the guidance contained in NUREG-1 800, and that the

methodology is capable of identifying those passive, long-lived components within the scope of

license renewal that are subject to an AMR.

2.11A Conclusion

The staff's review of the Information presented in LRA Section 2.1, the supporting information in

the scoping and screening implementation procedures and reports, the information presented

during the scoping and screening methodology audit, and the applicant's responses to the

staff's RAls, form the basis of the staff's safety determination. The staff verified that the

applicant's revised scoping and screening methodology is consistent with the requirements of

the Rule and the staff's position on the treatment of nonsafety-related SSCs. On the basis of

the review discussed above, the staff concluded that the applicant's methodology for identifying

SSCs within the scope of license renewal and SCs requiring an AMR is consistent with the

requirements of 10 CFR 54.4 and 10 CFR 54.21 (a)(1).

2.2 Plant-Level Scoping Results

2.2.1 Introduction

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 to be included within the scope of license renewal.

The staff reviewed the plant-level scoping results to determine whether the applicant properly

identified all plant-level systems and structures relied upon to mitigate design basis events

(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

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well as the systems and structures relied on safety analyses or plant evaluations to perform a

function that is required by one of the regulations referenced in 10 CFR 54.4(a)(3).

2.2.2 Summary of Technical Information In the Application

In LRA Table 2.2-1, the applicant provided a list of plant systems and structures, identifying

those that are within the scope of license renewal and those that are not within the scope of

license renewal. Based on the DBEs considered in the plant's CLB, other CLB information

relating to nonsafety-related systems and structures, and certain regulated events, the

applicant identified those plant-level systems and structures within the scope of license renewal,

as defined in 10 CFR 54.4.

As documented under RAI 2.1-1 in SER Section 2.1, by letter dated April 29, 2005, the

applicant changed the methodology used to determine the nonsafety-related SSCs that are

within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(2).

As a result of the Implementation of the scoping methodology changes, the applicant identified

no new plant-level systems or structures within the scope of license renewal.

2.2.3 Staff Evaluation

In LRA Section 2.1, the applicant described its methodology for identifying the systems and

structures 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 SER

Section 2.1. To verify that the applicant properly implemented its methodology, the staff

focused its review on the implementation results, as shown in LRA Table 2.2-1, to confirm that

there was no omission of plant-level systems and structures within the scope of license

renewal.

The staff determined whether the applicant properly identified the systems and structures within

the scope of license renewal, in accordance with 10 CFR 54.4. The staff reviewed selected

systems and structures that the applicant identified as not falling within the scope of license

renewal to verify whether those systems and structures have any intended functions that fall

within the scope of license renewal. The staff's review of the applicant's implementation was

conducted in accordance with the NUREG-1 800, Section 2.2.

The staff sampled the contents of the FSAR based on the listing of systems and structures in

LRA Table 2.2-1 to determine whether therevwere systems or structures that may have

intended functions as defined by 10 CFR 54.4, but were not included within the scope of license

renewal. The staff did not identify any omissions.

2.2.4 Conclusion

The staff reviewed LRA Section 2.2 and the supporting information in the FSAR to determine

whether any systems and structures within the scope of license renewal had not been identified

by the applicant. No omissions were identified. On the basis of this review, the staff concluded

that the applicant had appropriately identified the systems and structures that are within the

scope of license renewal in accordance with 10 CFR 54.4.

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2.3 System Scoping and Screening Results - Mechanical Systems

This section documents the staff's review of the applicant's scoping and screening results for

mechanical systems. Specifically, this section discusses the following mechanical systems:

* reactor vessel, internals, and reactor coolant system

* engineered safety features

* auxiliary systems

* steam and power conversion system

In accordance with the requirements of 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 its

methodology, the staff focused its review on the implementation results. This approach allowed

the staff to confirm that there were no omissions of mechanical systems components that meet

the scoping criteria and are subject to an AMR.

Staff Evaluation Methodology. The staff's evaluation of the information provided in the license

renewal application (LRA) was performed in the same manner for all mechanical systems. The

objective of the review was to determine if the components and supporting structures for a

specific mechanical system that appeared to meet the scoping criteria specified in the Rule

were identified by the applicant as within the scope of license renewal in accordance with

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).

Scovina. To perform its evaluation, the staff reviewed the applicable LRA section and

associated component drawings, focusing its review on components that had not been

identified as within the scope of license renewal. The staff reviewed relevant licensing basis

documents, including the FSAR, for each mechanical system component to determine whether

the applicant had omitted system components with intended functions delineated under

10 CFR 54.4(a) from the scope of license renewal. The staff also reviewed the licensing basis

documents to determine if all intended functions delineated under 10 CFR 54.4(a) were

specified in the LRA. If omissions were identified, the staff requested additional information to

resolve the discrepancies.

As documented under RAI 2.1-1 in SER Section 2.1, by letter dated April 29, 2005, the

applicant changed the methodology used to determine the nonsafety-related SCs that are

within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(2).

As a result of the implementation of the scoping methodology changes, the applicant identified

the following, previously excluded, mechanical systems component types:

(1) Engineered Safety Features (LRA Section 2.3.2)

* Safety Injection System (LRA Table 2.3.2-1)

- level gauges

* Containment Spray System (LRA Table 2.3.2-2)

- level gauges

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(2) Auxiliary Systems (LRA Section 2.3.3)

a Chemical and Volume Control System (LRA Table 2.3.3-1)

- level gauges

* Spent Fuel Pool Cooling System (LRA Table 2.3.3-3)

- filters and strainers

- tanks

* Waste Disposal System (LRA Table 2.3.3-4)

- compressor casing - pump casing

- drain traps - restricting orifices

- filters and strainers - sight glass

- level gauges - tank

* Treated Water System (LRA Table 2.3.3-11)

- filters and strainers

- heat exchangers

* Plant Sampling System (LRA Table 2.3.3-14)

- filters and strainers . restricting orifices

- level gauges - tanks

- piping and fittings - valve bodies

(3) Steam and Power Conversion System (LRA Section 2.3.4)

* Main and Auxiliary Steam System (LRA Table 2.3.4-1)i

- filters and strainers - pump casing

- heat exchangers - tanks

- level gauges

* Feedwater and Condensate System (LRA Table 2.3.4-2)

- level gauges - steam traps

- pump casing - tanks

In its letter, dated April 29, 2005, the applicant provided additional information regarding results

of the revised scoping methodology, with specific exceptions for special cases. The staff's

review of this letter identified several exceptions for which clarification was needed. During telephone conferences held on June 30 and July 8, 2005, the staff requested the applicant to

clarify these exceptions. In its response, dated July 19, 2005, the applicant clarified these

exceptions, and as a result, more components were added within the scope of license renewal.

Feedwater heaters 4 and 5, on the 26-feet elevation of the turbine hall for both Units 1 and 2,

have been included within the scope of license renewal. These heaters fall under component

type of "piping and fittings" in LRA Table 2.3.4-2.

The staff found the letters dated April 29 and July 19, 2005, to be acceptable on the basis that

they adequately identified all nonsafety-related structures and components that were added to

the scope of license renewal. The staff did not identify any omission related to the changed

methodology.

Screening.- After completing its scoping evaluation, the staff reviewed the applicant's screening

results. For those SCs with intended functions, the staff sought to determine: (1) if the

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function(s) are performed with moving parts or involve a change in configuration or properties,

or (2) if they are subject to replacement based on a qualified life or specific time period, as

described in 10 CFR 54.21 (a)(1). For those that did not meet any of these criteria, the staff

sought to confirm that these mechanical 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.

The corresponding sections of this SER (2.3.1 - 2.3.4) present the staff's review findings with

respect to the scoping and screening of the mechanical systems for both Units 1 and 2.

2.3.1 Reactor Vessel, Internals, and Reactor Coolant System

In LRA Section 2.3.1, the applicant identified the SCs of the reactor vessel, internals, and

reactor coolant system (RCS) that are subject to an AMR for license renewal.

The applicant described the supporting SCs of the reactor vessel, internals, and reactor coolant

system in the following LRA sections:

* 2.3.1.1 Class 1 piping/components system

* 2.3.1.2 reactor vessel

* 2.3.1.3 reactor vessel internals

• 2.3.1.4 pressurizer

* 2.3.1.5 steam generators

* 2.3.1.6 non-Class 1 RCS components system

The corresponding subsections of this SER (2.3.1.1 - 2.3.1.6) present the staff's review

findings with respect to the reactor vessels, internals, and reactor coolant systems for both

Units 1 and 2.

2.3.1.1 Class I Piping/Components System

2.3.1.1.1 Summary of Technical Information in the Application

In LRA Section 2.3.1.1, the applicant described the Class 1 piping/components system. The

Class 1 piping/components system consists of the main RCS loops, and interconnecting piping

from various other systems, typically extending to the second isolation valve off of the main

RCS loop. The RCS consists of two heat transfer loops connected in parallel to the reactor

pressure vessel (RPV). Each reactor coolant loop contains a reactor coolant pump (RCP) and

a steam generator (SG). In addition, the RCS includes a pressurizer that is connected to

loop B hot leg, interconnecting piping and valves, and instrumentation necessary for protection

and control.

Functions associated with the Class 1 portions of the RCS include the following:

* maintains the reactor core assembly geometry by supporting the fuel and fuel

assemblies

* uses boron injection paths to introduce emergency negative reactivity and make the

reactor subcritical

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* provides a reactor coolant pressure boundary by containing the coolant for heat transfer

* serves as a closed pressure boundary that limits leakage to the containment building

Units 1 and 2 building structure and interconnecting systems

* provides emergency heat removal from the reactor coolant system during normal or

abnormal operations by using secondary heat removal capability

* provides heat removal from the RCPs through the system's thermal barriers

* provides a primary containment boundary to limit the release of radioactive material to

the environment through piping that penetrates the containment

* supports/houses safety Class 1, 2, or 3 components

In addition, the Class 1 piping/components system performs functions that support fire

protection (FP), station blackout (SBO), pressurized thermal shock (PTS), and environmental

qualification (EQ).

Intended functions within the scope of license renewal include the following:

* <provides for mechanical closure integrity on bolted joints

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

* provides for flow restriction (throttle)

* provides structural support

In LRA Table 2.3.1-1, the applicant identified the following Class 1 piping/components system

component types that are within the scope of license renewal and subject to an AMR:

* bolting for flanged piping joints * reactor coolant pumps (casing and

* orifices and reducers main flange)

* piping and fittings less than four * reactor coolant pumps (thermal barrier,

inches, nominal pipe size (NPS) flange)

* piping and fittings greater than or * thermal barrier heat exchanger tubing

equal to four inches, NPS * thermowells

* piping welds and vent connections * valves less than four inches, NPS

(nickel alloys) * valves greater than or equal to four

primary loop elbows inches, NPS

reactor coolant pump lugs

2.3.1.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.1 and FSAR Sections 3.1, 3.2,4.1, 4.2, 5.2, 6.1, and 9.1.

The staff's review, using the evaluation methodology described in SER Section 2.3, was

conducted in accordance with the guidance described in the Standard Review Plan for License

Renewal (SRP-LR) (NUREG-1800), Section 2.3, uScoping and Screening Results: Mechanical

Systems."

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

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under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had

identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR in

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

The staff's review of LRA Section 2.3.1.1 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI, as discussed below.

RAI 2.3.1.1-1. In LRA Tables 2.3.1-1, 2.3.1-6, and 2.3.3-1, heat exchangers (HXs) have been

identified as a component type within the scope of license renewal. However, specifically for

these HXs, the pressure boundary function, but not the heat transfer function, was identified as

an intended function requiring aging management. In RAI 2.3.1.1-1, dated November 17, 2004,

the staff requested the applicant to clarify why the heat transfer function need not be identified

as within the scope of license renewal and requiring aging management.

In its response, dated December 21, 2004, the applicant stated that none of the HX

components represented in LRA Tables 2.3.1-1, 2.3.1-6 and 2.3.3-1 have a license renewal

intended function of heat transfer based on the CLB. Therefore, heat transfer function was not

listed, and only the pressure boundary function was identified for these HXs. It was further

stated that LRA Table 2.3.1-1 refers to the RCP thermal barrier HXs. The CLB shows that heat

transfer from the RCP HX thermal barrier is not a safety-related function (reference letter NPL

97-0401 dated July 7, 1997, from Wisconsin Electric to NRC). Therefore, heat transfer is not

an intended function for these HXs. LRA Table 2.3.1-6 refers to the RCP motor oil coolers.

The RCPs are powered from nonsafety-related power supplies and are assumed to be lost

during some accident scenarios. Heat transfer from the RCP motor oil coolers is not a

safety-related function; therefore, heat transfer is not an intended function for these HXs. LRA

Table 2.3.3-1 refers to miscellaneous HXs in the chemical and volume control system (CVCS),

including the regenerative, the non-regenerative, the excess letdown, the seal water, the boric

acid evaporator, and the boric acid evaporator condensate HXs. All of these HXs are

non-essential loads, and heat transfer from these HXs is not relied upon for any safety-related

function. The applicant, therefore, concluded that the heat transfer function is not an intended

function for the subject HXs.

The staff found the applicant's response to RAI 2.3.1.1-1 acceptable. The applicant provided

justification as to why the heat transfer function of the subject components need not be included

within the scope of license renewal and require aging management. Therefore, the staff's

concern described in RAI 2.3.1.1-1 is resolved.

2.3.1.1.3 Conclusion

The staff reviewed the LRA and the RAI response described above to determine whether any

SSCs that should be within the scope of license renewal were not identified by the applicant.

No omissions were identified. In addition, the staff performed a review to determine whether

any of the components that should be subject to an AMR were not identified by the applicant.

No omissions were identified. On the basis of its review, the staff concluded that there is

reasonable assurance that the applicant adequately identified the Class 1 piping/components

system components that are within the scope of license renewal, as required by

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10 CFR 54.4(a), and that the applicant adequately identified the Class 1 piping/components

system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.1.2 Reactor Vessel

2.3.1.2.1 Summary of Technical Information in the Application

In LRA Section 2.3.1.2, the applicant described the reactor vessel (RV). The RV, as the

principal component of the RCS, contains the heat-generating core and associated supports,

instrumentation and controls, and coolant circulating channels. Primary outlet and inlet nozzles

provide for the exit of heated coolant and its return to the RV for recirculation through the core.

Subcomponents included for evaluation with the RV include: control rod drive mechanism

(CRDM) penetrations and housings, bottom mounted instrument (BMI) penetrations and

external guide tubing, head vent penetration, seal table pressure boundary fittings, and head

closure bolting.

The primary function of the RV is to provide a reactor coolant pressure boundary (RCPB) and to

support the vessel internals and instrumentation. In addition, the RV performs functions that

support pressurized thermal shock.

Intended functions within the scope of license renewal include the following:

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

* provides structural and/or functional support to the thimble tubes

* provides structural and/or functional support to the RV internals

* provides for mechanical closure integrity of bolted joints

* provides structural and/or functional support for some RV subcomponent assemblies

In LRA Table 2.3.1-2, the applicant identified the following RV component types that are within

the scope of license renewal and subject to an AMR:

* BMI guide tubes

* closure head dome

* closure head dome (including lifting

lugs)

* closure head flange

* bottom head torus

* bottom head dome

* closure studs, nuts, and washers

* core support pads

* CRDM housings and flanges (rod

travel and latch)

* CRDM housing tubes (head

adapters)

* intermediate shell (including

circumferential beltline weld)

6

6

0

0

0

0

a

instrumentation tubes and safe ends

lower shell

nozzle support pads and external

support brackets

primary inlet nozzles

primary nozzle safe ends

primary outlet nozzle

refueling seal ledge

RV components (in contact with primary

water)

seal table fittings

upper shell

vent pipe

ventilation shroud support ring

vessel flange

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2.3.1.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.2 and FSAR Sections 3 and 4. The staff's review, using

the evaluation methodology described in SER Section 2.3, was conducted in accordance with

the guidance described in NUREG-1 800, Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had

identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR in

accordance with the requirements of 1 0 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.1.2 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

RAI 2.3.1.2-1. The staff position on reactor vessel flange leak-off lines is that unless a

plant-specific justification is provided, the components fall within the scope of license renewal

and will require aging management. In RAI 2.3.1.2-1, dated November 17, 2004, the staff

requested the applicant to clarify whether any of the component types listed in LRA

Table 2.3.1-2 (Reactor Vessel) or Table 2.3.1-6 (Non-Class 1 Reactor Coolant System

Components System) include the subject components. If not, then the subject components

should be identified as within the scope of license renewal, and requiring aging management.

In the alternative, the applicant may provide a plant-specific justification for excluding the

components.

In its response, dated December 21, 2004, the applicant stated that the reactor vessel flange

leak detection lines do not perform or support any license renewal system intended functions

that satisfy the scoping criteria of 10 CFR 54.4 and, therefore, are not within the scope of

license renewal. It further stated that each of the reactor vessel flange leak detection lines

includes a 3/1 6-inch diameter orifice in the reactor pressure vessel (RPV) flange which would

limit any potential RCS leakage to within the capacity of a charging pump in the unlikely event

of leakage past the inner 0-ring. Since the leak detection lines are nonsafety-related and their

potential failure would not prevent satisfactory accomplishment of any safety-related functions,

the leak detection lines do not perform or support any license renewal intended functions that

meet the scoping criteria of 10 CFR 54.4(a) and, therefore, an AMR is not required. Since they

are not in-scope, the leak detection lines are not included in any component types listed in LRA

Tables 2.3.1-2 or 2.3.1-6.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.1.2-1

acceptable. The applicant provided justification as to why the component did not meet the

scoping and screening criteria outlined in 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1); therefore, is

not required to be within the scope of license renewal. The staff's concern described in

RAI 2.3.1.2-1 is resolved.

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2.3.1.2.3 Conclusion

The staff reviewed the LRA and the RAI response described above to determine whether any

SSCs that should be within the scope of license renewal were not identified by the applicant.

No omissions were identified. In addition, the staff performed a review to determine whether

any of the components that should be subject to an AMR were not identified by the applicant.

No omissions were identified. On the basis of its review, the staff concluded that there is

reasonable assurance that the applicant adequately identified the RV components that are

within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant

adequately identified the RV components that are subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.3.1.3 Reactor Vessel Internals

2.3.1.3.1 Summary of Technical Information in the Application

In LRA Section 2.3.1.3, the applicant described the reactor vessel internals (RVI). The RVI

consist of two basic assemblies: (1) an upper internals assembly that is removed during each

refueling operation to obtain access to the reactor core; and (2) a lower internals assembly that

can be removed following a complete core unload. Subcomponents evaluated with the RVI

include: support columns and plates, core barrel, baffle former assembly and bolting, and the

instrument and control guides and supports.

The primary functions of the RVI are to support the core, provide flow distribution throughout

the core, shield the vessel, and guide and support any instrumentation and controls.

Intended functions within the scope of license renewal include the following:

* provides a passageway for the distribution of reactor coolant flow to the reactor core

* provides gamma and neutron shielding for the reactor pressure vessel

* provides for support and orientation of the reactor core

* provides a secondary core support for limiting the core support structure downward

displacement

* provides a passageway for support, guidance, and protection of in-core instrumentation

* provides for support, orientation, guidance, and protection of the control rod assemblies

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

In LRA Table 2.3.1-3, the applicant identified the following RVI component types that are within

the scope of license renewal and subject to an AMR:

* baffle and former plates - clevis insert bolts

* baffle/barrel - former bolts * clevis inserts

* bottom mounted instrumentation (BMI) * core barrel - plates

column cruciforms * core barrel flange - ring forging, core

* BMI columns barrel (guide key)

* clevis insert bolt locking mechanisms * core barrel outlet nozzle - nozzle

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forgings

* exposed surfaces and crevice

locations

* guide tube (GT) support pin (split pin)

* flux thimbles

6

0

0

0

0

S

S

S

0

head and vessel alignment pins

high temperature and neutron fluence

locations

hold down spring

lower core plate

lower core plate fuel alignment pins

lower support columns, sleeves

lower support forging

lower support plate column bolts/nuts

radial support keys

energy absorber, diffuser plate (flow

mixer plate)

* secondary core support assembly -

guide post, housing

* head cooling spray nozzle bodies and

nozzle tips

* thermal shield - plate material,

flexures, dowel pin

* upper core plate

* upper core plate alignment pin

* upper core plate fuel alignment pin

* upper instrumentation column, conduit

(tubing and supports), spacers/clamps

* upper support column (USC) and

bottom nozzles

* USC instrumentation fittings

* USC base castings

*; USC bolts

* upper support plate, deep beam

weldment, top plate, ribs, hollow

rounds

* rod control cluster assembly (RCCA)

flexures

* RCCA guide tube bolts

* RCCA guide tubes, inserts, and flow

downcomers

* secondary core support - base plate,

2.3.1.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.3 and FSAR Sections 3 and 4. The staff's review, using

the evaluation methodology described in SER Section 2.3, was conducted in accordance with

the guidance described in NUREG-1800, Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had

identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR in

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

2.3.1.3.3 Conclusion

The staff reviewed the LRA to determine whether any SSCs that should be within the scope of

license renewal were not identified by the applicant. No omissions were identified. In addition,

the staff performed a review to determine whether any of the components that should be

subject to an AMR were not identified by the applicant. No omissions were identified. On the

basis of its review, the staff concluded that there is reasonable assurance that the applicant

adequately identified the RVI components that are within the scope of license renewal, as

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required by 10 CFR 54.4(a), and that the applicant adequately identified the RVI components

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

2.3.1.4 Pressurizer

2.3.1.4.1 Summary of Technical Information in the Application

In LRA Section 2.3.1.4, the applicant described the pressurizer. The pressurizer is part of the

reactor coolant system (RCS) and is located inside the containment. It is used for RCS

pressure control and consists of the pressurizer vessel equipped with electric heaters, safety

valves, relief valves, spray nozzle, and all of the interconnecting piping and instrumentation.

During operation, the pressurizer contains saturated water and steam that is maintained at the

desired saturation temperature and pressure through the use of electric heaters and the spray

nozzle.

The pressurizer scope is limited to the pressure boundary up to and including the nozzles,

nozzle safe ends, nozzle-to-safe end welds, and the support skirt and flange. Boundaries

between the pressurizer and associated systems and components are typically drawn at the

pressurizer interface. As such, the following systems and components are not considered as

part of the pressurizer Class 1 piping and the attachment welds to the pressurizer nozzles/safe

ends; and instrument piping/tubing, valves, manifolds and instrumentation beyond the Class 1

boundary. The support skirt and support flange, which are welded to the lower pressurizer

head, are considered to be part of the pressurizer; however, the support attachment bolting is

not part of the pressurizer.

The pressurizer maintains the required reactor coolant pressure during steady-state operation

and normal heatup and cooldown. The pressurizer also limits pressure changes, to an

allowable range, that are the result of reactor coolant thermal expansion and contraction during

normal plant load changes and transients.

Intended functions within the scope of license renewal include the following:

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

* provides for mechanical closure integrity on bolted joints

* provides structural and/or functional support for some pressurizer subcomponent

assemblies

* provides thermal shielding to minimize nozzle low-cycle thermal fatigue

In LRA Table 2.3.1-4, the applicant identified the following pressurizer component types that are

within the scope of license renewal and subject to an AMR:

* heater well and heater sheath * relief nozzle safe end

* instrument nozzles * safety nozzle

* lower head * safety nozzle safe end

* manway cover * shell

* manway cover bolts * spray nozzle

* relief nozzle * spray nozzle safe end

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* spray nozzle thermal sleeve * surge nozzle safe end

* support skirt and flange * surge nozzle thermal sleeve

* surge nozzle * upper head

2.3.1.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.4 and FSAR Section 4. The staff's review, using the

evaluation methodology described in SER Section 2.3, was conducted in accordance with the

guidance described in NUREG-1 800, Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had

identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR in

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

The staff's review of LRA Section 2.3.1.4 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAls as discussed below.

RAI 2.3.1.4-1. Drawings 541 F091, sheet 2 and 541 F445, sheet 2 show that the pressurizer

relief tank (PRT) is within the scope of license renewal, whereas its subcomponents, such as

the PRT spray, rupture disk, and associated piping are shown to be outside the scope of

license renewal. The staff believes that failure of PRT spray, rupture disk, and/or the

associated piping can result in failure of the PRT itself to perform its intended function.

Therefore, in RAI 2.3.1.4-1, dated November 17, 2004, the staff requested the applicant to

include the PRT spray, rupture disk, and the associated piping within the scope of license

renewal, or to provide an explanation as to how failure of the PRT subcomponents will not

degrade the intended functions of the PRT.

In its response, dated December 21, 2004, the applicant stated that the PRT was

conservatively included within the scope of license renewal due to pressurizer safety

valve/power operated relief valve (PORV) discharge header being in-scope for the

10 CFR 50.48 regulated event. The discharge header was included as an Appendix R flow

boundary to assure availability of a pressurizer safety valve for reactor coolant pressure control.

Since the discharge header terminates inside of the PRT, the applicant conservatively included

the PRT in-scope. Neither the discharge header nor the PRT are safety-related components.

The PRT is designed to accommodate leakoffs/flows from various relief valves inside of

containment for cleanliness/contamination control concerns. It is also designed to handle a

"design discharge" from a pressurizer safety valve, which equates to 10 percent of the steam

volume above the full-power pressurizer water level setpoint. This steam volume was

established as the design sizing basis because it corresponds to a reasonable occurrence and

because it is not practical to design the tank to contain the largest conceivable discharge. If a

discharge should occur that exceeds this limit, the relief device (i.e., rupture disk) on the tank

would pass the discharge through the tank to containment. The rupture disk is fail-safe (i.e., it

is designed to fail), and age-related degradation could not prevent this function.

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The applicant further stated in the response that the PRT subcomponents (PRT spray, the

rupture disk, and other associated piping) were not included within the scope of license renewal

as they do not meet any of the 10 CFR 54.4 scoping criteria. None of these subcomponents is

safety-related (Criterion 1). The PRT is nonsafety-related and, therefore, a failure of these

subcomponents would not affect the function of any safety-related components (Criterion 2).

For the Appendix R scenario (regulated event - Criterion 3), none of these subcomponents is

required to function in order to maintain the availability of the pressurizer safety valve. In the

Appendix R scenario, the primary goal is to minimize loss of RCS inventory during cooldown, so

boundary valves (like the pressurizer PORVs) are assumed to fail closed. The pressurizer

safety valve is not expected to be used in this scenario, but only needs to be available to protect

the integrity of the RCS in case the heat sink is lost. Based on this reasoning, the PRT

subcomponents were determined by the applicant to be out-of-scope.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.1.4-1

acceptable. The applicant provided justification as to why the subject components did not meet

the scoping and screening criteria outlined in 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1) and,

therefore, are not required to be within the scope of license renewal. The staff's concern

described in RAI 2.3.1.4-1 is resolved.

RAI 2.3.1.4-2. In LRA Table 2.3.1-4, the pressurizer spray head was not listed as a component

type subject to an AMR. But drawings 541 F091 sheet 1 and 541 F445 sheet 1 showed that

the pressurizer spray head is within the scope of license renewal. In RAI 2.3.1.4-2, dated

November 17, 2004, the staff requested the applicant to clarify this inconsistency. The staff

determined that loss of the spray head due to aging will result in the failure of the pressure

control function of the pressurizer which may be relied upon during and following design-basis

events (DBE) and/or regulated events. If the spray head was to be excluded from the scope,

then the following additional information was requested:

* A justification for how the components (spray head and associated piping inside

,pressurizer) which are relied upon for pressure control function during plant transients,

as stated in the LRA (page 2-79), do not require any aging management during the

period of extended operation.

* A clarification as to whether the CLB for fire protection (FP) complies with certain

sections of Appendix R, particularly Section III.G, which provides the requirements for

the fire protection safe shutdown capability. The applicant was requested to discuss

whether the pressurizer spray head and associated piping are credited and relied upon

in the FP safe shutdown analysis to bring the plant to cold shutdown conditions within a

given time for compliance with Appendix R. If it is credited in the FP safe shutdown

analysis, the pressurizer spray head and associated piping would satisfy 10 CFR 50.48,

Appendix R requirements; and therefore, should be included within the scope of license

renewal.

The specific intended function of the subject components which meets the

10 CFR 54.4(a)(3) requirements is the spray function, and the particular components

which help perform this function are the section of piping and the spray head located

inside the pressurizer. The subject components do not have a pressure boundary

function. The applicant was requested to describe whether the loss of spray function

would make it impossible to bring the plant to cold shutdown conditions within the given

time for compliance with Appendix R. If so, then the staff requested that the spray head

2-39
and the associated piping inside pressurizer having the spray function be included within

the scope requiring aging management so that it would provide a reasonable assurance

that an adequate spray function will be maintained inside the pressurizer during the

period of extended operation.

In its response, dated December 21, 2004, the applicant stated the following:

* The pressurizer (PZR) spray head (made of austenitic stainless steel casting) is a

non-pressure boundary subcomponent and is secured in place by a locking bar. The

associated PZR internal piping is also made of austenitic stainless steel. A detailed

discussion of the function of these subcomponents during normal operation and an

Appendix R transient is presented below in the answer to the second question. These

subcomponents were initially placed within the scope of license renewal due to their

affiliation with the PZR, but were determined not to require aging management because

they do not serve a PZR component intended function.

* The PZR spray function is necessary for RCS PZR pressure control. As noted in

WCAP-1 4574-A, "Aging Management Evaluation for Pressurizers," the RCS pressure

control function of the PZR is not relied on to prevent or mitigate any of the

consequences of DBE. The PZR spray function is, however, credited in the Appendix R

safe shutdown analysis to cool and depressurize the RCS at less than 25 OF per hour

using auxiliary spray.

On the basis of an analysis discussed below, the applicant also concluded that since the Fire

Protection 10 CFR Part 50 Appendix R criteria allow up to 72 hours to achieve cold shutdown,

the spray function using the spray head is not required. The applicant stated the following:

The spray heads are attached to the spray nozzles inside the PZRs and do not perform

a pressure boundary function. The function of the spray heads is to enhance the

efficiency (i.e., RCS pressure control response time) of PZR spray during plant

transients by dispersing the spray flow in the steam space, and thereby maximizing

condensation of the steam bubble. Failure of the spray head would not prohibit the

120 OF spray water from entering the PZR, and consequently condensing a portion of

the steam, and also cooling the bulk liquid volume. It should be recognized that the

design PZR spray flow is 400 gallons per minute (gpm), whereas auxiliary spray flow

with one charging pump is only 30 gpm. Therefore, the effectiveness of the spray head

is diminished during its use in the auxiliary spray mode. Nonetheless, assuming the

anticipated liquid level of the PZR for the Appendix R fire scenario condition (30%), the

entire pressurizer liquid volume (approximately 2500 gallons) could be replaced in less

than 1.5 hours during a plant cooldown. During the Appendix R fire scenario time

period, this volume could be replaced multiple times, if required. This injection of cold

water into the PZR, in combination with securing the normally energized proportional

heaters, will result in significant cooling of the lower PZR shell. As a result, the lower

shell will act as a heat sink and cool the upper portion of the shell by direct conduction,

in addition to its heat losses to the containment environment. Condensation of the

steam will occur by heat transfer to the internal walls of the PZR and to the liquid

surface at the vapor/water interface. Although some temperature stratification of the

liquid volume may occur near the surface (i.e., vapor/water interface) as the steam

condenses, the introduction of cold water into the top of the PZR will provide for mixing

2-40 -
as the bulk fluid is drawn out of the bottom through the surge line. The heat losses to

the containment environment are compensated for by the proportional heaters which

have a rated capacity of >123 Kilowatts (KW). Approximately, 25KW of this capacity is

required to make up for the ambient heat losses. Thus, the PZR ambient heat losses

are approximately 100,000 Btu/Hr. This supports the conclusion that the Appendix R

fire scenario time period provides ample time to reduce PZR pressure.

In addition, the applicant stated in its response that the use of auxiliary pressurizer spray is the

preferred procedural method for RCS pressure reduction in an Appendix R fire scenario. An

alternate method is also available to accommodate RCS pressure reduction. In the alternate

approach, the pressurizer is taken to solid conditions, and pressure control is established using

the CVCS system directly. Use of auxiliary spray for pressure control is not credited in the

alternate method.

The applicant, therefore, concluded that the pressurizer spray heads at PBNP are not relied on

to demonstrate compliance with Appendix R postulated fire events, and that the components

have no intended function for license renewal and, therefore, do not require aging

management.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.1.4-2

acceptable. The applicant explained why the subject components have no intended functions

as delineated in 10 CFR 54.4(a). The applicant provided justification as to why the subject

components did not meet the scoping and screening criteria outlined in 10 CFR 54.4(a) and

10 CFR 54.21 (a)(1) and, therefore, are not required to be within the scope of license renewal.

The staff's concern described in RAI 2.3.1.4-2 is resolved.

2.3.1.4.3 Conclusion

The staff reviewed the LRA, accompanying scoping boundary drawings, and RAI responses

described above to determine whether any SSCs that should be within the scope of license

renewal were not identified by the applicant. No omissions were identified. In addition, the staff

performed a review to determine whether any of the components that should be subject to an

AMR were not identified by the applicant. No omissions were identified. On the basis of its

review, the staff concluded that there is reasonable assurance that the applicant adequately identified the pressurizer components that are within the scope of license renewal, as required

by 10 CFR 54.4(a), and that the applicant adequately identified the pressurizer components that

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

2.3.1.5 Steam Generators

2.3.1.5.1 Summary of Technical Information in the Application

In LRA Section 2.3.1.5, the applicant described the steam generators (SGs). The SGs form the

boundary between the radioactive RCS and the non-radioactive secondary systems. There are

two, essentially identical, SGs installed in each containment. There is one SG in each RCS

loop.

241
Functions associated with the SG system include the following:

0

0

provide a pressure boundary between the primary and secondary systems

remove heat from the RCS

provide structural support

In addition, the SGs perform functions that support fire protection and station blackout.

Intended functions within the scope of license renewal include the following:

* provides structural support to safety-related components

* provides a passageway for the distribution of reactor coolant flow

* provides for flow restriction

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

In LRA Table 2.3.1-5, the applicant identified the following SG component types that are within

the scope of license renewal and subject to an AMR:

* anti-vibration bars

* blowdown piping nozzles and

secondary side shell penetrations

* components (in contact with primary

water)

* divider plate

* feedwater nozzle

* primary channel head

* primary inlet and outlet nozzle safe

ends

* primary inlet and outlet nozzles

* primary manway bolting

* primary manways

* secondary closures

* secondary side closure bolting

* seismic lugs

* steam flow limiter

* tube plugs (mechanical)

* steam outlet nozzle

* support pads

* transition cone girth weld

* tube bundle wrapper and wrapper

support system

* tube support plates

* tubesheet

* upper and lower shell, elliptical head

and transition cone

* U-tubes

2.3.1.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.5 and FSAR Section 4. The staff's review, using the

evaluation methodology described in SER Section 2.3, was conducted in accordance with the

guidance described in NUREG-1 800, Section 2.3.

The staff's review of LRA Section 3.1.2.2.10 identified an area where additional information with

regard to the scoping of SG feedrings and J-tubes was necessary. This discussion is

documented under RAI 3.1.1-2 in SER Section 3.1.2.2.10.

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had

2-42
identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR in

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

2.3.1.5.3 Conclusion

The staff reviewed the LRA to determine whether any SSCs that should be within the scope of'

license renewal were not identified by the applicant. No omissions were identified. In addition,

the staff performed a review to determine whether any of the components that should be

subject to an AMR were not identified by the applicant. No omissions were identified. On the

basis of its review, the staff concluded that there is reasonable assurance that the applicant

adequately identified the SG components that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and that the applicant adequately identified the SG components

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

2.3.1.6 Non-Class 1 RCS Components System

2.3.1.6.1 Summary of Technical Information in the Application

In LRA Section 2.3.1.6, the applicant described the non-Class 1 reactor coolant system (RCS)

components system. The non-Class 1 RCS components system includes all safety Class 2,

Class 3, and non-nuclear safety grade equipment used to functionally support the RCS's

intended functions.

Functions associated with the non-Class 1 RCS Include the following:

* uses its instrumentation to detect, initiate, and actuate automatic safety functions for

reactor trip and engineered safety features actuation

* removes heat from the RCPs

* provides a primary containment boundary to limit the release of radioactive material to

the environment through piping that penetrates the containment

* provides Regulatory Guide (RG) 1.97, Type A post-accident monitoring variables for

instruments in the system

In addition, the non-Class 1 RCS components system performs functions that support

environmental qualification, fire protection and station blackout.

Intended functions within the scope of license renewal include the following:

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

* provides for mechanical closure integrity on bolted joints

* provides for flow control or distribution, as through a spray nozzle

provides a passageway for support, guidance, and protection of in-core instrumentation

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In LRA Table 2.3.1-6, the applicant identified the following non-Class 1 RCS components

system items that are within the scope of license renewal and subject to an AMR:

* carbon steel (CS) components * piping and fittings

* fasteners and bolting * seal table

* flow indicators * tanks

* flywheel * valve bodies

* heat exchanger * valve operator

* instrument valve assemblies

2.3.1.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.6 and FSAR Sections 4.2, 5.1, 5.2, 7.0, and 9.1. The

staff's review, using the evaluation methodology described in SER Section 2.3, was conducted

in accordance with the guidance described in NUREG-1 800, Section 2.3.

The PRT is one portion of the non-Class 1 RCS components system containing components

subject to an AMR. However, the staff identified an area of concern related to the PRT while

reviewing LRA Section 2.3.1.4. This discussion is documented under RAI 2.3.1.4-1 in SER

Section 2.3.1.4.

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had

identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR in

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

2.3.1.6.3 Conclusion

The staff reviewed the LRA to determine whether any SSCs that should be within the scope of

license renewal were not identified by the applicant. No omissions were identified. In addition,

the staff performed a review to determine whether any of the components that should be

subject to an AMR were not identified by the applicant. No omissions were identified. On the

basis of its review, the staff concluded that there is reasonable assurance that the applicant

adequately identified the non-Class 1 RCS components system components that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant adequately

identified the non-Class 1 RCS components system components that are subject to an AMR, as

required by 10 CFR 54.21 (a)(1).

2.3.2 Engineered Safety Features

In LRA Section 2.3.2, the applicant identified the structures and components of the engineered

safety features that are subject to an AMR for license renewal.

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The applicant described the supporting structures and components of the engineered safety

features in the following LRA sections:

* 2.3.2.1 safety injection system

* 2.3.2.2 containment spray system

* 2.3.2.3 residual heat removal system

* 2.3.2.4 containment isolation components system

The corresponding subsections of this SER (2.3.2.1 - 2.3.2.4) present the staff's review

findings with respect to the engineered safety features for both Units 1 and 2.

2.3.2.1 Safety Injection System

2.3.2.1.1 Summary of Technical Information in the Application

In LRA Section 2.3.2.1, the applicant described the safety injection (SI) system. The SI system

supports the RCS inventory and reactivity control during accident and post-accident conditions

by automatically delivering borated water to the reactor vessel for cooling under conditions of

high and low reactor coolant pressure. The Class 1 boundary components that carry an Si

equipment designation are addressed in the Class 1 piping/components system. The Si

system is a standby system during normal plant operation.

The portions of the Si system containing components subject to an AMR extend from the

accumulators and refueling water storage tank (RWST) to the RCS and include the high-head

Si pumps.

Functions associated with the Sl system include the following:

* introduces emergency negative, reactivity to make the reactor subcritical by increasing

the boron concentration, or by delivering borated water

* maintains the reactor coolant pressure boundary integrity during all modes of plant

operation

* provides emergency core coolant by delivering borated cooling water to the RCS during

the injection phase of Si to support core cooling

* provides heat removal through the seal water heat exchangers

* provides a primary containment boundary through containment isolation valves that

assure that an unrestricted release of radiation does not occur

* iprovides the liquid capacity to provide emergency heat removal from the primary

containment

* provides containment pressure control

The failure of nonsafety-related SSCs in the system could prevent the satisfactory

accomplishment'of a safety-related function. In addition, the Si system performs functions that

support environmental qualification and fire protection.

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Intended functions within the scope of license renewal include the following:

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

* provides for mechanical closure integrity on bolted joints

* provides for heat transfer

* provides for flow restriction

In LRA Table 2.3.2-1, as modified by letter dated April 29, 2005, the applicant identified the

following SI system component types that are within the scope of license renewal and subject to

an AMR:

* CS components * piping and fittings

* fasteners and bolting * pump casing

* flow elements * restricting orifices

* heat exchanger * tanks

* instrument valve assemblies * valve bodies

* level elements * level gauges

2.3.2.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.1 and FSAR Sections 4.1, 5.2, 6.2, and 9.1.1. The staff's

review, using the evaluation methodology described in SER Section 2.3, was conducted in

accordance with the guidance described in NUREG-1 800, Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). As a result of the implementation of the scoping methodology changes,

by letter dated April 29, 2005, the applicant identified additional component types within the

scope of license renewal. The staff then reviewed those components that the applicant had

identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR in

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

2.3.2.1.3 Conclusion

The staff reviewed the LRA and the April 29, 2005, letter to determine whether any SSCs that

should be within the scope of license renewal were not identified by the applicant. No

omissions were identified. In addition, the staff performed a review to determine whether any of

the components that should be subject to an AMR were not identified by the applicant. No

omissions were identified. On the basis of its review, the staff concluded that there is

reasonable assurance that the applicant adequately identified the SI system components that

are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant

adequately identified the SI 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 Spray System

2.3.2.2.1 Summary of Technical Information in the Application

In LRA Section 2.3.2.2, the applicant described the containment spray (CS) system. The CS

system is designed to remove sufficient heat from the containment atmosphere following an

accident condition in order to maintain the containment pressure within design limits. The CS

system, in conjunction with the sodium hydroxide (NaOH) tank, is also capable of reducing the

iodine in the containment atmosphere such that the offsite radiation exposure resulting from a

loss-of-coolant accident (LOCA) is within the guidelines established by 10 CFR Part 100. The

addition of NaOH is also credited to reduce the pH levels within the containment sump in order

to prevent chloride stress corrosion cracking (SCC). The system initially takes suction from the

refueling water storage tank (RWST). When a low level is reached in the tank, the spray pump

suction is fed from the discharge of residual heat removal (RHR) pumps if continued spray is

required.

The portions of the CS system containing components subject to an AMR extend from the

pump suction supplies, the RWST or the RHR pump discharge, to the spray headers. The

system also includes the NaOH tank, eductors, and spray pumps.

Functions associated with the CS system include the following:

* provides heat removal and/or a pressure boundary for the safety-related seal water heat

exchangers

* provides a primary containment boundary that can prevent the release of radioactivity

into the environment

* delivers buffered cooling water to the containment spray headers during the injection

phase of safety injection to support containment cooling and ensure that containment

pressure does not exceed its design value

* delivers water during the injection phase for removal of elemental iodine from the

containment atmosphere in the event of a LOCA

In addition, the CS system performs functions that support environmental qualification and fire

protection.

Intended functions within the scope of license renewal include the following:

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

* provides for mechanical closure integrity on bolted joints

* provides for heat transfer

* provides for flow restriction -

* provides for flow control or distribution, as through a spray nozzle

2-47
In LRA Table 2.3.2-2, as modified by letter dated April 29, 2005, the applicant identified the

following CS system component types that are within the scope of license renewal and subject

to an AMR:

* eductor * restricting orifices

* fasteners and bolting * spray nozzle

* flow elements * tanks

* heat exchanger * valve bodies

* instrument valve assemblies * CS components

* piping and fittings * level gauges

* pump casing

2.3.2.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.2 and FSAR Sections 5.2, 6.4, 9.1.1, and Appendix C.

The staff's review, using the evaluation methodology described in SER Section 2.3, was

conducted in accordance with the guidance described in NUREG-1 800, Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). As a result of the implementation of the scoping methodology changes,

by letter dated April 29, 2005, the applicant identified additional component types within the

scope of license renewal. The staff then reviewed those components that the applicant had

identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR in

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

2.3.2.2.3 Conclusion

The staff reviewed the LRA and the April 29, 2005, letter to determine whether any SSCs that

should be within the scope of license renewal were not identified by the applicant. No

omissions were identified. In addition, the staff performed a review to determine whether any of

the components that should be subject to an AMR were not identified by the applicant. No

omissions were identified. On the basis of its review, the staff concluded that there is

reasonable assurance that the applicant adequately identified the CS system components that

are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant

adequately identified the CS system components that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.2.3 Residual Heat Removal System

2.3.2.3.1 Summary of Technical Information in the Application

In LRA Section 2.3.2.3, the applicant described the residual heat removal (RHR) system. The

RHR system is a dual-purpose system, as it operates as a portion of the SI system during

normal operations and also operates by removing reactor decay heat during plant cooldown,

shutdown, and refueling operations. The RHR system's pumps and valves automatically deliver

2-48
borated water to the reactor vessel for cooling under low RCS pressure conditions. After the

injection phase, the RHR pumps will take suction from the containment sump, circulate the

spilled coolant through the RHR heat exchangers, and return the coolant to the reactor via the

reactor vessel nozzles. For normal plant cooldown and shutdown, the RHR system is designed

to transfer the fission product decay heat and other residual heat from the reactor core to the

component cooling water system. There are Class 1 boundary components within the high

temperature RCS envelope that carry RHR equipment designations. These components are

addressed in the Class 1 piping/components system. The RHR system is a standby system

during normal plant operation.

The portions of the RHR system containing components subject to an AMR extend from the

RHR pump suction supplies from the RWST, or the containment sump, to the system

inter-connections to the RCS, and, for recirculation operation, to the SI and CS pump suction

supply.

Functions associated with the RHR system include the following:

* maintains a reactor coolant pressure boundary during all modes of operation

* removes residual heat from the RCS

* removes decay heat from the RCS for mitigating the radiological consequences of the

rupture of a control rod mechanism housing (rod control cluster assembly (RCCA)

ejection), locked rotor, main steam line break, SG tube rupture accident

* delivers borated cooling water to the RCS during the emergency core cooling system

(ECCS) injection phase to support core cooling

* provides for heat removal from the safety-related seal water heat exchangers

* provides a primary containment boundary that can prevent the release of radioactivity

into the environment

* provides emergency heat removal from the primary containment

* provides containment pressure control by supplying water to the suction of the

containment spray pumps when in recirculation mode

In addition, the RHR system performs functions that support environmental qualification and fire

protection.

Intended functions within the scope of license renewal include the following:

* provides for heat transfer

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

* provides for flow restriction

In LRA Table 2.3.2-3, the applicant identified the following RHR system component types that

are within the scope of license renewal and subject to an AMR:

* heat exchanger * pump casing

* instrument valve assemblies * restricting orifice

* piping and fittings * sump screen

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* tanks * CS components

* thermowells * fasteners and boltings'

* valve bodies * filters and strainers

* valve operator * flow elements

2.3.2.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.3 and FSAR Sections 5.2, 6.2, 6.4.2, 9.1.1, and 9.2. The

staff's review, using the evaluation methodology described in SER Section 2.3, was conducted

in accordance with the guidance described in NUREG-1 800, Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had

identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR in

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

2.3.2.3.3 Conclusion

The staff reviewed the LRA to determine whether any SSCs that should be within the scope of

license renewal were not identified by the applicant. No omissions were identified. In addition,

the staff performed a review to determine whether any of the components that should be

subject to an AMR were not identified by the applicant. No omissions were identified. On the

basis of its review, the staff concluded that there is reasonable assurance that the applicant

adequately identified the RHR system components that are within the scope of license renewal,

as required by 10 CFR 54.4(a), and that the applicant adequately identified the RHR system

components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.2.4 Containment Isolation Components System

2.3.2.4.1 Summary of Technical Information in the Application

In LRA Section 2.3.2.4, the applicant described the containment isolation components system.

The containment isolation components system was created as a virtual system for those

systems whose only safety-related function is to provide a containment isolation function. Each

system whose piping penetrates the containment leakage-limiting boundary is designed to

maintain or establish isolation of the containment from the outside environment under any

accident condition, for which isolation is required. Piping penetrating the containment is

designed for pressures at least equal to the containment design pressure. Containment

isolation boundaries are provided, as necessary, in lines penetrating the containment to ensure

that no unrestricted release of radioactivity can occur. Components addressed within the

containment isolation components system include: containment penetration isolation valves,

test flanges, caps, and associated piping and valves to support the system's intended functions.

The system also includes: demineralized water penetrations, radiation monitoring system

containment air sample penetrations, spare containment penetrations, and tubing and valves

that support air-lock testing.

2-50
The portions of the containment isolation components system containing items subject to an

AMR extend between the penetration isolation valves. These include penetration test valves,

flanges, and piping for demineralized water subsystem penetrations, radiation monitoring

system containment air sample penetrations, spare containment penetrations, and associated

airlock support equipment.

The containment isolation components system provides a primary containment boundary to

prevent the release of radioactivity into the environment. In addition, the containment isolation

components system performs functions that support environmental qualification.

Intended functions within the scope of license renewal include the following:

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

* provides for mechanical closure integrity on bolted joints

In LRA Table 2.3.2-4, the applicant identified the following containment isolation system

component types that are within the scope of license renewal and subject to an AMR:

* CS components

* fasteners and bolting

* piping and fittings

* valve bodies

2.3.2.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.4 and FSAR Section 5.2. The staff's review, using the

evaluation methodology described in SER Section 2.3, was conducted in accordance with the

guidance described in NUREG-1 800, Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had

identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR in

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

2.3.2.4.3 Conclusion

The staff reviewed the LRA to determine whether any SSCs that should be within the scope of

license renewal were not identified by the applicant. No omissions were identified. In addition,

the staff performed a review to determine whether any of the components that should be

subject to an AMR were not identified by the applicant. No omissions were identified. On the

basis of its review, the staff concluded that there is reasonable assurance that the applicant

adequately identified the containment isolation components system components that are within

the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant adequately

2-51
identified the containment isolation components system components that are subject to an

AMR, as required by 10 CFR 54.21(a)(1).

2.3.3 Auxiliary Systems

In LRA Section 2.3.3, the applicant identified the structures and components (SCs) of the

auxiliary systems that are subject to an AMR for license renewal.

The applicant described the supporting SCs of the auxiliary systems in the following LRA

sections:

* 2.3.3.1 chemical volume and control system

* 2.3.3.2 component cooling water system

* 2.3.3.3 spent fuel cooling system

* 2.3.3.4 waste disposal system

* 2.3.3.5 service water system

* 2.3.3.6 fire protection system

* 2.3.3.7 heating steam system

* 2.3.3.8 emergency power system

* 2.3.3.9 containment ventilation system

* 2.3.3.10 essential ventilation system

* 2.3.3.11 treated water system

* 2.3.3.12 circulating water system

* 2.3.3.13 fuel handling system

* 2.3.3.14 plant sampling system

* 2.3.3.15 plant air system

* 2.3.3.16 containment hydrogen detectors and recombiner system

The corresponding subsections of this SER (2.3.3.1 - 2.3.3.16) present the staff's review

findings with respect to the auxiliary systems for both Units 1 and 2.

2.3.3.1 Chemical Volume and Control System

2.3.3.1.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.1, the applicant described the chemical volume and control system

(CVCS). The CVCS controls and maintains the RCS inventory and purity through the process

of charging and letdown. The system also provides seal injection flow to the reactor coolant

pump (RCP) seals. In addition to the reactivity control achieved by the control rods, the CVCS

also provides reactivity control by regulating the concentration of boric acid solution in the RCS.

In order to perform the above functions, a continuous feed-and-bleed process (charging and

letdown) is maintained between the RCS and the CVCS.

The portions of the CVCS containing components subject to an AMR extend from the RWST to

the RCS, and also from the RCS to system containment isolation valves (CIVs), including the

pumps, heat exchangers (HXs), piping, and valves.

2-52
The in-scope portion of the CVCS system includes the flow path from the RWST, through the

charging pumps, into the RCS. CVCS lines coming from the RCS are in-scope through the

CIVs.

Functions associated with the CVCS include the following:

* provides a reactor coolant pressure boundary

* provides for heat removal and/or a pressure boundary for the safety-related heat

exchangers (excess letdown, nonregenerative, and RCP seal water HXs)

* provides a primary containment boundary that isolates the containment

The failure of nonsafety-related SSCs in the system could prevent the satisfactory

accomplishment of a safety-related function. In addition, the CVCS system performs functions

that support environmental qualification, fire protection, and station blackout.

Intended functions within the scope of license renewal include the following:

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

* provides for mechanical closure integrity on bolted joints

* provides for filtration

In LRA Table 2.3.3-1, as modified by letter dated April 29, 2005, the applicant identified the

following CVCS component types that are within the scope of license renewal and subject to an

AMR:

* CS components * piping and fittings

* fasteners and bolting * pump casing * filters and strainers * tanks

* flow elements * thermowells

* heat exchanger * valve bodies

* instrument valve assemblies * level gauges

2.3.3.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.1 and the FSAR. -The staff's review, using the evaluation

methodology described in SER Section 2.3, was conducted in accordance with the guidance

described in NUREG-1 800, Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any cOInponents with intended functions delineated

under 10 CFR 54.4(a). As a result of the impi mel of r the scopr ation methodology changes,

by letter dated April 29, 2005, the applicant id ntifiez additional compopent types within the

scope of license renewal. The staff then reviewed et components Ithat the applicant had

identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR In

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

2-53
2.3.3.1.3 Conclusion

The staff reviewed the LRA and the April 29, 2005, letter to determine whether any SSCs that

should be within the scope of license renewal were not identified by the applicant. No

omissions were identified. In addition, the staff performed a review to determine whether any of

the components that should be subject to an AMR were not identified by the applicant. No

omissions were identified. On the basis of its review, the staff concluded that there is

reasonable assurance that the applicant 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

adequately identified the CVCS components that are subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.3.3.2 Component Cooling Water System

2.3.3.2.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.2, the applicant described the component cooling water (CCW) system.

The CCW system provides heat removal capability to support the operation of Units 1 and 2.

The CCW system removes residual and sensible heat from the RCS via the RHR heat

exchangers during the recirculation phase of safety injection in order to support long-term core

cooling.

Functions associated with the CCW system include the following:

* removes heat from the residual heat, safety injection, and containment spray pump seal

coolers to maintain the integrity of the pump seals

* precludes containment leakage through the CCW system piping penetrations following

accidents in order to limit the release of radioactive materials

* removes heat from the reactor coolant pump (RCP) thermal barrier cooling coils in order

to ensure RCS integrity

* removes heat from the RHR heat exchangers to mitigate the consequences of a

postulated main steam line break (MSLB) or steam generator tube rupture (SGTR)

accident

A spare component cooling (CC) pump motor with power cables is provided for a repair if a fire

causes damage to all four CC pumps. It should be noted that these Appendix R components

are addressed in the electrical AMR. The CC system is seismic Class 1 design with the

exception of the CC branch lines to various radwaste components. Recent leak-before-break

(LBB) analyses have allowed the CC system to be classified as a closed loop inside

containment.

The portions of the CCW system containing components subject to an AMR extend from the

supply header to the return header, and include pumps, heat exchangers, equipment coolers,

surge tanks, piping, and valves.

The CCW system provides heat removal from safety-related heat exchangers. The failure of

nonsafety-related SSCs in the system could prevent the satisfactory accomplishment of a

2-54
safety-related function. In addition, the CCW system performs functions that support fire

protections environmental qualification, and station blackout.

Intended functions within the scope of license renewal include the following:

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

* provides for mechanical closure integrity on bolted joints

* provides for heat transfer

In LRA Table 2.3.3-2, the applicant identified the following cooling water system component

types that are within the scope of license renewal and subject to an AMR:

* CS components * pump casing

* fasteners and bolting * radiation monitor

* flow elements * tanks

* heat exchanger * thermowells

* instrument valve assemblies * valve bodies

* piping and fittings

2.3.3.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.2 and FSAR Sections 9.1 and 5.2. The staff's review,

using the evaluation methodology described in SER Section 2.3, was conducted in accordance

with the guidance described in NUREG-1800, Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had

identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR in

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

The staff's review of LRA Section 2.3.3.2 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

RAI 2.3.3.2-1. FSAR Section 9.1 states that the CCW system removes heat from the RCP

thermal barrier cooling coils to ensure reactor coolant system integrity. Drawings LR-1 1 OE029,

sheet I(quadrants B-5 and B-8), Note 3 and LR-1 10E018, sheet 2 (quadrants B-5 and B-8),

Note 6, indicate a Swagelock 1 1

/4-inch diameter, stainless steel, flexible metal hose is used as

a piIpng component on the inlet and outlet of the RCPs. This flexible metal hose is shown on

thee drawings as within the scope of license renewal. If these hoses have been screened in and

incldded as passive components, then LRA Table 3.3.2-2 (Auxiliary Systems - Component

Cooling! Water System - Summary of Aging Management Evaluation) should have included an

entry forstainless steel piping and fittings in this environment. No such entry could be found.

Therefore, it is not clear if these flexible metal hose connectors are included in LRA

2-55
Table 2.3.3-2 as part of the piping and fittings component group. A degraded flexible metal

hose connector could adversely impact the pressure boundary function of the CCW system. In

RAI 2.3.3.2-1, dated November 10, 2004, the staff requested the applicant to clarify whether

these flexible metal hose connectors are included in LRA Table 2.3.3-2 as part of the piping and

fittings component group and are considered to be within the scope of license renewal and

subject to an AMR.

In its response, dated December 14, 2004, the applicant stated that since the flexible metal

hoses did not have a unique component identification number, these components were not

included in LRA Table 3.3.2-2 during the initial reviews for license renewal. The applicant

further stated that these flexible metal hoses are within the scope of license renewal and

subject to aging management. As part of its LRA annual update, the applicant will add line

items to Table 3.3.2-2 to include stainless steel material under the component type "Piping and

Fittings" to address this flexible tubing. The applicant also stated that the flexible tubing will be

age-managed similar to other stainless steel components in the CCW system, via a

combination of the Closed Cycle Cooling Water Program and the One-Time Inspection

Program.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.2-1

acceptable. The staff also agreed that adding additional line items to the 'Piping and Fitting"

component type category in LRA Table 3.3.2-2 is appropriate for stainless steel flexible hoses.

The flexible stainless steel tubing AMR is addressed in SER Section 3.3. The staff's concern

described in RAI 2.3.3.2-1 is resolved.

2.3.3.2.3 Conclusion

The staff reviewed the LRA, accompanying scoping boundary drawings, and the RAI response

described above to determine whether any SSCs that should be within the scope of license

renewal were not identified by the applicant. No omissions were identified. In addition, the staff

performed a review to determine whether any of the components that should be subject to an

AMR were not identified by the applicant. No omissions were identified. On the basis of its

review, the staff concluded that there is reasonable assurance that the applicant adequately

identified the CCW system components that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and that the applicant adequately identified the CCW system

components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.3 Spent Fuel Cooling System

2.3.3.3.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.3, the applicant described the spent fuel (SF) cooling system. The SF

cooling system is designed to remove decay heat produced by irradiated fuel assemblies stored

in the spent fuel pool (SFP). The SF cooling system consists of two separate trains that share

a common suction and return header. Each system possesses an identical heat exchanger and

pump and the associated piping and valves to support the system's intended functions. Water

from the pool is pumped through one or both heat exchangers for cooling and returned to the

pool. When purification is required, a portion of the flow is diverted through the interconnecting

2-56
SF purification subsystem. Service water (SW) is provided to the heat exchangers for removal

of decay heat, although SW can be interrupted during accident conditions.

Portions of the SF cooling system containing components subject to an AMR extend from the

suction header to the return header and include the pumps, heat exchangers, piping and valves

(including the fuel transfer tube isolation valves).

The SF cooling system ensures that SFP is adequately cooled by removing decay heat from

the irradiated fuel assemblies. The failure of nonsafety-related SSCs in the system could

prevent the satisfactory accomplishment of a safety-related function. In addition, the SF cooling

system performs functions that support fire protection.

Intended functions within the scope of license renewal include the following:

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

* provides for mechanical closure integrity on bolted joints

* provides for heat transfer

In LRA Table 2.3.3-3, as modified by letter dated April 29, 2005, the applicant identified the

following SF cooling system component types that are within the scope of license renewal and

subject to an AMR:

* CS components * piping and fittings

* fasteners and bolting * pump casing

* flow element * valve bodies

* heat exchanger * filters and strainers

* instrument valve assemblies * tanks

2.3.3.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.3 and FSAR Section 9.9. The staff's review, using the

evaluation methodology described in SER Section 2.3, was conducted in accordance with the

guidance described in NUREG-1800, Section 2.3.

In conducting its review, the staff evaluated the system functions described In the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intendedi funtions;delineated

under 10 CFR 54.4(a). As a result of the implementation of the scoping mtihodology changes,

by letter dated April 29, 2005, the applicant identified additional comporent'tyes within the

scope of license renewal. The staff then reviewed those components thatlhe'jpplidantfhad

identified as being within the scope of license renewal to verify that the aplcant had not,

omitted any passive and long-lived components that should be subject to anAMR i i

accordance with the requirements of 10 CFR 54.21 (a)(1). M

The staff's review of LRA Section 2.3.3.3 identified areas in which additicnl iformation was

necessary to complete the review of the applicant's scoping and scdening reslts. Thse

applicant responded to the staff's RAls as discussed below.

2-57
RAI 2.3.3.3-1. FSAR, Section 9.9.2, System Design and Operation (paragraph 2) states, *The

spent fuel pool cooling system piping and service water system piping supplying the spent fuel

pool heat exchangers are classified as safety-related, seismic Class 1 SFP drawing

LR-1 I OE01 8, sheet 4 (quadrant H-5) shows that the SW discharge piping from the SFP cooling

heat exchangers (HX-1 3A and HX-1 3B), downstream of the flow control valves, as not within

the scope of license renewal. This is inconsistent with SW system drawing LR-M-207, sheet 3

that shows the piping downstream of the discharge flow control valves as in-scope. In

RAI 2.3.3.3-1, dated November 10, 2004, the staff requested the applicant to clarify whether

this section of the SW piping at the boundaries of the SF cooling system is within the scope of

license renewal or to provide justification for its exclusion from the scope.

In its response, dated December 14, 2004, the applicant stated that drawing LR-1 10E018,

sheet 4 (quadrant H-5) was in error, and that the SW discharge piping from the SF cooling heat

exchangers (HX-1 3A and HX-1 3B), downstream of the flow control valves, is within the scope

of license renewal and subject to aging management. The applicant further stated that drawing

LR- 1 OE01 8, sheet 4 was revised and the error is being tracked in its corrective action

program.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.3-1

acceptable. The applicant sufficiently clarified that the SW discharge piping from the SF

cooling heat exchangers (HX-1 3A and HX-1 3B), downstream of the flow control valves, is within

the scope of license renewal. Therefore, the staff's concern described in RAI 2.3.3.3-1 is

resolved.

RAI 2.3.3.3-2. The SF cooling piping network downstream of the heat exchangers has a

branch going to out-of-scope piping and components leading from the skimmer pump. Drawing

LR- 1 OE01 8, sheet 4 (quadrant F-2) shows the in-scope boundary stopping in the middle of a

piping run and not including skimmer pump discharge isolation valve 793A. Other branch lines

leading off of the SF cooling system include at least one isolation valve within the scope of

license renewal. Failure of the out-of-scope piping or the out-of-scope skimmer pump system

may affect the pressure boundary integrity intended function of this piping segment. In

RAI 2.3.3.3-2, dated November 10, 2004, the staff requested the applicant to justify the

determination to exclude the piping up to and including valve 793A from the scope of license

renewal.

In its response, dated December 14, 2004, the applicant stated that the in-scope portion of the

branch connection referred to in RAI 2.3.3.3-2 includes isolation valve #28 (LR-1 1 OE01 8,

sheet 4, location G-3), which functions as a safety-related license renewal boundary valve for

this system. The applicant stated that, should leakage develop in either the skimmer pump

branch piping or the demineralizer return branch piping, valve #28 can be shut to maintain the

intended functions of the SF cooling system (pumps, HXs, etc.). Also, portions of these branch

connections were included in-scope for 10 CFR 54.4(a)(2) because of the potential for leakage

or spray to affect the safety-related SFP pumps. The in-scope portions of these

nonsafety-related branch connections were determined during plant walkdowns, and the

transition from in-scope to out-of-scope piping are shown at the points where the branch lines

exited the SF pump room/area. According to the applicant, the failure of the out-of-scope

piping or skimmer pump subsystem will have no effect on the intended functions of the SF

cooling system.

2-58
Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.3-2

acceptable. The applicant verified by plant walkdown that the in-scope portions of the

nonsafety-related branch connections, identified on drawing LR-1 1 OEO1 8, were consistent with

plant as-built configurations, and that failure of the out-of-scope piping and valve #793A would

not impact the intended functions of the SF cooling system. Therefore, the staff's concern

described in RAI 2.3.3.3-2 is resolved.

2.3.3.3.3 Conclusion

The staff reviewed the LRA, accompanying scoping boundary drawings, the April 29, 2005,

letter, and the RAI responses described above to determine whether any SSCs that should be

within the scope of license renewal were not identified by the applicant. No omissions were

identified. In addition, the staff performed a review to determine whether any of the

components that should be subject to an AMR were not identified by the applicant. No

omissions were identified. On the basis of its review, the staff concluded that there is

reasonable assurance that the applicant adequately identified the SF cooling system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

that the applicant adequately identified the SF cooling system components that are subject to

an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.4 Waste Disposal System

2.3.3.4.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.4, the applicant described the waste disposal (WD) system. The WD

system provides all the equipment necessary to collect, process, and prepare for the disposal

all potentially radioactive liquid, gaseous, and solid wastes produced as a result of plant

operation. Radioactive fluids entering the WD system are collected in sumps and tanks until

determination of subsequent treatment methods can be made. Design of the WD system is

based on assurance that the consequences of a radioactive release from a subsystem or

component do not pose a hazard to public health and safety.

The portions of the WD system containing components subject to an AMR include the waste

gas and waste liquid containment penetration isolation components, heat exchangers with

CCW interfaces, and the essential piping and valves credited for flood control and SW system

isolation from WD system components.

Functions associated with the WD system include the following:

* provides for pressure boundary of safety-related heat exchangers

* provides a primary containment boundary to prevent the release of radioactivity into the

environment

The failure of nonsafety-related SSCs in the system could prevent the satisfactory

accomplishment of a safety-related function. In addition, the WD system performs functions

that support environmental qualification.

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Intended functions within the scope of license renewal include the following:

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

* provides for mechanical closure integrity on bolted joints

In LRA Table 2.3.3-4, as modified by letter dated April 29, 2005, the applicant identified the

following WD system component types that are within the scope of license renewal and subject

to an AMR:

* CS components * compressor casing

* fasteners and bolting * drain traps

* flow indicators * restricting orifices

* heat exchanger * filters and strainers

* instrumentation * level gauges

* piping and fittings * pump casing

* radiation monitor * sight glass

* valve bodies * tanks

2.3.3.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.4 and FSAR Sections 5.2, 11.1, 11.2, and 11.3. The

staff's review, using the evaluation methodology described in SER Section 2.3, was conducted

in accordance with the guidance described in NUREG-1 800, Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). As a result of the implementation of the scoping methodology changes,

by letter dated April 29, 2005, the applicant identified additional component types within the

scope of license renewal. The staff then reviewed those components that the applicant had

identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR in

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

The staff's review of LRA Section 2.3.3.4 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAls as discussed below.

RAI 2.3.3.4-1. The FSAR states that the WD system discharge to the SW system has an

automatic isolation function to prevent exceeding 10 CFR Part 20 and 10 CFR Part 100 limits

due to high effluent radioactivity. LRA Section 2.3.3.4 states that piping and valves credited for

SW isolation from WD system components are within the scope of license renewal. However,

drain isolation valve WL-1 785A and its inter-tie piping to the WD system are shown as not

within the scope of license renewal on drawing LR-684J971, sheet 2, (Unit 1 & 2 Waste &

Blowdown Evaporator Distillate Process System), at location A-9. Failure of valve WL-1785A

and its associated piping could cause a loss of this 10 CFR Part 20 and 10 CFR Part 100

required function. In RAI 2.3.3.4-1, dated November 16, 2004, the staff requested the applicant

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to justify its determination to exclude valve WL-1 785A and its associated piping from the scope

of license renewal.

In its response, dated December 22, 2004, the applicant stated that the failure to identify drain

isolation valve WL-1785A and its associated piping as in-scope on drawing LR-684J971,

sheet 2 was a highlighting error. The applicant stated that these components are within the

scope of license renewal, subject to aging management, and represented by the 'Valve Bodies'

and 'Piping and Fittings' component types in LRA Table 3.3.2-4. The applicant further stated

that the above drawing was revised and the error is being tracked in its corrective action

program. Based on this discussion, the staff found the applicant's response to RAI 2.3.3.4-1

acceptable, and resolved.

RAI 2.3.3.4-2. The FSAR states WD system discharge to the SW system has an automatic

isolation function to prevent exceeding 10 CFR Part 20 and 10 CFR Part 100 limits due to high

effluent radioactivity. LRA Section 2.3.3.4 states that piping and valves credited for SW system

isolation from WD components are within the scope of license renewal. However, drawing

LR-PBM-231, sheet 1 (Units 1 and 2 de-ionized and reactor water makeup water) at

location F-7, indicates that valve RWM1249A and its downstream piping is not within the scope

of license renewal. Failure of valve RWM1 249A and its downstream piping could cause a loss

of the 10 CFR Part 20 and 10 CFR Part 100 required function. In RAI 2.3.3.4-2, dated

November 16, 2004, the staff requested the applicant to justify its determination to exclude

valve RWM1249A and its downstream piping from the scope of license renewal.

In its response, dated December 22, 2004, the applicant stated that valve RMW-1249A and its

associated piping are within the scope of license renewal and subject to aging management.

These components are represented by the 'Valve Bodies" and 'Piping and Fittings' component

types in LRA Table 3.3.2-4. The applicant explained that failure to highlight these components

as within the scope of license renewal on drawing LR-PBM-231, sheet 1 was an error.

However, these components are highlighted on another (continuation) drawing LR-684J971,

sheet 2 depicting that they are within the scope of license renewal. According to the applicant,

the drawing LR-PBM-231, sheet 1 was revised and the error is being tracked in its corrective

action program. Based on this discussion, the staff found the applicant's response acceptable.

The staff's concern described in RAI 2.3.3.4-2 is resolved.

RAI 2.3.3.4-3. LRA Section 2.3.3.4 states that principal components of the WD system within

the scope of license renewal include the heat exchangers with CCW system interfaces and the

piping and valves that are credited for SW system isolation from WD system components.

Drawing LR 684J971, sheet 1, Units 1 and 2, at location C-3 indicates that the following

components are not within the scope of license renewal: the SW supply to HX 702 (boric acid

waste evaporator vacuum system heat exchanger), the interface with the HX, and the interface

isolation valve BS VA37. This is contrary to the information provided in the LRA and drawing

LR-M-2207, sheet 1, Unit 2 service water at location A-9, which indicate these components are

within the scope of license renewal. Failure of these components could adversely impact the

isolation functions between the WD system and other interfacing systems. In RAI 2.3.3.4-3,

dated November 16, 2004, the staff requested the applicant to justify its determination for not

considering these components to be within the scope of license renewal.

In its response, dated December 22, 2004, the applicant stated that the heat exchanger

HX-702, the valve BS-VA37, and associated piping are within the scope of license renewal as

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highlighted on drawing LR-2207, sheet 1 and are subject to aging management. The applicant

explained that failure to identify these components as in-scope on drawing LR-684J971, sheet 1

was a highlighting error. The applicant also stated that valve BS VA37 and the tubes in HX-702

provide the in-scope boundary between SW and WD systems. These components are

represented by the "Heaters/Coolers" and "Valve Bodies" component types in LRA

Table 3.3.2-5. According to the applicant, drawing LR-684J971, sheet 1 was revised and the

error is being tracked in its corrective action program.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.4-3

acceptable. Also, since there are no other SW/WD interface components identified on drawing

LR-PBM-231, sheet 1, the staff's concern described in RAI 2.3.3.4-3 is resolved.

RAI 2.3.3.4-4. The following inconsistencies within the WD system designations (shown on the

drawings) were identified:

* The print-to-print inter-tie designator from drawing LR-684J971, sheet 2, location A-8 to

the service water overboard piping on drawing LR-M-207, sheet 3 is not designated as

within the scope of license renewal.

* Drawing LR-684J971, sheet 2, at location C-8 indicates that the piping upstream of

valve RWM-1 249A as within the scope of license renewal. This is not consistent with

drawing LR-PBM-231, sheet 1.

* Drawing LR-684J971, sheet 1, identifies the piping segment upstream of line

1 -inch-WD-1 51 R-1 5 at location E-9 and the piping segment downstream of isolation

valve 1708 at location F-9 as within the scope of license renewal. The basis for this

determination needs to be explained.

Failure of the above components currently designated as outside the scope of license renewal

could have an adverse impact on the intended functions of the WD system. In RAI 2.3.3.4-4,

dated November 16, 2004, the staff requested the applicant to clarify its determination as to

which WD system components, as described above, are within the scope of license renewal.

In its response, dated December 22, 2004, the applicant stated the following:

* The print-to-print inter-tie designator on drawing LR-684J971, sheet 2 at location A-8,

should have been highlighted to show it as within the scope of license renewal. The

applicant explained that failure to identify these components as in-scope on the above

drawing was an error, and that the continuation on LR-M-207 shows all necessary

components that are in-scope. According to the applicant, drawing LR-684J971,

sheet 2 was revised and the error is being tracked in its corrective action program.

* Failure to identify the piping upstream of valve RWM-1 249A as in-scope on drawing

LR-PBM-231, sheet 1, was a drawing error. The valve RWM-1 249A and its associated

piping are within the scope of license renewal and represented by the Valve Bodies"

and Piping and Fittings component types in LRA Table 3.3.2-4.

* Based on 10 CFR 54.4(a)(2) criteria, these piping segments were identified to be within

the scope of license renewal during a plant walkdown, and are shown in LRA

Table 2.1.2.1-1, page 2-28, second line-item from the bottom. The applicant determined

that there was a potential for leakage or spray that could affect the safety-related

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equipment. Additionally, the transition from in-scope to out-of-scope piping shown on

drawing LR-684J971, sheet 1 is intended to show the points where the branch lines exit

the room or area containing safety-related equipment.

Based on the above discussion, the staff found the applicant's responses to RAI 2.3.3.4-4

acceptable. The applicant clarified that failure to identify the discussed components as within

the scope of license renewal was a drawing error. Therefore, the staff's concerns described in

RAI 2.3.3.4-4 are resolved.

2.3.3.4.3 Conclusion

The staff reviewed the LRA, accompanying scoping boundary drawings, the April 29, 2005,

letter, and the RAI responses described above to determine whether any SSCs that should be

within the scope of license renewal were not identified by the applicant. No omissions were

identified. In addition, the staff performed a review to determine whether any of the

components that should be subject to an AMR were not identified by the applicant. No

omissions were identified. On the basis of its review, the staff concluded that there is

reasonable assurance that the applicant adequately identified the WD system components that

are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant

adequately identified the WD system components that are subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.3.3.5 Service Water System

2.3.3.5.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.5, the applicant described the service water (SW) system. The SW

system provides cooling water to various essential and non-essential services throughout the

plant. The six motor-driven SW pumps take their suction from the pump bays in the circulating

water pump house (CW PH), draw raw water from Lake Michigan, and discharge it into a loop

supply header. This supply header is capable of being split, via isolation valves, into two

separate headers. Essential services are capable of being supplied from either header.

Non-essential services are capable of being automatically isolated from the supply headers.

The return lines discharge to the cooling water discharge in Unit 1 and/or Unit 2. Under the

conditions of a LOCA, the SW system can provide the necessary cooling capacity for the

essential heat loads of the affected unit and supply SW for the normal operation of the

unaffected unit (this situation describes the most limiting heat load for the SW system).

The portions of the SW system containing components subject to an AMR extend from the

pump bays to the circulating water discharge, including connections to the suction of the

auxiliary feedwater (AFW) pumps, or the fire protection system; and includes pumps, heat

exchangers, strainers, piping, and valves.

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Functions associated with the SW system include the following:

* provides an emergency supply of water to the AFW pumps when the normal condensate

supply is exhausted

* provides heat removal from and/or a pressure boundary for safety-related heat

exchangers

* provides a primary containment boundary to prevent the release of radioactivity into the

environment

* provides for emergency heat removal from the primary containment

* provides pressure control

* maintains emergency temperatures within areas containing safety Class 1, 2, and 3

components, including the primary auxiliary building battery room and HVAC heat

exchangers in the essential ventilation system

* provides cooling water to spent fuel pool cooling water heat exchanges for decay heat

removal

The failure of nonsafety-related SSCs in the system could prevent the satisfactory

accomplishment of a safety-related function. In addition, the SW system performs functions

that support fire protection.

Intended functions within the scope of license renewal include the following:

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

* provides for mechanical closure integrity on bolted joints

* provides for filtration

* provides for heat transfer

* provides for flow restriction

In LRA Table 2.3.3-5, the applicant identified the following SW system component types that

are within the scope of license renewal and subject to an AMR:

* CS components * instrument valve assemblies

* expansion joints * piping and fittings.

* fasteners and bolting * pump casing

* filters and strainers * radiation monitor

* flow elements - restricting orifices

* flow indicators sight glass

* heat exchanger * thermowells

* heaters and coolers * valve bodies

* hose reel

2.3.3.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.5 and FSAR Section 9.6. The staff's review, using the

evaluation methodology described in SER Section 2.3, was conducted in accordance with the

guidance described in NUREG-1800, Section 2.3.

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In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had

identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR in

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

The staff's review of LRA Section 2.3.3.5 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAls as discussed below.

RAI 2.3.3.5-1. FSAR Section 9.6 states that the SW system shall provide sufficient flow to

support the heat removal requirements of components required to mitigate the consequences

of a LOCA in one unit, while supporting the normal flow of the unaffected unit. Drawing

LR-M-207, sheet 1 A shows three pipe stubs without isolation valves off the SW pressure

boundary (listed below) as not within the scope of license renewal. LRA Section 2.3.3.5 states

that the SW piping and fittings are in-scope as a pressure boundary. Failure of these sections

of piping could affect the pressure boundary function of the SW system. In RAI 2.3.3.5-1,

dated November 10, 2004, the staff requested the applicant to justify why the three piping areas

listed below are not within the scope of license renewal and subject to an AMR:

(1) cap on 4-inch-JB-2 piping, location G-5

(2) pipe stub and cap downstream of valve SW-48, location C-4

(3) pipe stub and cap downstream of valve SW-57, location D-4

In its response, dated December 14, 2004, the applicant stated that the piping and fittings in

RAI-2.3.3.5-1 not shown as within the scope of license renewal on drawing LR-M-207, sheet 1 A

are highlighting errors. According to the applicant, these components are considered to be

in-scope and are represented in LRA Table 3.3.2-5 under the "Piping and Fittings" component

type, and managed by the open-cycle cooling water system aging management program.

Additionally, the applicant stated that the above drawing was revised and the errors are being

tracked in its corrective action program.

Based on the abovediscusslon, the staff found the applicant's response to RAI 2.3.3.5-1

acceptable. The applicant confirmed that three piping areas identified in the RAI are within the

scope of license renewal. Therefore, the staff's concerns described in RAI 2.3.3.5-1 are

resolved.

RAI 2.3.3.5-2. SW drawing LR-M-207, sheets 1, 2, and 3, show seven valve actuators as

outside the scope of license renewal. LRA Section 2.3.3.5 states that the SW valve bodies are

in-scope as a pressure boundary. The seven valve actuators are not shown in a manner that is

consistent with other similar valves in the SW system. In RAI 2.3.3.5-2, dated

November 10, 2004, the staff requested to clarify which portions of these seven valves (listed

below) have pressure boundary functions, and should be within the scope of license renewal

and subject to an AMR.

(1) Actuator for BS-291 1, drawing LR-M-207, sheet 1, location G-3

(2) Actuator for valve SW- -401 G, drawing LR-M-207, sheet 2, location F-7

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(3) Actuator for strainer Z-1 04A, drawing LR-M-207, sheet 2, location G-6

(4) Actuator for valve SW-12A, drawing LR-M-207, sheet 3, location E-9

(5) Actuator for valve TCV-12B, drawing LR-M-207, sheet 3, location E-7

(6) Actuator for valve TCV-1 2C, drawing LR-M-207, sheet 3, location E-7

(7) Actuator for valve SW- 2D, drawing LR-M-207, sheet 3, location E-6

In its response, dated December 14, 2004, the applicant stated that the pressure boundary

portion (valve body or strainer body) of all the valves listed in RAI-2.3.3.5-2, Items 1-7 are

identified as within the scope of license renewal and are being age-managed as noted in the

applicable line items of LRA Table 3.3.2-5. The applicant also stated that the actuators would

not affect the pressure boundary function of these components and that these actuators were

originally shown to be out-of-scope based on their CLB functions. The applicant provided the

following details:

1 The motor operators for Zurn strainers BS-2911 and BS-2912 were originally considered

to be outside the scope of license renewal based on the PBNP 0-list (ie., CLB).

According to the applicant, this CLB position is being evaluated, and should this change

in the future to show these operators/actuators as within the scope of license renewal,

no aging management would be required as these operators are active components.

However, the bodies of these strainers were originally included within the scope of

license renewal, and are represented in LRA Table 3.3.2-5 by the 'Filters/Strainers'

component type, which have both a 'Pressure Boundary" and a "Provide Filtration"

component intended function.

2, 3 These two actuators are associated with the nonsafety-related Zum strainer that

supplies non-essential SW to the Unit 1 Turbine Hall loads. Because of their location in

the auxiliary feedwater (AFW) pump room and their potential to affect safety-related

equipment in this room via water leakage, spray, or flooding, these components were

shown to be within the scope of license renewal due to 10 CFR 54.4(a)(2) criterion. The

only license renewal intended function, therefore, is pressure boundary, which is

addressed in LRA Table 3.3.2-5 under the "Valve Bodies" and "Filters/Strainers"

component types. These actuators have no effect on the pressure boundary and are,

therefore, outside the scope of license renewal and not subject to an AMR.

4 - 7 These four actuators are for flow control valves SW-1 2A, TCV-12B, TCV-12C, and

SW- 2D that are used to control CCW outlet temperatures by throttling SW flow through

the CCW heat exchangers. All these actuators are fail-open, and were determined not

to have the potential to affect the pressure boundary of respective valve body.

According to the applicant, even if these actuators were considered to be within the

scope of license renewal, since they are active components, no aging management

would be required. The pressure boundary portions (ie., valve bodies) for all four of

these valves are in-scope, and are represented by the "Valve Bodies" component type in

LRA Table 3.3.2-5.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.5-2

acceptable. The applicant clarified that each of the valve actuators listed in the RAI is

non-pressure retaining active component, and their failure will not affect the pressure retaining

capabilities of the associated components. The staff also agrees that because these motor

operators/actuators are non-pressure retaining active components, no passive component

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aging management program is required. Therefore, the staff's concerns described in

RAI 2.3.3.5-2 are resolved.

RAI 2.3.3.5-3. FSAR Section 9.6.2 states that the SW system, serving both units, supplies

cooling water to equipment in the steam plant, to the containment ventilation coolers and to

reactor auxiliary systems. Non-essential services in each unit receive water from their

respective SW header (north or south). Drawing LR-M-207, sheet 2 shows equipment around

strainer Z-1 04A as within the scope of license renewal. LRA Section 2.3.3.5 states that

portions of the SW system contain components subject to an AMR. These components extend

from the pump bays to the circulating water discharge, including connections to the suction of

the AFW pumps, or the fire protection system, including pumps, heat exchangers, strainers,

piping, and valves. The staff determined that the transition location from out-of-scope to

in-scope is not clearly marked for the following two locations:

(1) 3-inch-JB-1, drawing LR-M-207, sheet 2, location F-6

(2) 6-inch-JB-1, drawing LR-M-207, sheet 2, location F-7

In RAI 2.3.3.5-3, dated November 10, 2004, the staff requested the applicant to clarify the exact

locations of these two transitions and which sections are within the scope of license renewal.

In its response, dated December 14, 2004, the applicant stated that the piping sections

identified in RAI 2.3.3.5-3, Items 1 and 2 are associated with the nonsafety-related Zum strainer

Z-1 04A that supplies non-essential SW to the Unit 1 turbine hall loads. Because of their

location in the AFW pump room and their potential to affect safety-related equipment in this

room via leakage, spray, or flooding, the applicant stated that these piping and associated

components were shown to be within the scope of license renewal pursuant to

10 CFR 54.4(a)(2). The applicant stated that the in-scope portions of these nonsafety-related

piping sections, although difficult to show on a drawing, were determined by plant walkdown,

and the transition locations shown on drawing LR-M-207, sheet 2 represent the points where

the piping exited the AFW pump room.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.5-3

acceptable. The applicant verified, by plant walkdown, that the in-scope portions of the

non-essential SW piping and components identified on drawing LR-M-207, sheet 2 were

consistent with plant as-built configurations, and that the failure of the out-of-scope piping

pressure boundary will not impact the intended functions of the safety-related equipment in the

AFW pump room. Therefore, the staff's concerns described in RAI 2.3.3.5-3 are resolved.

RAI 2.3.3.5-4. FSAR Section 9.6.1 states that the SW system shall provide sufficient flow to

the spent fuel pool heat exchangers to provide adequate heat removal of spent fuel decay heat.

On drawing LR-M-207, sheet 3, with regard to the piping downstream of valve SW-750,

location C-7, the marking is not legible as to whether this piping is within, or outside the scope

of license renewal. In RAI 2.3.3.5-4, dated November 10, 2004, the staff requested the

applicant to clearly show which sections are within the scope of license renewal and which are

not within the scope of license renewal.

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In its response, dated December 14, 2004, the applicant stated that the piping components

downstream of valve SW-750 are a pipe stub and cap. SW-750 is a normally closed valve, and

the downstream pipe stub and cap are not within the scope of license renewal, since they have

no license renewal intended function.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.54

acceptable, and is consistent with accepted practices for establishing scope transition

boundaries. Therefore, the staff's concern described in RAI 2.3.3.5-4 is resolved.

RAI 2.3.3.5-5. FSAR Section 9.6 states that the return from the SW system is directed to the

return line of the circulating water (CW) system. Drawing LR-M-207, sheet 1 shows SW system

piping 20-inch-JB-2 returning to the CW system as within the scope of license renewal. LRA

Section 2.3.3.5 states that much of the SW return header is not safety-related, but it was

included in-scope up to manual isolation valves, pursuant 10 CFR 54.4(a)(2). The transition

location from in-scope (SW system) to out-of-scope (CW system) is not clearly marked at the

following two locations:

(1) 20-inch-JB-2, drawing LR-M-212, sheet 1, location F-8

(2) 20-inch-JB-2, drawing LR-M-2212, location A-7

In RAI 2.3.3.5-5, dated November 10, 2004, the staff requested the applicant to clarify the exact

locations of these two transitions to clearly show which sections are within, and which are

outside the scope of license renewal.

In its response dated December 14, 2004, the applicant identified a highlighting error on

drawings LR-M-212, sheet 1 and LR-M-2212 where the two transition locations identified were

not clearly marked to depict the in-scope and out-of-scope sections of the piping. According to

the applicant, the SW return header is within the scope of license renewal up to the CW system

return header. This transition is not a valve, since the CW return header is buried underground.

Regarding the statement N.. . much of the SW return header is not safety-related, but was

included in-scope up to manual isolation valves per Criterion 2 (10 CFR 54.4(a)(2))," the

applicant stated that it was intended for above-ground piping components where there could be

leakage, spray, or flooding effects. The drawings LR-M-212, sheet 1 and LR-M-2212 were

revised and the errors are being tracked in the applicant's corrective action program. The

applicant further stated that the CW return header is outside the scope of license renewal as

there is no credible age-related failure of the CW return header that could affect the SW

system.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.5-5

acceptable. The applicant adequately identified those SW system return header sections that

are within the scope of license renewal. Also, the applicant addressed its corrective action

program in updating its drawings for the two in-scope transition locations. Therefore, the staff's

concerns described in RAI 2.3.3.5-5 are resolved.

2.3.3.5.3 Conclusion

The staff reviewed the LRA, accompanying scoping boundary drawings, and the RAI responses

described above to determine whether any SSCs that should be within the scope of license

renewal were not identified by the applicant. No omissions were identified. In addition, the staff

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performed a review to determine whether any of the components that should be subject to an

AMR were not identified by the applicant. No omissions were identified. On the basis of its

review, the staff concluded that there is reasonable assurance that the applicant adequately

identified the SW system components that are within the scope of license renewal, as required

by 10 CFR 54.4(a), and that the applicant adequately identified the SW system components

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

2.3.3.6 Fire Protection System

2.3.3.6.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.6, the applicant described the fire protection (FP) system. The FP system

provides assurance, through defense-in-depth design, that a fire will not prevent the

performance of necessary safe-shutdown functions, or significantly increase the risk of the

release of radioactivity to the environment during a fire. The FP system provides fire

suppression by fixed water-spray and sprinkler systems, fixed gas systems, hose stations, and

portable extinguishers located in various areas of the PBNP site. A fire detection and alarm

subsystem locally alerts selected areas of the plant and transmits various alarm, supervisory,

and trouble signals to the control room. The FP system receives its water supply from Lake

Michigan.

The FP system also provides alternate sources of backup water to other plant systems. The

FP system supports SBO activities by providing a backup supply of bearing cooling water to the

turbine-driven auxiliary feedwater pumps. It can also provide a backup source of water

inventory to the spent fuel pool, or a backup supply of feedwater through the use of the

diesel-driven fire pump and routing of a fire hose between existing connections on the fire

header and the condensate storage tanks. These secondary functions of the FP system do not

prohibit the system from performing its primary functions.

The portions of the FP system subject to an AMR include: pumps, piping, valves, accumulator,

hose stations, hydrants, spray/sprinkler heads, nozzles, fuel oil day-tank, fuel oil supply to the

diesel-driven fire pump, halon gas cylinders, and reactor coolant pump (RCP) oil collection

components.

The failure of nonsafety-related SSCs in the system could prevent the satisfactory

accomplishment of a safety-related function.

Intended functions within the scope of license renewal include the following:

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

* provides for mechanical closure integrity on bolted joints

* -provides for filtration

* provides fire protection, as through flame suppression

* provides for heat transfer

* provides for flow control or distribution, as through a spray nozzle

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In LRA Table 2.3.3-6, the applicant identified the following FP system component types that are

within the scope of license renewal and subject to an AMR:

* accumulators and cylinders * instrument valve assemblies

* compressor casing * piping and fittings

* CS components * pump casing

* expansion joints * RCP oil collection

* fasteners and bolting * sight glass

* filters and strainers * spray nozzles

* fire hydrant * sprinkler heads

* flame arrestors * tanks

* heat exchanger * valve bodies

* hose reel

2.3.3.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.6, FSAR Section 9.10, and Fire Protection Evaluation

Report (FPER), Revision 3. The staff's review, using the evaluation methodology described in

SER Section 2.3, was conducted in accordance with the guidance described in NUREG-1 800,

Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had

identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR in

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

In addition, the staff reviewed the Units 1 and 2 FPER, Revision 3, April 2004, approved fire

protection SER, dated August 2, 1979, and its fire protection SER supplements. These reports

are referenced in its fire protection CLB, which summarizes the fire protection program and its

commitments to 10 CFR 50.48 using the guidance of Branch Technical Position (BTP) Auxiliary

and Power Conversion Systems Branch (APCSB) 9.5-1, Appendix A, dated August 23, 1976.

The staff's review of LRA Section 2.3.3.6 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAls as discussed below.

RAI 2.3.3.6-1. The NRC's "Fire Protection Safety Evaluation Report" dated August 2, 1979,

Section 4.3.1, addresses 13 hose stations in various areas of the plant, which do not appear in

the LRA drawings. In RAI 2.3.3.6-1, dated September 10, 2004, the staff requested the

applicant to verify whether these stations are within the scope of license renewal in accordance

with 10 CFR 54.4(a) and subject to an AMR in accordance with 10 CFR 54.21 (a)(1). If they

are, they should be included in LRA Tables 2.3.3-6 and 3.3.2-6. If they are excluded from the

scope of license renewal and not subject to an AMR, then the applicant was requested to

provide justification for the exclusion.

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In its response, dated October B,2004, the applicant stated that the 13 hose stations identified

in Section 4.3.1 of the above referenced NRC SER are hose reels HR-35 through HR-47.

All 13 of these hose stations are identified on drawing LR-M-208 sheet 2, locations B5, B6, C8,

D7, and E4. All of these hose reels are shown to be within the scope of license renewal in

accordance with 10 CFR 54.4(a), subject to an AMR in accordance with 10 CFR 54.21(a)(1),

and are represented in LRA Tables 2.3.3-6 and 3.3.2-6 under the component type "hose reel."

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.6-1

acceptable. Hose stations have been identified, located and discussed; additionally, the AMR

requirements have been identified. Therefore, the staff's concern described in RAI 2.3.3.6-1 is

resolved.

RAI 2.3.3.6-2. The NRC's "Fire Protection Safety Evaluation Report" dated August 2, 1979,

Sections 4.3.1 and 4.5 addresses floor drains. In drawings LR-M-208 sheet 1, floor drains at

location D3 and LR-M-208 sheet 15, floor drains at locations C6, C7, E6, E7, E8, F6, F8, and

F9 are not highlighted as portions of the flow diagram within the scope of license renewal and

subject to an AMR. In RAI 2.3.3.6-2, dated September 10,2004, the staff requested the

applicant to verify whether these floor drains are within the scope of license renewal in

accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with

10 CFR 54.21 (a)(1). If they are, the staff requested that they be included in LRA Tables 2.3.3-6

and 3.3.2-6. If they are excluded from the scope of license renewal and not subject to an AMR,

the applicant was requested to provide justification for the exclusion.

In its response, dated October 8, 2004, the applicant stated that the drains identified on

drawings, LR-M-208 sheet 1 and LR-M-208 sheet 15 are drains from the piping system, not

floor drains. These are not within the scope of license renewal in accordance with

10 CFR 54.4(a) because they are downstream of normally shut isolation valves.

The applicant further stated that floor drains are considered in the flooding analysis review that

was performed as part of Criterion 2, scoping methodology (reference LRA Section 2.1.2.1.2).

This resulted in the highlighted drain lines being included within the scope of license renewal in

accordance with 10 CFR 54.4(a) and subject to aging management in accordance with

10 CFR 54.21 (a)(1) (reference LRA Table 2.1.2.1 -1, pages 2-25 and 2-26).

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.6-2

acceptable. Pipe drains serve no pressure boundary function and they are downstream of

normally closed isolation valves; therefore, they are not subject to an AMR. The staff's concern

described in RAI 2.3.3.6-2 is resolved.

RAI 2.3.3.6-3. The NRC's "Fire Protection Safety Evaluation Report" dated August 2, 1979,

Section 4.3.1, addresses the dry pipe automatic sprinkler systems for "Warehouse" and

"Compressor Building" and deluge automatic sprinkler with fusible-link actuation in "Control

Room Emergency Ventilation System Charcoal Filters," which do not appear in the LRA

drawings. In RAI 2.3.3.6-3, dated September 10,2004, the staff requested the applicant to

verify whether these fire suppression systems and components are within the scope of license

renewal in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with

10 CFR 54.21 (a)(1). If they are, the staff requested that they be included in LRA Tables 2.3.3-6

and 3.3.2-6. If they are excluded from the scope of license renewal and not subject to an AMR,

the applicant was requested to provide justification for the exclusion.

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In its response, dated October 8, 2004, the applicant stated that, as described in the referenced

SER, the dry pipe automatic sprinkler systems were in the following buildings: "Warehouse' and

Compressor Building." These equate to warehouse #1 and warehouse #2 in PBNP current

terminology. Warehouse #1 is no longer a dry pipe system, as it was converted to a wet pipe

system, as shown on drawing LR-M-208 sheet 1, location B4. Warehouse #2 is still a dry pipe

system, as shown on drawing LR-M-208 sheet 1, location B8.

The deluge automatic sprinkler with fusible-link actuation in the control room emergency

ventilation system charcoal filters is shown on drawing LR-M-208 sheet 2, location F7 (F-i 6

Charcoal Filter).

As shown on the referenced drawings, these portions of the FP system are within the scope of

license renewal in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with

10 CFR 54.21(a)(1). These are represented in LRA Tables 2.3.3-6 and 3.3.2-6 by component

types "piping and fittings" and "valve bodies."

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.6-3

acceptable. The applicant adequately explained that the sprinkler systems in question are

within the scope of license renewal in accordance with 10 CFR 54.4(a) and are subject to an

AMR in accordance with 10 CFR 54.21 (a). Therefore, the staff's concern described in

RAI 2.3.3.6-3 is resolved.

RAI 2.3.3.6-4. The NRC's "Fire Protection Safety Evaluation Report" dated August 2, 1979,

Section 4.3.1, addresses the foam extinguishing system for two above-ground fuel oil storage

tanks, which does not appear in the drawings. In RAI 2.3.3.6-4, dated September 10, 2004, the

staff requested the applicant to verify whether this foam suppression system and components

are within the scope of license renewal in accordance with 10 CFR 54.4(a) and subject to an

AMR in accordance with 10 CFR 54.21(a)(1). If they are, the staff requested that they be

included in LRA Tables 2.3.3-6 and 3.3.2-6. If they are excluded from the scope of license

renewal and not subject to an AMR, the applicant was requested to provide justification for the

exclusion.

In its response, dated October 8, 2004, the applicant stated that the foam extinguishing system

for the above-ground fuel oil storage tanks has been removed and, therefore, is not within the

scope of license renewal.

The foam extinguishing system was removed via a plant modification (MR 94-075), which

included a 10 CFR 50.59 evaluation (SER 95-078). A fire protection technical evaluation was

also performed with this modification in order to determine the impact of this modification on the

previously approved NRC fire protection configurations. This evaluation concluded that

although the foam extinguishing system was installed and referenced at the time of the NRC's

fire protection safety evaluation report, it was not considered necessary to meet the guidelines

of Appendix A to Branch Technical Position (BTP) 9.5-1. The guidelines specified a separation

distance between fuel oil storage tanks and structures that house safety-related equipment.

This criterion was met without the need of the foam extinguishing system.

Additionally, the above-ground fuel oil storage tanks no longer supply fuel oil to the

safety-related diesel generators. Two below-ground fuel oil storage tanks were installed during

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the modification to add two new diesel generators. These below-ground tanks are capable of

supplying fuel oil to any and all of the four diesel generators in the event of an Appendix R fire.

Alternative fire protection methods in the form of manual fire fighting using portable foam

generating equipment is considered to provide an acceptable and adequate level of fire

protection for the potential fire hazard presented by the fuel oil storage tanks.

The FSAR and FPER were updated when this modification was completed. FPER

Section 7.3.10 details the current configuration of the fuel oil storage areas at the plant.

The foam extinguishing system for the two above-ground fuel oil storage tanks no longer exists

and, therefore, is not considered to be within the scope of license renewal in accordance with

10 CFR 54.4(a) and is not subject to an AMR in accordance with 10 CFR 54.21 (a)(1).

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.6-4

acceptable. The applicant adequately explained that the foam system for two above-ground

fuel oil storage tanks in question is not within the scope of license renewal in accordance with

10 CFR 54.4(a) and subject to an AMR accordance with 10 CFR 54.21 (a), because it was

removed. Therefore, the staff's concern described in RAI 2.3.3.6-4 is resolved.

RAI 2.3.3.6-5. The NRC's "Fire Protection Safety Evaluation Report" dated August 2, 1979,

Section 4.3.2, addresses the carbon dioxide (C02) suppression system in the remote gas

turbine building and the Halon 1301 suppression system in the record storage vault, which do

not appear in the LRA drawings. In RAI 2.3.3.6-5, dated September 10, 2004, the staff

requested the applicant to verify whether these gaseous fire suppression systems and

components are within the scope of license renewal in accordance with 10 CFR 54.4(a) and

subject to an AMR in accordance with 10 CFR 54.21 (a)(1). If they are, the staff requested that

they be included in LRA Tables 2.3.3-6 and 3.3.2-6. If they are excluded from the scope of

license renewal and not subject to an AMR, the applicant was requested to provide justification

for the exclusion.

In its response, dated October 8, 2004, the applicant stated that the record storage vault that

had a Halon 1301 suppression system was located in the original energy information center

building. This building was demolished to make way for a new training building and nuclear

engineering services (NES) building. A record storage vault now exists in the NES building, but

it no longer has a Halon suppression system (reference Section 7.3.16 of PBNP FPER,

Revision 3). The above-referenced Halon 1301 suppression system no longer exists and,;

therefore, is not within the scope of license renewal. The NES and training buildings are i

supplied with firewater sprinkler systems fed from the plant fire header (reference drawing [

LR-M-208 sheet 1, location E2). However, since these buildings are more than 500 feet away T

from the plant protected area (such that fires in these buildings could not affect safety-related

equipment within the plant) and have the capability to be isolated from the plant fire header, the

FP systems for these buildings were judged to be not within the scope of license renewal.

The CO2 suppression system in the gas turbine building was removed (for safety reasons) and

replaced with a pre-action water sprinkler system. This is shown on LR-M-208 sheet 9,

location ElO. This pre-action water sprinkler system is within the scope of license renewal in

accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with

10 CFR 5421 (a)(1). This pre-action water sprinkler system is represented in LRA

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Tables 2.3.3-6 and 3.3.2-6 by component types 'piping and fittings," "sprinkler heads," and

Evalve bodies."

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.6-5

acceptable. The applicant adequately explained that the CO2 suppression system in question,

was removed and replaced with a pre-action water sprinkler system. The new system is within

the scope of license renewal in accordance with 10 CFR 54.4(a) and subject to an AMR

accordance with 10 CFR 54.21 (a). The staff concluded that the pre-action water sprinkler

system components were correctly included within the scope of license renewal and subject to

an AMR. Therefore, the staff's concern described in RAI 2.3.3.6-5 is resolved.

RAI 2.3.3.6-6. PBNP "Fire Protection Evaluation Report," Revision 3, April 2004, Section 5.1.4,

states that "protection of exposed structural steel in other plant areas is provided by sprayed-on

fire proofing material." No reference is made to it in the LRA Section 2.3.3.6, "Fire Protection

Systems" or Section 2.4.11, "Fire Barrier Commodity Group." This appears to be a PBNP

license condition. In RAI 2.3.3.6-6, dated September 10, 2004, the staff requested the

applicant to clarify where this fire proofing material is addressed in the LRA scoping, screening,

and AMR sections.

In its response, dated October 8, 2004, the applicant stated that LRA Section 2.4.11, "Fire

Barrier Commodity Group," discusses fire stops and fire wraps. The term fire wrap is

associated with fire barriers and their penetrations. The term fire stop is associated with an

enveloping construction of fireproofing material. During original plant design, where structural

steel fireproofing was required, masonry brick was applied. Subsequently, modifications have

been performed where the masonry brick was replaced with a rigid board wrap at some

locations. The LRA represents these materials with a calcium silicate board or ceramic

fiberboard component group designation.

More recent plant modifications have employed a fire wrap using a cementitious fireproofing

that is spray applied. LRA Section 2.4.11 uses the generic silicone-based material component

group to represent all sprayed-on mastic fireproofing materials. The number of applications of

this type of fireproofing is limited. The aging management review for the fire-proofing materials

is presented in LRA Table 3.5.2-11.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.6-6

acceptable. The applicant adequately explained that the sprayed-on fire-proofing materials on

structural steel in question are within the scope of license renewal in accordance with

10 CFR 54.4(a) and subject to an AMR accordance with 10 CFR 54.21 (a). LRA Section 2.4.11

uses the generic silicone-based material component group to represent all sprayed-on mastic

fireproofing materials. Therefore, the staff's concern described in RAI 2.3.3.6-6 is resolved.

RAI 2.3.3.6-7. PBNP "Fire Protection Evaluation Report," Revision 3, April 2004, Section 5.1.9,

addresses the Units 1 and 2 fire suppression system for outdoor transformers. However,

drawing LR-M-208 sheet 9 depicts the fire suppression system for "1, 2-X04 Transformers." In

RAI 2.3.3.6-7, dated September 10, 2004, the staff requested the applicant to explain whether

the above drawing includes the fire suppression system for the Units 1 and 2 outdoor

transformers.

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In its response, dated October 8, 2004, the applicant stated that drawing LR-M-208 sheet 9,

location C2, references 01, 2-X04 Transformers." This refers to the Unit 1 and Unit 2 X04

transformers, which are the outdoor, low-voltage station auxiliary transformers, located west of

the primary auxiliary building. Both units' transformers are protected by this portion of the FP

system shown on this drawing due to their close proximity to each other.

Additionally, as noted in PBNP FPER Section 5.1.9, the deluge systems for the Unit I main and

auxiliary transformers are shown on drawing LR-M-208 sheet 2, location F1, and deluge

systems for the Unit 2 main and unit auxiliary transformers are shown on drawing LR-M-208

sheet 2, location D9.

All of the piping and components for these transformers' deluge systems are within the scope of

license renewal in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with

10 CFR 54.21 (a)(1).

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.6-7

acceptable. The applicant identified and explained the fire suppression system for "1I, 2-X04

Transformers," which are the outdoor low-voltage station auxiliary transformers, located west of

the primary auxiliary building. The staff concluded that the fire suppression systems in question

were correctly included within the scope of license renewal and subject to an AMR. Therefore,

the staff's concern described in RAI 2.3.3.6-7 is resolved.

RAI 2.3.3.6-8. PBNP "Fire Protection Evaluation Report," Revision 3, April 2004, Section 5.5.1,

addresses a fixed smoke and heat removal system for computer and instrument rack room,

control room, and cable spreading, which does not appear in the LRA drawings. In

RAI 2.3.3.6-8, dated September 10, 2004, the staff requested the applicant to verify whether

this smoke and heat removal system and its components are within the scope of license

renewal in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with

10 CFR 54.21 (a)(1). If they are, the staff requested that they be included in LRA Tables 2.3.3-6

and 3.3.2-6. If they are excluded from the scope of license renewal and not subject to an AMR,

the applicant was requested to provide justification for the exclusion.

In its response, dated October 8, 2004, the applicant stated that the smoke and heat removal

system is essentially a ventilation system, as shown on drawing LR-M-1 44 sheet 2, location H2.

This smoke and heat removal system is within the scope of license renewal in accordance with

10 CFR 54.4(a) and subject to an AMR in accordance with 10 CFR 54.21 (a)(1). The essential

ventilation system is represented by component types "ductwork" and "fan/blower housing" in

LRA Section 2.3.3.10 and Table 3.3.2-9.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.6-8.

acceptable. The applicant adequately explained and identified that the smoke and heat

removal system in question is within the scope of license renewal in accordance with

10 CFR 54.4(a) and subject to an AMR in accordance with 10 CFR 54.21 (a). The staff

concluded that the smoke and heat removal system in question was correctly included within

the scope of license renewal and subject to an AMR in the drawing LR-M-144 sheet 2,

location H2 and LRA Tables 2.3.3.10 and 3.3.2-9. Therefore, the staff's concern described in

RAI 2.3.3.6-8 is resolved.

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RAI 2.3.3.6-9. PBNP "Fire Protection Evaluation Report," Revision 3, April 2004, Section 6.4.1,

addresses the Halon 1301 suppression system for the plant battery rooms, which does not

appear in the drawings. In RAI 2.3.3.6-9, dated September 10, 2004, the staff requested the

applicant to verify whether the Halon 1301 suppression system and its components are within

the scope of license renewal in accordance with 10 CFR 54.4(a) and subject to an AMR in

accordance with 10 CFR 54.21 (a)(1). If they are, they should be included in LRA

Tables 2.3.3-6 and 3.3.2-6. If they are excluded from the scope of license renewal and not

subject to an AMR, the applicant was requested to provide justification for the exclusion.

In its response, dated October 8, 2004, the applicant stated that the battery rooms referenced

in Section 6.4.1 of the PBNP FPER are the two small battery rooms adjacent to the vital

switchgear room. Although drawing LR-M-208 sheet 5, location El 0, does not specifically

mention 0Battery Rooms," the Halon 1301 suppression system for the vital switchgear room

also covers the battery rooms. This Halon suppression system is within the scope of license

renewal in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with

10 CFR 54.21 (a)(1). This system is represented in LRA Tables 2.3.3-6 and 3.3.2-6 by

component types "piping and fittings" and "valve bodies" with an air/gas internal environment.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.6-9

acceptable. The applicant adequately identified and explained that the Halon 1301 suppression

system and its components in question are within the scope of license renewal and subject to

an AMR. The Halon 1301 suppression system for the vital switchgear room also covers the

battery rooms. The staff concluded that the battery rooms Halon 1301 suppression system in

question was correctly included within the scope of license renewal and subject to an AMR.

Therefore, the staff's concern described in RAI 2.3.3.6-9 is resolved.

RAI 2.3.3.6-10. PBNP "Fire Protection Evaluation Report," Revision 3, April 2004,

Section 6.5.1, addresses the dry chemical suppression system for the plant turbine-generator

bearings and the gas turbine-generator exhaust, which does not appear in the LRA drawings.

In RAI 2.3.3.6-10, dated September 10, 2004, the staff requested the applicant to verify

whether the dry chemical suppression system and its components are within the scope of

license renewal in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with

10 CFR 54.21 (a)(1). If they are, the staff requested that they be included in LRA Tables 2.3.3-6

and 3.3.2-6. If they are excluded from the scope of license renewal and not subject to an AMR,

the applicant was requested to provide justification for the exclusion.

In its response, dated October 8, 2004, the applicant stated that the dry chemical suppression

system for the turbine-generator bearings and the gas turbine exhaust bearing are not shown

on a plant drawing and, therefore, were not included in the drawings. The applicant stated that

the dry chemical suppression system for the turbine-generator bearings and the gas turbine

exhaust bearing, however, are within the scope of license renewal in accordance with

10 CFR 54.4(a). The dry chemical containers are managed similar to a fire extinguisher, where

they are routinely monitored, and replaced as needed (reference LRA Section 2.1.3.1.3,

"Identification of Short-lived Components and Consumables"). The fixed components subject to

aging management are represented by component types "piping and fittings," uspray nozzles,"

and valve bodies" in LRA Tables 2.3.3-6 and 3.3.2-6.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.6-10

acceptable. The applicant adequately explained the dry chemical suppression system for the

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turbine-generator bearings and the gas turbine exhaust bearing in question are within the scope

of license renewal and subject to an AMR. The dry chemical containers are managed similar to

a fire extinguisher; they are routinely monitored, and replaced as needed. The staff agreed that

the dry chemical containers are short-lived components and consumables and are not subject

to an AMR. Therefore, the staff's concern described in RAI 2.3.3.6-10 is resolved.

RAI 2.3.3.6-11. PBNP "Fire Protection Evaluation Report," Revision 3, April 2004,

Section 6.5.2, addresses fixed C02 hose reel stations in the control room, which do not appear

in the drawings. In RAI 2.3.3.6-11, dated September 10, 2004, the staff requested the

applicant to verify whether the C02 hose reel stations and components are within the scope of

license renewal in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with

10 CFR 54.21 (a)(1). If they are, the staff requested that they be included in LRA Tables 2.3.3-6

and 3.3.2-6. If they are excluded from the scope of license renewal and not subject to an AMR,

the applicant was requested to provide justification for the exclusion.

In its response, dated October 8, 2004, the applicant stated that the C02 hose reel stations in

the control room are not shown on a plant piping and instrumentation diagram (P&ID) and,

therefore, were not included in the drawings. These stations are within the scope of license

renewal in accordance with 10 CFR 54.4(a) but are not subject to an AMR in accordance with

10 CFR 54.21 (a)(1). The C02 containers are managed similar to a fire extinguisher; they are

routinely monitored, and replaced as needed (reference LRA Section 2.1.3.1.3, Identification of

Short-lived Components and Consumables).

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.6-11

acceptable. The components in question (CO2 hose reel stations in the control room) are

short-lived and consumable, routinely monitored, replaced as needed and, therefore, not

subject to an AMR. The staff's concern described in RAI 2.3.3.6-11 is resolved.

RAI 2.3.3.6-12. Electric, diesel, and jockey fire pumps are highlighted on drawing LR-M-208

sheet 1 as falling within the scope of license renewal. However, the highlighting does not trace

the outline of the fire pumps and associated strainers. In RAI 2.3.3.6-12, dated

September 10, 2004, the staff requested the applicant to verify whether the fire pump strainers

are within the scope of license renewal in accordance with 10 CFR 54.4(a) and subject to an

AMR in accordance with 10 CFR 54.21 (a)(1). If they are, the staff requested that they be

included in LRA Tables 2.3.3-6 and 3.3.2-6. If they are excluded from the scope of license

renewal and not subject to an AMR, the applicant was requested to provide justification for the

exclusion.

In its response, dated October 8, 2004, the applicant stated that suction strainers on the pumps

and other filters and strainers throughout the FP system, are shown as falling within the scope

of license renewal in accordance with 10 CFR 54.4(a) on the drawings, and subject to an AMR

in accordance with 10 CFR 54.21 (a)(1). They are represented by the component type

filters/strainersm in LRA Tables 2.3.3-6 and 3.3.2-6.

Based on the above discussion, the staff found applicant's response to RAI 2.3.3.6-12

acceptable. The components in question (fire pump strainers and filters) throughout the FP

systems are within the scope of license renewal in accordance with 10 CFR 54.4(a) and subject

to an AMR in accordance with 10 CFR 54.21 (a). The staff concluded that the components were

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correctly included within the scope of license renewal and subject to an AMR. Therefore, the

staff's concern described in RAI 2.3.3.6-12 is resolved.

RAI 2.3.3.6-13. Drawings LR-M-208 sheets 10 through 14 show the FP system, but do not

indicate any reference to areas of protection provided or type of FP system (i.e., sprinkler

system or other as applicable). In RAI 2.3.3.6-13, dated September 10, 2004, the staff

requested the applicant to identify the areas served by the FP system(s).

In its response, dated October 8, 2004, the applicant stated that LR-M-208 sheets 10

through 14 are for the north service building FP system. The original P&ID indicated as such in

the title, but the title block was changed for the drawing; therefore, that description was lost.

The north service building borders the north end of the Unit 2 turbine building and is within the

plant protected area. The north service building FP system is supplied from the plant fire

header (reference the drawing LR-M-208 sheet 2, location ElO).

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.6-13

acceptable. The applicant adequately described the drawings referenced to areas of

protection. Therefore, the staff's concern described in RAI 2.3.3.6-13 is resolved.

2.3.3.6.3 Conclusion

The staff reviewed the LRA, accompanying scoping boundary drawings, and the RAI responses

described above to determine whether any SSCs that should be within the scope of license

renewal were not identified by the applicant. No omissions were identified. In addition, the staff

performed a review to determine whether any of the components that should be subject to an

AMR were not identified by the applicant. No omissions were identified. On the basis of its

review, the staff concluded that there is reasonable assurance that the applicant adequately

identified the FP system components that are within the scope of license renewal, as required

by 10 CFR 54.4(a), and that the applicant adequately identified the FP system components that

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

2.3.3.7 Heating Steam System

2.3.3.7.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.7, the applicant described the heating steam system. The heating steam

system supports habitability and equipment reliability by maintaining plant area temperatures

within acceptable boundaries. In addition to supporting ventilation functions, the heating steam

system also provides process steam for other plant support functions. The principal

components of the heating steam system consist of the boiler, tanks, pumps, heaters, and

associated piping and valves. The heating steam is provided from the house boilers or from a

connection on the main and auxiliary steam system.

The portions of the heating steam system containing components subject to an AMR include

the heating steam supply and condensate return piping in the primary auxiliary building (PAB),

which includes the heat exchangers, piping, and valves.

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The failure of nonsafety-related SSCs in the system could prevent the satisfactory

accomplishment of a safety-related function.

Intended functions within the scope of license renewal include the following:

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

* provides for mechanical closure integrity on bolted joints

In LRA Table 2.3.3-7, the applicant identified the following heating steam system component

types that are within the scope of license renewal and subject to an AMR:

* CS components * pump casing

* fasteners and bolting * steam traps

* filters and strainers * tanks

* heaters and coolers * valve bodies

* piping and fittings

2.3.3.7.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.7 and the FSAR. The staff's review, using the evaluation

methodology described in SER Section 2.3, was conducted in accordance with the guidance

described in NUREG-1800, Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had

identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR in

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

The staff's review of LRA Section 2.3.3.7 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

RAI 2.3.3.7-1. As described in the LRA, the heating steam system does not perform any

safety-related functions. However, certain portions of the heating steam system are within the

scope of license renewal in accordance with 10 CFR 54.4(a)(2). Portions of the

nonsafety-related heating steam system in the PAB have the potential to affect the function of

safety-related equipment. Drawing LR-M-214, sheet 1 depicts heat exchangers HX-97A,

HX-97B, HX-86A, HX-86B, HX-35A, HX-35B, 1 HX-77A, and 1 HX-77B as being within the

scope of license renewal. However, LRA Table 2.3.3-7 does not indicate that heating steam

system heat exchangers are components requiring an AMR. Since the heating steam system

heat exchangers are shown as being within the scope of license renewal on the drawings, in

RAI 2.3.3.7-1, dated November 10, 2004, the staff requested the applicant to explain the

reasons for not listing these heat exchangers in LRA Tables 2.3.3-7 and 3.3.2-15.

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In its response, dated December 14, 2004, the applicant stated that all of these heating steam

heat exchangers are simple industrial area heaters, which consist of a fan blowing across an

open coil. The applicant stated that these components are within the scope of license renewal

and subject to aging management, and are represented under the "Heaters/Coolers

component type in LRA Tables 2.3.3-7 and 3.3.2-15.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.7-1

acceptable. The design of these heat exchanger components is consistent with the

'Heater/Cooler" component type classification in LRA Tables 2.3.3.7 and 3.3.2-15. Therefore,

the staffs concerns described in RAI 2.3.3.7-1 are resolved.

2.3.3.7.3 Conclusion

The staff reviewed the LRA, accompanying scoping boundary drawing, and the RAI response

described above to determine whether any SSCs that should be within the scope of license

renewal were not identified by the applicant. No omissions were identified. In addition, the staff

performed a review to determine whether any of the components that should be subject to an

AMR were not identified by the applicant. No omissions were identified. On the basis of its

review, the staff concluded that there is reasonable assurance that the applicant adequately

identified the heating steam system components that are within the scope of license renewal,

as required by 10 CFR 54.4(a), and that the applicant adequately identified the heating steam

system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.8 Emergency Power System

2.3.3.8.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.8, the applicant described the emergency power system. The emergency

power system is designed to provide emergency or backup power to the station following the

loss of normal power. The emergency power system consists of four diesel generators and a

gas turbine generator (GTG). The normal source of power to the safety-related 4160

volts-altemating current (VAC) and 480 VAC buses is from offsite power through the station's

low-voltage auxiliary transformers. If this normal source fails, the standby source of power is

provided by the emergency diesel generators (EDGs). The diesel generator portion of the

emergency power system is composed of four diesel generators that directly supply the

safety-related 4160 VAC power system. In the unlikely event of a loss of all offsite and onsite

AC power, the GTG is available to power the required loads until a power supply is restored

from a diesel generator or from offsite power.

The portions of the emergency power system subject to an AMR are the diesel generator and

GTG subsystems. This includes the turbochargers, tanks, expansion joints, heat exchangers,

piping, and valves.

Functions associated with the emergency power system include the following:

* senses or provides process conditions

* generates signals for reactor coolant trip and engineered safety features actuation

* provides electrical power to the safety-related 4160 VAC power system

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The failure of nonsafety-related SSCs in the system could prevent the satisfactory

accomplishment of a safety-related function. In addition,-the emergency power system

performs functions that support fire protection and station blackout.

Intended functions within the scope of license renewal include the following:

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

* provides for mechanical closure integrity on bolted joints

* provides for filtration

* provides for fire protection, as through flame suppression

* provides for heat transfer

* provides for flow restriction

In LRA Table 2.3.3-8, the applicant identified the following emergency power system

component types that are within the scope of license renewal and subject to an AMR:

* air motor * instrumentation

* drain trap * instrument valve assemblies

* expansion joints * piping and fittings

* fan/blower housing * pump casing

* fasteners and bolting * restricting orifices

* filters and strainers * sight glass

* flame arrestors * silencer

* flow elements * tanks

* flow indicator * turbine casing

* heat exchanger * turbo-charger

* heaters and coolers * valve bodies

2.3.3.8.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.8 and FSAR Sections 8.0, 8.8, and 8.9. The staff's

review, using the evaluation methodology described in SER Section 2.3, was conducted in

accordance with the guidance described in NUREG-1 800, Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). The staff then reviewed those components that the applicar thad

identified as being within the scope of license renewal to verify that the applican- h1d not

omitted any passive and long-lived components that should be subject to an AMR In i j i I

accordance with the requirements of 10 CFR 54.21(a)(1). I

The staff's review of LRA Section 2.3.3.8 identified areas in which additional Information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAIs as discussed below.

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RAI 2.3.3.8-1. FSAR Section 8.8 states that in order to perform its safety-related function, the

DG system has several auxiliary support systems that must function, including the air intake

and exhaust system. Drawing LR-M-226 shows the air intake oil bath filters inside the DG

building with air intake screens shown on the building wall. The air intake screens on the DG

building walls are shown as outside the scope of license renewal on drawing LR-M-226,

sheets 1 and 2 at location E-3. LRA Section 2.4.4 states that the DG building is a

safety-related seismic Class 1 structure but does not specifically address the air intake screens.

In RAI 2.3.3.8-1, dated November 16, 2004, the staff requested the applicant to justify its

determination to not include the diesel generator air intake screens within the scope of license

renewal and subject to an AMR.

In its response, dated December 22, 2004, the applicant stated that the failure to Identify the air

intake screens on the DG building walls as in-scope on sheets 1 and 2 of drawing LR-M-226

was a drawing error. The applicant stated that the air intake screens are within the scope of

license renewal. The applicant also stated that the air intakes are a chevron design, which are

part of the structure and, therefore, are addressed as part of the civil/structural review in LRA

Table 3.5.2-4, by Structural Carbon SteeVOutdoorn component type. The applicant further

stated that the drawing LR-M-226, sheets 1 and 2, were revised, and the error is being tracked

in its corrective action program.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.8-1

acceptable. The applicant confirmed that the air intake screens on the DG building walls are

within the scope of license renewal, and the drawings were revised and the error is being

tracked. Therefore, the staff's concerns described are RAI 2.3.3.8-1 is resolved.

RAI 2.3.3.8-2. FSAR Section 8.8 states that in order to perform its safety-related function, the

DG system has several auxiliary support systems that must function, including the fuel oil

system. The instrument CS P105 and associated line on the gas turbine fuel oil supply pump

P-105 is shown as outside the scope of license renewal on drawing LR-M-21 9, sheet 1 at

location B-9. This is inconsistent with instruments CS P70A and CS P70B for fuel oil transfer

pumps P-70A and P-70B. These instruments and their associated lines are shown as falling

within the scope of license renewal. Failure of this instrument and its associated line may

adversely impact the integrity of the gas turbine fuel oil transfer pump. A degraded gas turbine

fuel oil transfer pump could adversely impact the SBO function of the GTG. In RAI 2.3.3.8-2,

dated November 16, 2004, the staff requested the applicant to explain its determination to not

include the instrument CS P105 and its associated line as within the scope of license renewal.

In its response, dated December 22, 2004, the applicant stated that failure to identify instrument

CS P105 and its associated line on the gas turbine fuel oil supply pump P-1 05 as within the

scope of license renewal, on sheet 1 of drawing LR-M-219, was a drawing (highlighting) error.

The applicant also stated that this control switch CS P105 is within the scope of license

renewal, but it is not subject to aging management because it is an active component. The

applicant further stated that the drawing LR-M-219, sheet 1 was revised, and the error is being

tracked in its corrective action program.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.8-2

acceptable. The applicant confirmed that the instrument CS P105 (and its associated line) is

within the scope of license renewal. Therefore, the staff's concern described in RAI 2.3.3.8-2 is

resolved.

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RAI 2.3.3.8-3. FSAR Section 8.8 states that in order to perform its safety-related function, the

DG system has several auxiliary support systems that must function, including the fuel oil

system. The instruments, position switch (POS) 3930 and control switch (CS) 3930, and their

associated lines on the DG day tank T-31 A are shown as outside the scope of license renewal

on drawing LR-M-219, sheet 1, location G-3. This is inconsistent with instruments POS 3931

and CS 3931 for DG day tank T-31 B. These instruments and their associated lines are shown

as falling within the scope of license renewal. Failure of these instruments and their associated

lines may adversely impact the integrity of the supply lines to the DG day tank. A degraded DG

day tank supply could adversely impact the safety-related function of the G01 diesel generator.

In RAI 2.3.3.8-3, dated November 16, 2004, the staff requested the applicant to explain its

determination to not include the instruments POS 3930 and CS 3930 and their associated lines

as within the scope of license renewal.

In its response, dated December 22, 2004, the applicant stated that failure to identify

instruments POS 3930 and CS 3930 and their associated lines as within the scope of license

renewal, on sheet 1 of drawing LR-M-21 9, was a highlighting error. The applicant also stated

that these instruments POS 3930 and CS 3930 are within the scope of license renewal, but

they are not subject to aging management because they are active components.

In a telephone conference on January 1 8, 2005, the applicant stated that the lines/wiring

associated with POS 3930 and CS 3930 are represented under the commodity group,

"Electrical Cables and Connectors Not Subject to 10 CFR 50.49 EQ Requirements," in LRA

Table 2.5-1. The applicant further stated that the drawing LR-M-219, sheet 1 was revised, and

the error is being tracked in its corrective action program. In its response, dated

February 7, 2005, the applicant confirmed the previous statement provided during the

telephone conference.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.8-3

acceptable. The applicant confirmed that the instruments POS 3930 and CS 3930 (and their

associated lines) are within the scope of license renewal. Therefore, the staff's concerns

described in RAI 2.3.3.8-3 are resolved.

RAI 2.3.3.8-4. FSAR Section 8.8 states that in order to perform its safety-related function, the

DG system has several auxiliary support systems that must function, including the fuel oil

system. The solenoid vent valve FO 3922 S on flow control valve FC 3922 is shown as within

the scope of license renewal on drawing LR-M-21 9, sheet 1 at location G-4. The line to this

solenoid vent valve is shown as outside the scope of license renewal. In addition, the solenoid

vent valve FO 3923 S on flow control valve FC 3923 is shown as out-of-scope at location E9.

A degraded DG fuel oil supply system could adversely impact the safety-related function of the

diesel generators. In RAI 2.3.3.8-4, dated November 16, 2004, the staff requested the

applicant to clarify why only solenoid vent valve FO 3922 S on FC 3922 is shown as in-scope,

while the associated lines and the similar vent valve configuration on FC 3923 are not shown

within the scope of license renewal.

In its response, dated December 22, 2004, the applicant stated that failure to identify the

solenoid vent valve FO 3923 S on flow control valve FC 3923 as within the scope of license

renewal (on sheet 1 of the drawing LR-M-219) was a drawing error. The applicant stated that

solenoid valve FO 3923 S is an active component and, although within the scope of license

renewal, it is not subject to aging management. Additionally, the applicant stated that the air

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lines between the solenoid valves (FO 3922 S and 3923 S) and the air-operated control valves

(FC 3922 and FC 3923) are not shown as being within the scope of license renewal, because

these air lines have no license renewal intended function. Should either of these air lines fail,

the associated air operated control valve (FC 3922 or FC 3923) will fail to their closed position

and thereby satisfy their intended function. The drawing LR-M-21 9, sheet 1 was revised, and

the error is being tracked in its corrective action program.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.8-4

acceptable. The applicant confirmed that the solenoid vent valve FO 3923 S is within the scope

of license renewal. The staff agreed that the vent lines upstream of solenoid vent valves

FO 2922 S and FO 3923 S may be considered outside the scope of license renewal.

Therefore, the staff's concerns described in RAI 2.3.3.8-4 are resolved.

RAI 2.3.3.8-5. FSAR Section 8.8 states that in order to performr its safety-related function, the

DG system has several auxiliary support systems that must function, including the fuel oil

system. The 20-inch manway, SAX 7907, 3-inch vent lines, and LS 3942 on the emergency

fuel tank T-72 are shown as outside the scope of license renewal on drawing LR-M-219,

sheet 1 at location C-5. This is inconsistent with the 24-inch manway, SAX 791 3A, 4-inch vent

lines and LS 3933A for DG storage tank T-1 75A shown on drawing LR-M-219, sheet 2 which

shows similar equipment on T-1 75A as in-scope. A degraded DG emergency fuel tank T-72

could adversely impact the emergency fuel supply and the safety-related function of the diesel

generators. In RAI 2.3.3.8-5, dated November 16, 2004, the staff requested the applicant to

support its determination that the 20-inch manway, SAX 7907, 3-inch vent lines, and LS 3942

on the emergency fuel tank are outside the scope of license renewal.

In its response, dated December 22, 2004, the applicant stated that the failure to identify the

20-inch manway, SAX 7907, 3-inch vent lines, and LS 3942 on the emergency fuel tank as

within the scope of license renewal on sheet 1 of drawing LR-M-21 9 was a highlighting error.

The applicant stated that the manway, SAX (sample point) 7907, and the 3-inch vent lines are

in-scope and subject to aging management. These components are represented by the OTank"

and NPiping and Fittingso component types in LRA Table 3.3.2-7. The applicant further stated

that level switch LS 3942 is also within the scope of license renewal; however, it is an active

component; therefore, it would not be subject to aging management. The applicant further

stated that the drawing LR-M-21 9, sheet 1 was revised, and the error is being tracked in its

corrective action program.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.8-5

acceptable. The applicant confirmed that the 20-inch manway, SAX 7907, 3-inch vent lines,

and LS 3942 on the emergency fuel tank are within the scope of license renewal. Therefore,

the staff's concerns described in RAI 2.3.3.8-5 are resolved.

2.3.3.8.3 Conclusion

The staff reviewed the LRA, accompanying scoping boundary drawings, and the RAI responses

described above to determine whether any SSCs that should be within the scope of license

renewal were not identified by the applicant. No omissions were identified. In addition, the staff

performed a review to determine whether any of the components that should be subject to an

AMR were not identified by the applicant. No omissions were identified. On the basis of its

review, the staff concluded that there is reasonable assurance that the applicant adequately

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identified the emergency power system components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and that the applicant adequately identified the

emergency power system components that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.3.9 Containment Ventilation System

2.3.3.9.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.9, the applicant described the containment ventilation system. The

containment ventilation system provides for emergency heat removal from the containment

atmosphere, containment pressure control, and containment isolation.

The containment ventilation system is made up of the following heating and ventilation

subsystems:

* containment cooling (VNCC)

* containment purge supply and exhaust (VNPSE)

* control rod drive (CRDM) cooling (VNCRD)

* reactor cavity cooling (VNRC)

* refueling cavity ventilation (VNRF)

* containment cleanup (VNCF)

Of these subsystems, only VNCC and VNPSE are within the scope of license renewal. The

portions of the containment ventilation system containing components subject to an AMR

include the equipment necessary to provide (1) emergency heat removal from the containment

atmosphere, (2) containment pressure control, and (3) containment isolation, including heat

exchangers, ductwork, damper housings, piping, and valves.

Functions associated with the containment ventilation system include the following:

* provides a primary containment boundary to prevent the release of radioactivity into the

environment

* provides emergency heat removal from the containment, following a LOCA or main

steam line break (MSLB) to limit the containment's pressure and temperature within the

limits of design

In addition, the containment ventilation system performs functions that support environmental

qualification.

Intended functions within the scope of license renewal include the following:

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

* provides for mechanical closure integrity on bolted joints

* provides for heat transfer

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In LRA Table 2.3.3-9, the applicant identified the following containment ventilation system

component types that are within the scope of license renewal and subject to an AMR:

* accumulators and cylinders * filters and strainers

* CS components * heat exchanger

* damper housings * heaters and coolers

* ductwork * piping and fittings

* fan/blower housing * thermowells

* fasteners and bolting * valve body

2.3.3.9.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.9 and FSAR Sections 5.2, 5.3, and 6.3. The staff's

review, using the evaluation methodology described in SER Section 2.3, was conducted in

accordance with the guidance described in NUREG-1800, Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had

identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR in

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

The staff's review of LRA Section 2.3.3.9 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

RAI 2.3.3.9. In RAI 2.3.3.9, dated November 17, 2004, the staff requested the applicant to

clarify whether all the system components such as, but not limited to, cooling coil housings and

roughing filter housings including screens for air intake or exhaust structures, etc., are within

the scope of license renewal in accordance with 10 CFR 54.4(a), and subject to an AMR in

accordance with 10 CFR 54.21 (a)(1).

In its response, dated December 17, 2004, the applicant stated the following:

* The roughing filter housings are in-scope and subject to AMR, and are included in the

OFilters/Strainers component type in LRA Table 2.3.3-9, Containment Ventilation

System" and LRA Table 3.3.2-8, "Auxiliary Systems-Containment Ventilation

System-Summary of Aging Management Evaluation."

* The 1/2HX-15A/B/CID cooling coils are in-scope and subject to aging management, and

are included in the Heat Exchanger component type line item in LRA Table 2.3.3-9,

"Containment Ventilation System" and LRA Table 3.3.2-8, "Auxiliary

Systems-Containment Ventilation System-Summary of Aging Management Evaluation."

The screens for intake and exhaust and expanded metal screen to hold the roughing filters in

place were not included within the scope of license renewal, as they provide no

10 CFR 54.4(a)(1), 10 CFR 54.4(a)(2), or 10 CFR 54.4(a)(3) functions for license renewal (and,

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therefore, are not included in the LRA tables). Also, screens or louvers on the exhaust

ductwork are not mentioned in the CLB, and, therefore, no credit was taken for them being in

place.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.9

acceptable. The applicant clarified that all applicable system components consisting of cooling

coil housings and roughing filter housings are within the scope of license renewal in accordance

with 10 CFR 54.4(a), and that they are subject to an AMR in accordance with

10 CFR 54.21 (a)(1).

2.3.3.9.3 Conclusion

The staff reviewed the LRA and the RAI response described above to determine whether any

SSCs that should be within the scope of license renewal were not identified by the applicant.

No omissions were identified. i In addition, the staff performed a review to determine whether

any of the components that should be subject to an AMR were not identified by the applicant.

No omissions were identified. On the basis of its review, the staff concluded that there is

reasonable assurance that the applicant adequately identified the containment ventilation

system components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and that the applicant adequately identified the containment ventilation system

components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.10 Essential Ventilation System

2.3.3.10.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.10, the applicant described the essential ventilation system. The essential

ventilation system is made up of the following subsystems that provide heating, ventilation, and

air conditioning (including chilled water) for their respective areas and the associated equipment

contained within those areas:

* control room ventilation (VNCR)

* computer room ventilation (VNCOMP)

* cable spreading room ventilation (VNCSR)

* primary auxiliary building (PAB) battery and inverter room ventilation (VNBI)

* diesel generator building ventilation (VNDG)

* PAB ventilation (VNPAB)

* circulation water pump house ventilation (VNPH)

* radwaste ventilation (VNRAD)

* drumming area ventilation (VNDRM)

* battery room ventilation (VNBR)

* auxiliary feedwater area ventilation (VNAFW)

* gas turbine building ventilation (VNGT)

Of these subsystems, only VNCR, VNCOMP, VNCSR, VNBI, VNGT, VNPAB, and VNDG are

within the scope of license renewal. The portions of the essential ventilation system containing

components subject to an AMR include: filters, fans, damper housings, valves, heat

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exchangers, air conditioning/chiller packages, ductwork, and the associated piping and valves

to support the system's intended functions.

Functions associated with the essential ventilation system include the following:

* provides climate control to areas containing safety Class 1, 2, and 3 components,

namely to the inverter, diesel generator, and station battery rooms for the VNBI

subsystem

* maintains the control room envelope to limit unfiltered leakage for the VNCOMP, VNCR,

and VNCSR subsystems

The system can filter and remove particulates and iodine from the outside air during emergency

operations to support the control room's occupants. In addition, the essential ventilation system

performs functions that support fire protection and station blackout.

Intended functions within the scope of license renewal include the following:

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

* provides for mechanical closure integrity on bolted joints

* provides for filtration

* provides for heat transfer

In LRA Table 2.3.3-10, the applicant identified the following essential ventilation system

component types that are within the scope of license renewal and subject to an AMR:

* damper housings * humidifier

* ductwork * instrument valve assemblies

* fan/blower housing * instrumentation

* fasteners and bolting * piping and fittings

* filters and strainers * pump casing

* flow elements * tanks

* heat exchanger * thermowells

* heaters and coolers * valve bodies

2.3.3.10.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.10 and FSAR Sections 8.7, 8.8, 9.5, and 9.8. The staff's

review, using the evaluation methodology described in SER Section 2.3, was conducted in

accordance with the guidance described in NUREG-1 800, Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had

identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR in

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

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The staff's review of LRA Section 2.3.3.10 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

RAI 2.3.3.10. In RAI 2.3.3.10, dated November 17, 2004, the staff requested the applicant to

clarify whether all the system components such as, but not limited to, cooling coil housing, valve

bodies for service water system control valves, heating coil housings, direct expansion coils,

filter housings, screens for intake and exhaust structures including duct sealants, wall sealants,

and pressure boundary sealants, etc., are within the scope of license renewal in accordance

with 10 CFR 54.4(a), and subject to AMR in accordance with 10 CFR 54.21(a)(1).

In its response, dated December 17, 2004, the applicant stated the following:

* Cooling coilheating coil housings are in-scope, subject to aging management, and are

already included within the existing NHeaters/Coolers component type in LRA

Table 3.3.2-9, "Auxiliary Systems - Service Water System - Summary of Aging

Management Evaluation," (and LRA Table 2.3.3-10, "Essential Ventilation System").

* The valve bodies for the service water control valves are in-scope, subject to aging

management, and are already included in LRA Table 3.3.2-5, "Auxiliary Systems -

Service Water System - Summary of Aging Management Evaluation".

* Filter housings are in-scope, subject to aging management, and are already included

within the existing OFihters/Strainers' component type in LRA Table 3.3.2-9, 'Auxiliary

Systems - Service Water System - Summary of Aging Management Evaluation," (and

LRA Table 2.3.3-10, uEssential Ventilation System").

* Intake and exhaust screens/louvers have no license renewal intended functions and,

therefore, require no aging management. The outside air intake screen, however, will

be included within the scope of license renewal, subject to aging management, with

potential aging effects of loss of material and fouling, both of which will be managed by

the System Monitoring Program.

* Duct sealants, wall sealants, and pressure boundary sealants are in-scope, subject to

aging management, and are already included in commodity fashion, in the

CiviVStructural portion of the LRA Tables 2.4.2 / 3.5.2-2, for "Elastomers/indoor-AII" and

LRA Tables 2.4.11 / 3.5.2.11, for "Silicone Based Materia~lndoor."

The applicant further stated that heat exchangers HX-1 90 A/B and HX-1 91 A/B were

inadvertently shown to be in-scope on drawing LR-M-144, sheet 2. These heat exchangers are

part of the supplementary cooling for the computer room, which were installed specifically for

the plant process computer (which is nonsafety-related). The heat exo ar~er copling units are

not safety-related, and they do not affect the control room envelope. T e loss Q these cooling

units will have no effect on any safety-related equipment, antefo!tslil ar

considered to be outside the scope of license renewal, as they provd e nhCFH 4.4(a)(1)

10 CFR 54.4(a)(2), or 10 CFR 54.4(a)(3) functions for license renewal n heref oe are not

included in the LRA tables.

Based on the above discussion, the staff found the applicant's respons to IAI 2.3.3!10

acceptable. The applicant clarified that all applicable system components consisting of cooling

coil housing, valve bodies for service water system control valves, heating coil housings, filter

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housings, outside air intake screen including duct sealants, wall sealants, and pressure

boundary sealants are within the scope of license renewal in accordance with 10 CFR 54.4(a),

and subject to an AMR in accordance with 10 CFR 54.21 (a)(1) for the essential ventilation

system. These are identified as "Component Types" in LRA Tables 2.3.3-10, 3.3.2-9 and other

associated LRA Tables 2.4.2, 2.4.11, 3.3.2-5, 3.5.2-2, and 3.5.2.11. Therefore, the staff's

concern described in RAI 2.3.3.10 is resolved.

RAI 2.3.3.10-1. In RAI 2.3.3.10-1, dated December 17, 2004, the staff requested the applicant

to clarify whether the chiller and associated components shown on drawing LR-M-214, sheet 4

at location C-9 for the control room chilled water system and any other applicable components

of the system are within the scope of license renewal in accordance with 10 CFR 54.4(a), and

subject to AMR in accordance with 10 CFR 54.21 (a)(1).

In an e-mail dated, January 6, 2005, the applicant stated the following:

* As part of license renewal review, the applicant did not create a specific TChiller"

component type, but rather left them as Heat Exchanger" subcomponents. Therefore,

a TChiller component type does not show up in Tables 2.3.3-10 or 3.3.2-9.

* All of the "Chiller" subcomponents are in-scope and require aging management, and

they are represented by the Heat Exchanger' component type. The *Heat Exchangers

line items in Table 3.3.2-9 that have treated water environment, represent those

subcomponents that are on the chilled water side of the unit. The nHeat Exchanger" line

items with an air/gas environment, represent the subcomponents that are on the

refrigerant side of the unit. The "Heat Exchanger" line items with "Raw Water"

environment represent the subcomponents that are on the service water side of the unit.

Based on the above discussion, the staff found the applicant's proposed response to

RAI 2.3.3.10-1 acceptable. The applicant clarified that all applicable system components

consisting of chillers and its subcomponents are within the scope of license renewal in

accordance with 10 CFR 54.4(a), and subject to an AMR in accordance with

10 CFR 54.21 (a)(1) for the essential ventilation system and are identified as 'Component

Types" in LRA Tables 2.3.3-10 and 3.3.2-9. In its response, dated January 17, 2005, the

applicant confirmed the statement previously provided via e-mail. Therefore, the staff's

concerns described in RAI 2.3.3.10-1 are resolved.

2.3.3.10.3 Conclusion

The staff reviewed the LRA, the accompanying scoping boundary drawings, and the RAI

responses described above to determine whether any SSCs that should be within the scope of

license renewal were not identified by the applicant. No omissions were identified. In addition,

the staff performed a review to determine whether any of the components that should be

subject to an AMR were not identified by the applicant. No omissions were identified. On the

basis of its review, the staff concluded that there is reasonable assurance that the applicant

adequately identified the essential ventilation system components that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and that the applicant adequately identified the

essential ventilation system components that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

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2.3.3.11 Treated Water System

2.3.3.11.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.11, the applicant described the treated water system. The treated water

system is comprised of the water treatment (WT), demineralized water (Dl), potable water

(PW), hydrazine addition (HA), sewage treatment plant (STP), and non-radioactive liquid waste

disposal (floor drains, secondary sample effluents, etc.) secondary plant subsystems. These

subsystems treat and demineralize water, store and supply demineralized and potable water for

various uses in the plant, transfer and hold sanitary waste, clean site sump discharges, and

introduce hydrazine and morpholine to the steam generators and condensate subsystem. -The

treated water system is a non-seismic piping system whose primary function is to support other

plant process systems. The principal components of the treated water system are pumps,

tanks, hot water heaters, hoses, valves, and associated piping.

The portions of the treated water system containing components subject to an AMR include:

* shear gate valves in the GO1/G02 room's oily sump

* eyewash/safety shower in the auxiliary feedwater pump (AFP) area

* equipment drains from the heating, ventilation and air conditioning (HVAC) room above

the main control room

* sump pump discharge piping and STP piping in the safety injection (SI) / component

cooling (CC) pump area

* Dl piping in close proximity to the containment spray and spent fuel pool (SFP) pumps,

and the Unit 2 charging pump cubicles

The failure of nonsafety-related SSCs in the system could prevent the satisfactory

accomplishment of a safety-related function.

Intended functions within the scope of license renewal include the following:

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

* provides for mechanical closure integrity on bolted joints

In LRA Table 2.3.3-11, as modified by letter dated April 29, 2005, the applicant identified the

following treated water system component types that are within the scope of license renewal

and subject to an AMR:

* CS components * valve bodies

* fasteners and bolting * filters and strainers

* piping and fittings * heat exchangers

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2.3.3.11.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.11 and the FSAR. The staff's review, using the

evaluation methodology described in SER Section 2.3, was conducted in accordance with the

guidance described in NUREG-1 800, Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). As a result of the implementation of the scoping methodology changes, by letter dated April 29, 2005, the applicant identified additional component types within the

scope of license renewal. The staff then reviewed those components that the applicant had

identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR in

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

The staff's review of LRA Section 2.3.3.11 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAls as discussed below.

RAI 2.3.3.11-1. LRA Section 2.3.3.11 states that the shear gate valves in the G01 and G02

rooms' oily sumps are within the scope of license renewal. In addition, the LRA states these

are nonsafety-related SSCs whose failure has an effect on the function of safety-related

equipment. Drawing LR-M-223, sheet 3, location F-2, indicates STP 14 and 15 are in the G02

room and are within the scope of license renewal. The shear gate valves for Room G01 could

not be located on the LRA drawings. In RAI 2.3.3.11-1, dated November 10, 2004, the staff

requested the applicant to clarify the location of the shear gate valves associated with Room

G01 that are called out as within the scope of license renewal and subject to an AMR in

accordance with 10 CFR 54.21 (a)(1).

In its response, dated December 14,2004, the applicant stated that drawing LR-M-223,

sheet 3, location F-2, showing both STP-1 4 and STP-1 5 in the room for G02 is a drawing error.

In reality, STP-1 4 is located in the room for G01, whereas STP-15 is in G02. The applicant

further stated that the plant drawing was updated to correct this error, and confirmed that both

gate valves associated with the above STPs are within the scope of license renewal.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.11-1

acceptable; therefore, the staff's concern described in RAI 2.3.3.11-1 is resolved.

RAI 2.3.3.11-2. The LRA states that all nonsafety-related SSCs whose failure could prevent

satisfactory accomplishment of any of the functions identified within 10 CFR 54.4(a)(1)(i),

(ii), or (iii) shall be considered within the scope of license renewal. Inconsistencies within the

treated water system LRA drawings were identified as follows: piping segments identified on

drawing LR-PBM-231, sheet 2, locations B-3, D-4, and B-9; drawing LR-M-223, sheet 3 at

locations E-8 and H-8; and drawing LR-PBM-231, sheet 1 at location B-3 are designated to be

within the scope of license renewal; however, the basis for these determinations is not

explained. These piping segments can adversely impact the function of safety-related SSCs.

In RAI 2.3.3.11-2, dated November 10, 2004, the staff requested the applicant to provide

additional information and drawing LR-PBM-231, sheet 2, to permit verification that they have

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been properly identified to be within the scope of license renewal and subject to an AMR in

accordance with 10 CFR 54.21 (a)(1).

In its response, dated December 14, 2004, the applicant stated that the LRA process included

performing plant walkdowns to identify nonsafety-related components that could affect

safety-related components, pursuant to 10 CFR 54.4(a)(2). This is discussed in LRA

Section 2.1.2.1.2. LRA Table 2.1.2.1-1 displays the results of these walkdowns and provides a

brief description of the nonsafety-related SSCs that were added to the scope of license

renewal. The applicant further stated:

Although difficult to show on a drawing, the in-scope portions of these non-SR

[safety-related] piping sections were determined during plant walkdowns and transitions

are shown at the points where the piping exited the room. Therefore, the scoping

boundary may appear in the middle of a piping run and not at an isolation valve.

Based on the above statements, the applicant stated the following:

* For LRA drawing LR-PBM-231, sheet 2, the three instances identified in the RAI are all

represented in Table 2.1.2.1-1, p. 2-28, in the third line item from the bottom. The

safety-related equipment that could be potentially affected includes the containment

spray pumps, the spent fuel pool pumps, and other safety-related equipment near

pipeways #2 and #3, and near the charging pump cubicles.

* For LRA drawing LR-PBM-233, sheet 3, the two instances Identified in the RAI are both

represented in Table 2.1.2.1-1, p. 2-27, in the first line item. The safety-related

equipment that could be potentially affected includes the safety Injection pumps and the

component cooling water pumps.

* For LRA drawing LR-PBM-231, sheet 1, the one instance identified in the RAI is

represented in Table 2.1.2.1 -1,- p. 2-27, in the third line item from the top. The

safety-related equipment that could be potentially affected includes the safety injection

pumps, the containment spray pumps, the component cooling water pumps, and other

safety-related equipment near the charging pump cubicles.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.11-2

acceptable; therefore, the staff's concern described in RAI 2.3.3.11-2 is resolved.

2.3.3.11.3 Conclusion

The staff reviewed the LRA, accompanying scoping boundary drawings, the April 29, 2005,

letter, and the RAI responses described above to determine whether any SSCs that should be

within the scope of license renewal were not identified by the a plicant. No omissions were

identified. In addition, the staff performed a review to determine whether any of the

components that should be subject to an AMR were not identifi d by the applicant. No

omissions were identified. On the basis of its review, the staff concluded that there is

reasonable assurance that the applicant adequately identified the treated water system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

that the applicant adequately identified the treated water system components that are subject to

an AMR, as required by 10 CFR 54.21(a)(1).

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23.3.12 Circulating Water System

2.3.3.12.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.12, the applicant described the circulating water (CW) system. The CW

system provides a reliable supply of water from Lake Michigan to condense the steam

exhausted from the low-pressure turbines. The system is a non-seismic piping system whose

primary function is to remove heat from the steam cycle via the main condensers. The principal

components of the CW system are the circulating water pumps, traveling screens and screen

wash pumps, chlorine addition subsystem, and the associated piping and valves.

The portions of the CW system containing components subject to an AMR include: pump

casings, valves, expansion joints and associated piping, screen wash and chlorination piping,

valves, and associated components.

The failure of nonsafety-related SSCs in the system could prevent the satisfactory

accomplishment of a safety-related function.

Intended functions within the scope of license renewal include the following:

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

* provides for mechanical closure integrity on bolted joints

In LRA Table 2.3.3-12, the applicant identified the following CW system component types that

are within the scope of license renewal and subject to an AMR:

* expansion joints * pump casing

* fasteners and bolting * valve bodies

* piping and fittings

2.3.3.12.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.12 and FSAR Section 10.1. The staff's review, using the

evaluation methodology described in SER Section 2.3, was conducted in accordance with the

guidance described in NUREG-1 800, Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had

identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR in

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

The staff's review of LRA Section 2.3.3.12 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAls as discussed below.

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RAI 2.3.3.12-1. LRA Section 2.3.3.12 states that portions of the CW system are considered to

be within the scope of license renewal pursuant to 10 CFR 54.4(a)(2) due to the potential for

flooding or spray to affect the function of the safety-related SW pumps. The 10 CFR 54.4(a)(2)

scoping results for portions of the CW system that are within the scope of license renewal are

identified on drawing LR-PBM-232 at location D5. This drawing indicates that the chlorination

piping to the suction of CW pumps 2P-30A and 30B is in-scope; however, the same line to CW

pumps 1 P-30A and 30B is shown as not in-scope. In RAI 2.3.3.12-1, dated

November 10, 2004, the staff requested the applicant to provide its basis for not considering

chlorination piping between isolation valves CD-46 and 47 to the suction of CW pumps

1 P-30A and 30B within the scope of license renewal.

In its response, dated December 14, 2004, the applicant stated that based on its

10 CFR 54.4(a)(2) walkdown, the physical location of the system with relation to the CW pumps

is such that the Unit I chlorination piping does not cross the safety-related SW pump room as

the Unit 2 chlorination lines do. Therefore, failure of the Unit 2 chlorination lines has the

potential to affect the safety-related SW pumps via leakage or spray, and these lines are

identified as within the scope of license renewal. Unit 1 lines do not have the potential to affect

any safety-related equipment; therefore, they are not within the scope of license renewal.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.12-1

acceptable. Therefore, the staff's concerns described in RAI 2.3.3.12-1 are resolved.

RAI 2.3.3.12-2. LRA Section 2.3.3.12 states that portions of the CW system are considered to

be within the scope of license renewal pursuant to 10 CFR 54.4(a)(2) due to the potential for

flooding or spray to affect the function of the safety-related SW pumps. LRA drawings

LR-M-212, sheet 1 and LR-M-2212 show the portions of the CW system that are within the

scope of license renewal. The scoping review in the LRA states that the pumps, discharge

valves, expansion joints, and associated piping within the CW pump house structure are

in-scope; however, pressure taps (1 P13503 and 3504, and 1 P13503 and 3504) on the discharge

of CW pumps 1 -P30A and 30B and 2-P30A and 30B are not included within the scope of

license renewal. In RAI 2.3.3.12-2, dated November 10, 2004, the staff requested the applicant

to provide its technical justification for omitting the pressure taps (1 P13503 and 3504, and

1 P13503 and 3504) on the discharge of CW pumps 1 -P30A and 30B and 2-P30A and 30B from

the scope of license renewal.

In its response, dated December 14, 2004, the applicant stated that the CW system pumps,

piping, valves, and expansion joints are in-scope, because of the flooding potential due to the

large volume of water they carry/transport. In the event of a failure of any of these

components, the water accumulation in the CW pump housing structure could exceed its

draining capacity, which could thereby affect the safety-related pumps within that structure.

Whereas, according to the applicant, a failure of any the small bore pressure taps will not cause

water accumulation that could exceed the draining capacity of the housing structure and,

therefore, will not affect the safety-related SW pumps in the structure. Therefore, the applicant

concluded that the pressure taps that are identified in the RAI are not within the scope of

license renewal, because they do not meet the scoping criteria for license renewal.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.12-2

acceptable. Therefore, the staff's concern described in RAI 2.3.3.12-2 is resolved.

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2.3.3.12.3 Conclusion

The staff reviewed the LRA, accompanying scoping boundary drawings, and the RAI responses

described above to determine whether any SSCs that should be within the scope of license

renewal were not identified by the applicant. No omissions were identified. In addition, the staff

performed a review to determine whether any of the components that should be subject to an

AMR were not identified by the applicant. No omissions were identified. On the basis of its

review, the staff concluded that there is reasonable assurance that the applicant adequately

identified the CW system components that are within the scope of license renewal, as required

by 10 CFR 54.4(a), and that the applicant adequately identified the CW system components

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

2.3.3.13 Fuel Handling System

2.3.3.13.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.13, the applicant described the fuel handling system. The fuel handling

system provides a safe and effective means of transporting and handling fuel, from the time it

reaches the plant in a non-irradiated condition until it leaves the plant as spent fuel. The

system is designed to minimize the possibility of mishandling or misoperation that could cause

fuel damage and potential fission product release.

The fuel handling system ensures adequate cooling in the SFP.

2.3.3.13.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.13 and FSAR Section 9.4. The staff's review, using the

evaluation methodology described in SER Section 2.3, was conducted in accordance with the

guidance described in NUREG-1800, Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had

identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR in

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

2.3.3.13.3 Conclusion

The staff reviewed the LRA to determine whether any SSCs that should be within the scope of

license renewal were not identified by the applicant. No omissions were identified. In addition,

the staff performed a review to determine whether any of the components that should be

subject to an AMR were not identified by the applicant. No omissions were identified. On the

basis of its review, the staff concluded that there is reasonable assurance that the applicant

adequately identified the fuel handling system components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and that the applicant adequately identified the fuel

handling system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.3.3.14 Plant Sampling System

2.3.3.14.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.14, the applicant described the plant sampling system. The plant

sampling system includes both the primary and secondary sampling subsystems. The primary

sampling subsystem is able to take samples for laboratory analysis in order to evaluate reactor

coolant and other auxiliary systems' chemistry during normal operation. In addition, this

subsystem contains isolation valves for maintaining the containment pressure boundary. The

secondary sampling subsystem provides a mean to obtain samples for various secondary plant

location laboratory analysis.

Functions associated with the plant sampling system include the following:

* maintains the integrity of the reactor coolant pressure boundary

* provides automatic isolation of sample lines penetrating containment to prevent release

of radioactivity to the environment

* provides heat removal from and/or pressure boundary of safety-related heat exchangers

In addition, the plant sampling system performs functions that support fire protection and

environmental qualification.

The portions of the plant sampling system that constitute a part of the containment boundary

and reactor coolant pressure boundary are within the ASME Class 1 boundary and are

addressed in the Class 1 piping/components system. For convenience, a few additional

components within the scope of license renewal are addressed in the following parent systems:

residual heat removal system, chemical and volume control system, and component cooling

water system.

As a result of the implementation of the scoping methodology changes, by letter dated

April 29, 2005, the applicant identified more components within the scope of license renewal.

The items originally addressed in other interface systems were left in those systems. The

newly identified components include the tubing runs and valves from containment isolation

valves or various sample locations to the primary sample room. The following, previously

excluded, intended function and component types were identified.

Intended function within the scope of license renewal is to provide a pressure-retaining

boundary so that sufficient flow at adequate pressure is delivered.

In LRA Table 2.3.3-14, as modified by letter dated April 29, 2005, the applicant identified the

following plant sampling system component types that are within the scope of license renewal

and subject to an AMR:

* filters and strainers * restricting orifices I

* levelgauges * tanks

* piping and fittings * valve bodies I

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2.3.3.14.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.14 and FSAR Sections 5.2 and 9.11. The staff's review,

using the evaluation methodology described in SER Section 2.3, was conducted in accordance

with the guidance described in NUREG-1 800, Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). As a result of the implementation of the scoping methodology changes,

by letter dated April 29, 2005, the applicant identified additional component types within the

scope of license renewal. The staff then reviewed those components that the applicant had

identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR in

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

2.3.3.14.3 Conclusion

The staff reviewed the LRA and the April 29, 2005, letter to determine whether any SSCs that

should be within the scope of license renewal were not identified by the applicant. No

omissions were identified. In addition, the staff performed a review to determine whether any of

the components that should be subject to an AMR were not identified by the applicant. No

omissions were identified. On the basis of its review, the staff concluded that there is

reasonable assurance that the applicant adequately identified the plant sampling system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

that the applicant adequately identified the plant sampling system components that are subject

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

2.3.3.15 Plant Air System

2.3.3.15.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.15, the applicant described the plant air system. The plant air system

includes the instrument air (IA), service air (SA), and emergency breathing air (EBA)

subsystems. The IA and SA subsystems supply compressed air throughout the plant. The IA

subsystem supplies dry, oil-free air to various components for the normal operation of both

Units 1 and 2. The SA subsystem supplies non-dried, oil-free air to those plant services not

requiring dry air. The EBA subsystem provides EBA to control room personnel based on fire

protection criteria.

The portions of the plant air system containing components subject to an AMR include:

* IA components that support the charging pump vari-drives

* pressurizer power-operated relief valves (PORVs)

* IA and -SA containment isolation valves

* SA boundary valves to the EBA subsystem

* EBA components from the air receivers to the connections in the control room

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The plant air system provides a primary containment boundary to prevent the release of

radioactivity into the environment. In addition, the plant air system performs functions that

support fire protection, environmental qualification, and station blackout.

Intended functions within the scope of license renewal include the following:

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

* provides for mechanical closure integrity on bolted joints

* provides for filtration

In LRA Table 2.3.3-15, the applicant identified the following plant air system component types

that are within the scope of license renewal and subject to an AMR:

* accumulators and cylinders * flow indicators

* compressor casing * piping and fittings

* CS components * tanks

* fasteners and bolting * valve bodies

* filters and strainers

2.3.3.15.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.15 and FSAR Sections 9.7 and 5.2. The staff's review,

using the evaluation methodology described in SER Section 2.3, was conducted in accordance

with the guidance described in NUREG-1 800, Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had

identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR in

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

The staff's review of LRA Section 2.3.3.15 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAls, as discussed below.

RAI 2.3.3.15-1. FSAR Section 9.7.1 states that the instrument air (IA) system shall

automatically isolate the purge supply and exhaust valve accumulators, including the

supplemental nitrogen bottle system for 2VNPSE-3212 and 2VNPSE-3244, from the IA system

during a loss of instrument air to maintain containment integrity and prevent release of

radioactivity to the outside environment.

Drawing LR-PBM-2332 shows two valve actuators (listed below) as outside the scope of license

renewal. However, LRA Section 2.3.3.15 states that the valve bodies are in-scope as a

pressure boundary. The two valve actuators are not shown on plant drawings in a manner that

is consistent with similar valves in the IA system. If portions of these valves have pressure

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boundary functions that are not within the scope of license renewal, their failure could adversely

impact the IA system pressure boundary function. In RAI 2.3.3.15-1, dated

November 16, 2004, the staff requested the applicant to justify why the following valve

actuators are not shown as within the scope of license renewal and subject to an AMR.

actuator for 2VNPSE-3212, drawing LR-PBM-2332, location E-2.

* actuator for 2VNPSE-3244, drawing LR-PBM-2332, location E-6.

In its response, dated December 22, 2004, the applicant stated that failure to identify

2VNPSE-3212 and 2VNPSE-3244 actuators as within the scope of license renewal on drawing

LR-PBM-2332 was a highlighting error. According to the applicant, these solenoid actuators

are in-scope; however, they are not subject to aging management since they are active portions

of the valves. Also, the bodies of the solenoid valves are in-scope as'depicted on the drawing,

and they have a pressure boundary intended function. Therefore, these valves would be

subject to aging management. The applicant further stated that these valves are represented

by the "Valve Bodieso component type in LRA Table 3.3.2-11. The above drawing was revised

and the error is being tracked in its corrective action program.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.15-1

acceptable. Therefore, the staff's concerns described in RAI 2.3.3.15-1 are resolved.

RAI 2.3.3.15-2. FSAR Section 9.7.1 states that the IA system shall automatically isolate the

instrument air lines penetrating containment whenever a containment isolation signal exists to

maintain containment integrity and prevent release of radioactivity to the outside environment.

Drawing LR-M-209, sheet 7 shows IA piping through penetrations P-33A and P-33B in four

locations as within the scope of license renewal. This agrees with LRA Section 2.3.3.15 that

states the in-scope portion of the IA subsystem includes those IA components that support the

charging pump variable drives, pressurizer PORVs, and the IA containment isolation valve.

However, the IA air piping continuation for these containment penetrations on drawing

LR-M-209, sheet 11 (at four locations B-1, C-1, C-6, and D-6) shows the IA piping as

out-of-scope for license renewal. The transition location from in-scope (containment isolation)

to out-of-scope (inside containment) is not clearly marked. If portions of these piping sections

are out-of-scope for license renewal, their failure may affect the integrity of containment. In

RAI 2.3.3.15-2, dated November 16, 2004, the staff requested the applicant to clarify the exact

locations of these four transitions, and to clearly show which sections are within, and which are

outside, the scope of license renewal.

In its response, dated December 22, 2004, the applicant stated that this was a highlighting error

on drawing LR-M-209, sheet 11. The containment isolation function'for the IA system is

performed by two valves outside containment for each line, as shown on sheet 7 of the above

drawing. According to the applicant, these valves and piping up to and including the

containment penetration are in-scope and subject to aging management. The piping adjacent

to the penetrations inside containment is out-of-scope. The applicant further stated that the

drawing LR-M-209, sheet 11, was revised and the error is being tracked in its corrective action

program.

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Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.15-2

acceptable. The applicant confirmed that the in-scope transitions occur inside containment at

the penetration. Therefore, the staff's concerns described in RAI 2.3.3.15-2 are resolved.

RAI 2.3.3.15-3. FSAR Section 9.7.1 states that the IA system shall automatically isolate the

instrument air lines penetrating containment whenever a containment isolation signal exists to

maintain containment integrity and prevent release of radioactivity to the outside environment.

Drawing LR-M-209, sheet 7 shows four tanks and associated piping as out-of-scope for license

renewal. LRA Section 2.3.3.15 states that the in-scope portion of the IA subsystem includes

those IA components that support the charging pump variable drives, pressurizer PORVs, and

the IA containment isolation valves. Failure of these sections of piping depicted as not in-scope

could affect the integrity of containment. In RAI 2.3.3.15-3, dated November 16, 2004, the staff

requested the applicant to justify its determination of the following tanks and associated piping

as outside the scope of license renewal and subject to an AMR:

* iT -196, drawing LR-M-209, sheet 7, location B-3

* 1 T -197, drawing LR-M-209, sheet 7, location A-3

* T -196, drawing LR-M-209, sheet 7 location E-2

* T -197, drawing LR-M-209, sheet 7 location F-2

In its response, dated December 22, 2004, the applicant stated that the four tanks referenced in

this question are small air accumulators on the air line to the actuators. These tanks and their

associated piping are correctly shown to be outside the scope of license renewal, because they

perform no license renewal intended function and cannot affect the containment isolation

function of the containment isolation valves. The applicant further stated that the failure of

these tanks or piping would cause air to bleed off the actuator, thereby causing the associated

containment isolation valve to close in its fail-safe position.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.3.15-3

acceptable. The pressure boundary failure of air accumulators (1T1 96, 1T1 97, T196, and

T1 97) and the associated vent piping will not prevent the containment isolation valves from

fulfilling their intended safety function. The staff agreed that these air accumulators and the

adjacent vent piping for containment isolation valves 1 CV3047, 1 CV3048, 2CV3047, and

2CV3048 can be considered outside the scope of license renewal. Therefore, the staff's

concerns described in RAI 2.3.3.15-3 are resolved.

2.3.3.15.3 Conclusion

The staff reviewed the LRA, accompanying scoping boundary drawings, and the RAI responses

described above to determine whether any SSCs that should be within the scope of license

renewal were not identified by the applicant. No omissions were identified. In addition, the staff

performed a review to determine whether any of the components that should be subject to an

AMR were not identified by the applicant. No omissions were identified. On the basis of its

review, the staff concluded that there is reasonable assurance that the applicant adequately

identified the plant air system components that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and that the applicant adequately identified the plant air system

components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.33.16 Containment Hydrogen Detectors and Recombiner System

2.3.3.16.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.16, the applicant described the containment hydrogen detectors and

recombiner system. The containment hydrogen detectors and recombiner system (generally

referred to as the post-accident containment ventilation system (PACV)) provides a long-term

method of controlling hydrogen accumulation within the containment following a LOCA. The

system includes independent sample, exhaust and supply piping connections, and the

associated piping and valves that support the system's intended functions. Each piping

connection is equipped with redundant containment isolation valves that are located to minimize

personnel's exposure to radiation, if valve operation is required. Exhaust piping discharges to

either the PAB exhaust ventilation subsystem or to a hydrogen recombiner that is stored offsite.

The portions of the containment hydrogen detectors and recombiner system containing

components subject to an AMR extend from the piping inside containment to the containment

isolation valves, including the associated piping and valves.

Functions associated with the containment hydrogen detectors and recombiner system include

the following:

* provides a primary containment boundary to prevent the release of radioactivity into the

environment

* provides a long-term method of controlling hydrogen accumulation and thereby

containment pressure control following a LOCA

In addition, the containment hydrogen detectors and recombiner system performs functions that

support environmental qualification.

Intended functions within the scope of license renewal include the following:

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

* provides for mechanical closure integrity on bolted joints

In LRA Table 2.3.3-16, the applicant identified the following containment hydrogen detectors

and recombiner system component types that are within the scope of license renewal and

subject to an AMR:

* CS components * piping and fittings

* fasteners and bolting * valve bodies

* instrument valve assemblies

2.3.3.16.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.16 and FSAR Sections 5.2 and 5.3.2.4. The staff's

review, using the evaluation methodology described in SER Section 2.3, was conducted in

accordance with the guidance described in NUREG-1 800, Section 2.3.

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In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to-verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had

identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR in

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

2.3.3.16.3 Conclusion

The staff reviewed the LRA to determine whether any SSCs that should be within the scope of

license renewal were not identified by the applicant. No omissions were identified. In addition,

the staff performed a review to determine whether any of the components that should be

subject to an AMR were not identified by the applicant. No omissions were identified. On the

basis of its review, the staff concluded that there is reasonable assurance that the applicant

adequately identified the containment hydrogen detectors and recombiner system components

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the

applicant adequately identified the containment hydrogen detectors and recombiner system

components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.4 Steam and Power Conversion System

In LRA Section 2.3.4, the applicant identified the structures and components (SCs) of the steam

and power conversion system that are subject to an AMR for license renewal.

The applicant described the supporting SCs of the steam and power conversion system in the

following LRA sections:

* 2.3.4.1 main and auxiliary steam system

* 2.3.4.2 feedwater and condensate system

* 2.3.4.3 auxiliary feedwater system

The corresponding subsections of this SER (2.3.4.1 - 2.3.4.3) present the staff's review

findings with respect to the steam and power conversion systems for both Units 1 and 2.

2.3.4.1 Main and Auxiliary Steam System

2.3.4.1.1 Summary of Technical Information in the Application

In LRA Section 2.3.4.1, the applicant described the main and auxiliary steam system. The main

and auxiliary steam system transports the steam produced in the steam generator (SG) to the

main turbine for the production of electricity. The system also provides heat removal from the

RCS during normal, accident, and post-accident conditions. In addition, the main and auxiliary

steam system provides steam for the turbine-driven auxiliary feedwater pumps (AFPs), which

can be accessed from either of the main steam lines that are located upstream of the main

steam isolation valves. The main and auxiliary steam system is in continuous operation during

normal plant operation.'

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The portions of the main and auxiliary steam system containing components subject to an AMR

include the main steam line components extending from the SGs to downstream of the

non-retum valves, the auxiliary steam lines to the turbine-driven AFPs (including exhaust

piping), the radwaste steam lines until they exit the PAB, and the SG blowdown and sample

piping components that extend from the SGs to the containment isolation valves.

Functions associated with the main and auxiliary steam system include the following:

* contains instrumentation that functions by detecting, initiating, and actuating automatic

safety functions

* provides steam to the turbine-driven AFP

* provides primary containment boundary

* provides emergency heat removal from the RCS using secondary heat removal

capability

Some nonsafety-related portions of piping in the system have failure modes that could prevent

the satisfactory accomplishment of safety-related functions due to high-energy line breaks. In

addition, the main and auxiliary steam system performs functions that support fire protection,

environmental qualification, and station blackout.

Intended functions within the scope of license renewal include the following:

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

* provides for mechanical closure integrity on bolted joints

* provides for flow control or distribution, as through a spray nozzle

In LRA Table 2.3.4-1, as modified by letter dated April 29, 2005, the applicant identified the

following main and auxiliary steam system component types that are within the scope of license

renewal and subject to an AMR:

* CS components * steam traps

* drain trap * valve bodies

* fasteners and bolting * filters and strainers

* flow elements * heat exchangers

* instrument valve assemblies * level gauges

* piping and fittings * pump casing

* restricting orifices * tanks

2.3.4.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.1 and FSAR Sections 10.1 and 10.2. The staff's review,

using the evaluation methodology described in SER Section 2.3, was conducted in accordance

with the guidance described in NUREG-1 800, Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

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under 10 CFR 54.4(a).- As a result of the implementation of the scoping methodology changes,

by letter dated April 29, 2005, the applicant identified additional component types within the

scope of license renewal. The staff then reviewed those components that the applicant had

identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR in

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

2.3.4.1.3 Conclusion

The staff reviewed the LRA and the April 29, 2005, letter to determine whether any SSCs that

should be within the scope of license renewal were not identified by the applicant. No

omissions were identified. In addition, the staff performed a review to determine whether any of

the components that should be subject to an AMR were not identified by the applicant. No

omissions were identified. On the basis of its review, the staff concluded that there is

reasonable assurance that the applicant adequately identified the main and auxiliary steam

system components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and that the applicant adequately identified the main and auxiliary steam

system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.4.2 Feedwater and Condensate System

2.3.4.2.1 Summary of Technical Information in the Application

In LRA Section 2.3.4.2, the applicant described the feedwater and condensate system. The

feedwater and condensate system condenses and collects the steam exhausted from the

low-pressure turbines and then returns it to the SGs for reuse. Components within the system

are used to provide emergency heat removal from the RCS by utilizing secondary heat removal

capability. The engineered safety features actuation system (ESFAS) provides actuation

signals for feedwater isolation. The feedwater and condensate system is normally in

continuous operation during normal plant operation.

The portions of the feedwater and condensate system containing components subject to an

AMR extend from the feedwater regulating valves to the SGs.

Functions associated with the feedwater and condensate system include the following:

* detects, initiates, and actuates automatic safety functions

* provides emergency heat removal from the RCS by using secondary heat removal

capability

* provides a primary containment boundary to prevent the release of radioactivity Into the

environment

Portions of the feedwater and condensate system have failure modes that could prevent the

satisfactory accomplishment of safety-related functions due to high-energy line breaks i n.

addition, the feedwater and condensate system performs functions that support environ ental

qualification, station blackout, anticipated transient without scram, and fire protection.

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Intended functions within the scope of license renewal include the following:

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

* provides for mechanical closure integrity on bolted joints

* provides for flow control or distribution, as through a spray nozzle

In LRA Table 2.3.4-2, as modified by letters dated April 29 and July 19, 2005, the applicant

identified the following feedwater and condensate system component types that are within the

scope of license renewal and subject to an AMR:

* CS components * valve bodies

* fasteners and bolting * level gauges

* flow elements * pump casing

* instrument valve assemblies * steam traps

* piping and fittings * tanks

2.3.4.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.2 and FSAR Sections 5.2, 7.2, 7.4, and 10.1. The staff's

review, using the evaluation methodology described in SER Section 2.3, was conducted in

accordance with the guidance described in NUREG-1 800, Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). As a result of the implementation of the scoping methodology changes,

by letters dated April 29 and July 19, 2005, the applicant identified additional component types

within the scope of license renewal. The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR in

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

The staff's review of LRA Section 2.3.4.2 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAls as discussed below.

RAIs 2.3.4.2-1 and 2.3.4.2-4. As described in FSAR Section 10.1, the primary function of the

feedwater system is to provide feedwater to the steam generators. Further, according to the

LRA, portions of the feedwater system also provide pressure boundary and flow paths to

support AFW makeup to the steam generators. The LRA drawings for the feedwater and

condensate systems show the following listed piping/valves/fittings off of the feedwater

pressure boundary as not within the scope of license renewal. Whereas, LRA Section 2.3.4.2

states that the feedwater and condensate piping and fittings are within the scope of license

renewal as a pressure boundary. Failure of these sections of piping could affect the pressure

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boundary function of the feedwater system. In RAI 2.3.4.2-1, dated November 16, 2004, the

staff requested the applicant to justify as to why the piping areas listed below are not within the

scope of license renewal and subject to an AMR.

Dwg. LR-M-202, SH-2, F-8 and C-8-two sets of clean-out flanges

Dwg. LR-M-202, SH-2, F-8 and C-8.two capped 3/8m ME with two in line valves

Dwg. LR-M-202, SH-2, F-9 and B-9 two inlet lines from the Chem. Injection system

Dwg. LR-M-202, SH-2, F-7 and H-10......valvel45A and an outlet line to Dwg. 222

Dwg. LR-M-202, SH-2, B-7 . an outlet line with valve 151A

Dwg. LR-M-202, SH-2, C-9 ., an outlet line to 1TE 2105

Dwg. LR-M-202, SH-2, C-9 . an outlet line to 1 PT 2289

Dwg. LR-M-202, SH-2, C-B - an outlet line to 1TX 2102

Dwg. LR-M-202, SH-2, F-9 an outlet line to ITE 2104

Dwg. LR-M-202, SH-2, F-9 .................. - an outlet line to 1 PT 2290

Dwg. LR-M-202, SH-2, F-B - an outlet line to 1TX 2101

Dwg. LR-M-202, SH-1, D-10 an outline to 216 with valve 87

Dwg. LR-M-2202, SH-2, F-3 and C-3.,, a clean-out flange

Dwg. LR-M-2202, SH-2, F-3 and B-3,.,,,two capped 3/8" ME with two in line valves

Dwg. LR-M-2202, SH-2, F-3 andB-3-,,,,,,two inlet lines with valves 180 and 167

Dwg. LR-M-2202, SH-2, G-6 and F-4,.,,,an outlet line to 2222 with valve 145B

Dwg. LR-M-2202, SH-2, B-4. .,,,,,,,,,,an outlet line with valve 151 A

Dwg. LR-M-2202, SH-2, C-2,,,,,,------ _,,,,,,an outlet line to 2TE 2105

Dwg. LR-M-2202, SH-2, C-3 - an outlet line to 2PT 2289

Dwg. LR-M-2202, SH-2, C- - an outlet line to 2TX 2102

Dwg. LR-M-2202, SH-2, F-2 .- ,_,an outlet line to 2TE 2104

Dwg. LR-M-2202, SH-2, F-3-..,,,,,,,,,,an outlet line to 2PT 2290

Dwg. LR-M-2202, SH-2, F-3-,,,,,,,,,,,,,,,,,,an outlet line to 2TX 2101

Dwg. LR-M-202, SH-1, D-1 - an outline to 216 with valve 87

In its response, dated December 22, 2004, the applicant stated that the primary safety functions

of the feedwater and condensate system are to provide containment isolation and to maintain

capability for heat removal via the steam generators. Both of these functions are accomplished

by the two check valves in the main feed lines, just upstream of the steam generators (AFW

makeup is downstream of these check valves). For these reasons, the applicant stated that the

16-inch main feed headers between these check valves and the feedwater regulating valves

are nonsafety-related. These nonsafety-related headers were included within the scope of

license renewal in order to comply with the 10 CFR 54.4(a)(2) criterion, due to potential high

energy line break (HELB) interactions with nearby safety-related equipment (LRA

Table 2.1.2.1-1, p. 2-25, first line item). The applicant further stated that:

... Branches off of the main feedwater headers that are 1-inch and under were not

included in-scope as they are not considered in HELB evaluations (per NRC guidance

for HELB evaluations - per FSAR Appendix A.2 Reference 1: "General Information

Required for Consideration of the Effects of a Piping System Break Outside

Containment," (AEC, December 19, 1972).

Additionally, according to the applicant, since these connections of 1-inch and under, would not

be likely to provide sufficient energy to create a harsh environment (as defined by the PBNP

Equipment Qualification Program), only the header itself was included within the scope of

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license renewal for potential HELB concerns. Therefore, the applicant stated that branch

connections 1-inch and under, on the in-scope, nonsafety-related portions of the main

feedwater headers, are considered to be outside the scope of license renewal.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.4.2-1

acceptable, except for the 10 CFR 54.21 (a)(2) spatial effects of the branch lines, 1-inch and

under, off the main feedwater headers. The applicant should further evaluate these branch

lines to ensure that failure would not adversely impact the intended functions of safety-related

SSCs in the room where these branches are located.

The staff review of the applicant's response to RAI 2.3.4.2-1 identified two follow-up questions.

In RAI 2.3.4.2-4, dated January 10, 2005, the staff requested the applicant to:

(1) Confirm that a break in the branch piping (one-inch or less) would not impact any

safety-related equipment in the immediate vicinity of the possible break location.

(2) Discuss flooding associated with a failure in the branch piping and its impact on

safety-related equipment.

In its response, dated January 26,2005, the applicant stated the following:

(1) The section of main feedwater piping in question was included in-scope to protect the

safety-related (SR) (but non-environmentally qualified) feedwater transmitters

(1/2FT-466, -467, -476, -477). Walkdowns were performed to verify that no high energy

branch piping (including branch piping one-inch and less) was in proximity to the SR

transmitters where pipe whip or jet impingement could be a hazard. Additionally, the

transmitters are in large open areas where the energy input from a failure of a small

bore line off of this header would not create a sufficiently harsh environment to affect the

functions of these transmitters.

(2) The SR feedwater flow transmitters in question are location on the 26' elevation for

Unit 2 and 39' elevation for Unit 1, and mounted about four feet off of the floor. Any

leakage from the main feedwater header branch connections at these elevations would

cascade to lower elevation, and not affect the function of these transmitters nor any

other safety-related equipment due to flooding.

During a meeting on February 15, 2005, the staff indicated and the applicant agreed, that this

response required further clarification with respect to flooding associated with branch piping

failure. In its response, a clarification letter dated March 15, 2005, the applicant stated that any

leakage from these main feedwater header branch connections would not cause flooding that

would affect the function of the safety-related equipment, such as flow transmitters located in

the room. Additionally, the applicant stated "the scoping methodology will change to a 'spaces'

approach, and as such, the nonsafety-related components (including these 1-inch lines) in the

same space with the safety-related transmitters will be included in-scope."

Aging effects specified in 10 CFR 54.4 were not considered in the previous HELB evaluation.

Originally, the additional justification that "these 1-inch lines would not likely provide sufficient

energy to create a harsh environment" was not adequate. The distances between these 1-inch

lines and safety-related SSCs were not specified, and the staff was not able to evaluate the

validity of the statement to ensure that the failure of these branch lines would not adversely

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impact the intended functions of safety-related SSCs in the room where these branches are

located. By including all nonsafety-related components in the same space with the

safety-related transmitters, as stated in the clarification letter, the staff concluded that the

applicant provided an acceptable response. The staff's concerns described in RAls 2.3.4.2-1

and 2.3.4.2-4 are resolved.

RAI 2.3.4.2-2. FSAR Section 10.1 describes the primary function of the feedwater system as

providing feedwater to the SGs. As described in the LRA, portions of the feedwater system

also provide pressure boundary and flow paths to support AFW makeup to the SGs. The

condenser manual fill line shown on drawing LR-M-202 sheet 1, at location D-1 0 is indicated to

be within the scope of license renewal. However, a similar condenser manual fill line shown on

drawing LR-M-2002, sheet 1, location D-1 is not within the scope of license renewal. Failure of

this section of piping could affect the pressure boundary function of the feedwater system. In

RAI 2.3.4.2-2, dated November 16, 2004, the staff requested the applicant to justify its

determination to exclude this section of piping from the scope of license renewal for the Unit 2

feedwater system.

In its response, dated December 22, 2004, the applicant stated that this was a highlighting error

on drawing LR-M-2002, sheet 1. The applicant also stated that the condenser manual fill line

up to and including valves 2CS-86 and -87 is within the scope of license renewal and subject to

aging management. These components are represented by the 'Piping and Fittingsu and

nValve Bodies" component types in LRA Table 3.4.2-2. According to the applicant, the drawing

LR-M-2002, sheet 1 was revised, and the error is being tracked in its corrective action program.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.4.2-2

acceptable. Therefore, the staff's concern described in RAI 2.3.4.2-2 is resolved.

RAI 2.3.4.2-3. FSAR Section 10.1 describes the primary design system function of the

feedwater system including provisions for blowdown from the SGs. Portions of the ESFAS also

provide actuation signals for feedwater system isolation including the SG blowdown lines.

Drawing LR-M-201 sheet 3, at location F-1 0 indicates that the blowdown lines from the steam

generators A and B are within the scope of license renewal. However, drawing LR-M-2201,

sheet-3, at location F-1 indicates that these sections of SG blowdown pressure boundary piping

are not within the scope of license renewal for Unit 2. Also, drawing LR-M-201, sheet 1, at

location E-8 indicates that this section of piping is not within the scope of license renewal for

Unit 1, contrary to drawing LR-M-201, sheet 3. If the blowdown lines from the SGs are relied

upon for a pressure boundary function and isolation on an ESFAS signal, then their failure

could adversely impact their intended functions. In RAI 2.3.4.2-3, dated November 16, 2004,

the staff requested the applicant to clarify which sections of the steam generator blowdown

lines have pressure boundary functions and should be within the scope of license renewal and

subject to an AMR. The applicant was further asked to justify its determination of those

portions of the blowdown piping that are outside the scope of license renewal.

In its response, dated December 22, 2004, the applicant stated that this was a highlighting error

on drawing LR-M-2201, sheet 3. The applicant further stated that the upstream piping is within

the scope of license renewal as indicated on sheet 1 of this drawing, but the transition arrow

was missed on sheet 3 of the drawing. The applicant also stated that, in both units, the

blowdown piping between the SGs up to and including valves 1/2MS-2042 and 1/2MS-2045 is

within the scope of license renewal and subject to aging management. According to the

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applicant, drawing LR-M-2201, sheet 3 was revised, and the error is being tracked in its

corrective action program.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.4.2-3

acceptable. The applicant confirmed that the blowdown lines questioned by the staff are within

the scope of license renewal. Therefore, the staff's concerns described in RAI 2.3.4.2-3 are

resolved.

2.3.4.2.3 Conclusion

The staff reviewed the LRA, the accompanying scoping boundary drawings, the April 29 and

July 19, 2005, letters, and the RAI responses described above to determine whether any SSCs

that should be within the scope of license renewal were not identified by the applicant. No

omissions were identified. In addition, the staff performed a review to determine whether any of

the components that should be subject to an AMR were not identified by the applicant. No

omissions were identified. On the basis of its review, the staff concluded that there is

reasonable assurance that the applicant adequately identified the feedwater and condensate

system components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and that the applicant adequately identified the feedwater and condensate

system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.4.3 Auxiliary Feedwater System

2.3.4.3.1 Summary of Technical Information in the Application

In LRA Section 2.3.4.3, the applicant described the auxiliary feedwater (AFW) system. The

AFW system is designed to supply high-pressure feedwater to the SGs in order to maintain a

water inventory for the removal of heat energy from the RCS. This can be achieved through

secondary side steam release in the event of inoperability or unavailability of the main

feedwater subsystem. One turbine-driven AFW pump (per unit) and two electric-driven AFW

pumps (shared by the two units) are provided to ensure that adequate feedwater is supplied to

the SGs to remove heat under all circumstances, including loss of power and loss of normal

heat sink. Auxiliary feedwater flow can be maintained until power is restored or reactor decay

heat removal can be accomplished by other systems.

The portions of the AFW system subject to an AMR extend from the condensate storage tanks

(CSTs) to the SGs, including the associated pumps, piping, valves, and portions of the air

subsystem that are required to function after loss of normal plant air supply.

Functions associated with the AFW system include the following:

* provides emergency heat removal from the reactor coolant system using secondary

heat removal capability

* removes heat from the turbine bearing coolers

* provides a primary containment boundary to prevent the release of radioactivity into the

environment

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The failure of nonsafety-related SSCs In the system could prevent the satisfactory

accomplishment of a safety-related function. In addition, the AFW system performs functions

that support environmental qualification, fire protection, anticipated transient without scram, and

station blackout.

Intended functions within the scope of license renewal include the following:

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

* provides for mechanical closure integrity on bolted joints

* provides for heat transfer

* provides for flow restriction

In LRA Table 2.3.4-3, the applicant identified the following AFW system component types that

are within the scope of license renewal and subject to an AMR:

* accumulators and cylinders * pump casing

* CS components * restricting orifices

* fasteners and bolting * tanks

* flow elements * turbine casing

* heat exchanger * valve bodies

* instrument valve assemblies * valve operator

* piping and fittings

2.3.4.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.3 and FSAR Sections 5.2, 7.4, 10.0, and 10.2. The

staff's review, using the evaluation methodology described in SER Section 2.3, was conducted

in accordance with the guidance described in NUREG-1 800, Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had

identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR in

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

The staff's review of LRA Section 2.3.4.3 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAls as discussed below.

RAI 2.3.4.3-1. FSAR Section 10.2 states that the AFW system has several safety-related

functions, including supplying high-pressure feedwater to the SGs in order to maintain a water

inventory for removal of heat energy from the reactor under specific accident conditions.

Drawing LR-M-217, sheet 2, quadrant B-2, identifies a portion of the SW return piping from

AFW pump 1 P-29 as outside the scope of license renewal. This is inconsistent with the

drawing LR-M-207, sheet 1 A, quadrant B-9, that shows the return SW piping from AFW pump

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1 P-29 as within the scope of license renewal. Failure of the out-of-scope return line may affect

the pressure boundary integrity of the AFW system. In RAI 2.3.4.3-1, dated

November 16, 2004, the staff requested the applicant to clarify whether this portion of SW

piping is within the scope of license renewal; if it is not, the staff requested the applicant to

provide justification for not considering this piping within the scope of license renewal.

In its response, dated December 22, 2004, the applicant stated that this was a highlighting error

on drawing LR-M-217, sheet 2. The applicant further stated that the SW piping (supply and

return for the AFW pump bearings) is within the scope of license renewal, as depicted on

drawing LR-M-207, sheet 1 A, and would be subject to aging management. According to the

applicant, the drawing LR-M-217, sheet 2 was revised, and the error is being tracked in its

corrective action program.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.4.3-1

acceptable. Therefore, the staff's concern described in RAI 2.3.4.3-1 is resolved.

RAI 2.3.4.3-2. FSAR Section 10.2 states the AFW system has several safety-related functions

including supplying high-pressure feedwater to the SGs in order to maintain a water inventory

for removal of heat energy from the reactor under specific accident conditions. Drawing

LR-M-217, sheet 2, quadrant B-3, identifies a portion of the air supply piping to valve 1 MS

2090 as within the scope of license renewal. This is inconsistent with the drawing LR-M-207,

sheet IA, quadrant C-10, which shows the pneumatic supply line to I MS 2090 as outside the

scope of license renewal. Failure of the out-of-scope pneumatic supply line may adversely

impact the safety-related functions of the AFW system. In RAI 2.3.4.3-2, dated

November 16, 2004, the staff requested the applicant to clarify whether this portion of air supply

piping is within the scope of license renewal; if it is not, the staff requested the applicant to

provide justification for not considering this piping within the scope of license renewal.

In its response, dated December 22, 2004, the applicant stated that this was a highlighting error

on drawing LR-M-217, sheet 2. The solenoid valve associated with 1 MS 2090 is within the

scope of license renewal, but it is an active component and, therefore, is not subject to aging

management. The applicant also stated that the air piping between the solenoid and valve is

not in-scope, because it has no intended function. If this air tubing were to fail, the valve would

go to its fail-safe position, and would not impact the intended function of the valve (i.e., to

supply SW to the bearings). According to the applicant, the drawing LR-M-217, sheet 2 was

revised, and the error is being tracked in its corrective action program.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.4.3-2

acceptable. Therefore, the staff's concern described in RAI 2.3.4.3-2 is resolved.

RAI 2.3.4.3-3. FSAR Section 10.2 states the AFW system has several safety-related functions,

including supplying high-pressure feedwater to the SGs in order to maintain a water inventory

for removal of heat energy from the reactor under specific accident conditions. Drawing

LR-M-217, sheet 2, quadrant E-8 identifies a portion of the air supply piping to valve 2 MS 2090

as within the scope of license renewal. This is inconsistent with drawing LR-M-207, sheet IA,

quadrant G-1 0 that shows the pneumatic supply line to 2 MS 2090 as outside the scope of

license renewal. Failure of the out-of-scope pneumatic supply line may adversely impact the

safety-related functions of the AFW system. In RAI 2.3.4.3-3, dated November 16, 2004, the

staff requested the applicant to clarify whether this portion of air supply piping is within the

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scope of license renewal; if it is not, the staff requested the applicant to provide justification for

not considering this piping within the scope of license renewal.

In Its response, dated December 22, 2004, the applicant stated that this was a highlighting error

on drawing LR-M-217, sheet 2. The solenoid valve associated with 2 MS 2090 is within the

scope of license renewal, but it is an active component and, therefore, is not subject to aging

management. The applicant also stated that the air piping between the solenoid and valve is

not in-scope, because it has no intended function. If this air tubing were to fail, the valve would

go to its fail-safe position, and would not impact the intended function of the valve (i.e., to

supply SW to the bearings). According to the applicant, drawing LR-M-217, sheet 2 was

revised, and the error is being tracked in its corrective action program.

Based on the above discussion, the staff found the applicant's response to RAI 2.3.4.3-3

acceptable. Therefore, the staff's concern described in RAI 2.3.4.3-3 is resolved.

2.3.4.3.3 Conclusion

The staff reviewed the LRA, the accompanying scoping boundary drawings, and the RAI

responses described above to determine whether any SSCs that should be within the scope of

license renewal were not identified by the applicant. No omissions were identified. In addition,

the staff performed a review to determine whether any of the components that should be

subject to an AMR were not identified by the applicant. No omissions were identified. On the

basis of its review, the staff concluded that there is reasonable assurance that the applicant

adequately identified the AFW system components that are within the scope of license renewal,

as required by 10 CFR 54.4(a), and that the applicant adequately identified the AFW system

components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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

Supports

This section documents the staff's review of the applicant's scoping and screening results for

containments, structures, and component supports. Specifically, this section discusses the

following containments, structures, and component supports:

* Units 1 and 2 containment building

* control building

* circulating water pumphouse

* diesel generator building

* Units 1 and 2 facade

* primary auxiliary building (PAB)

* Units 1 and 2 turbine building

* yard structures

* cranes, hoists, and lifting devices

* component supports commodity group

* fire barrier commodity group

* 13.8 kV switchgear building

* fuel oil pumphouse

* gas turbine building

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In accordance with the requirements of 10 CFR 54.21 (a)(1), the applicant must identify and list

passive, long-lived containments, structures, and component supports 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 there was no omissions of containments, structures, and component

supports that meet the scoping criteria and are subject to an AMR.

Staff Evaluation Methodolo v. The staff's evaluation of the information provided in the LRA

was performed in the same manner for all containments, structures, and component supports.

The objective of the review was to determine if the components and supporting structures for a

specific containment, structure or containment support that appeared to meet the scoping

criteria specified in the Rule were identified by the applicant as within the scope of license

renewal in accordance with 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 had not been

identified as within the scope of renewal. The staff reviewed relevant licensing basis

documents, including the final safety analysis report (FSAR), for each containment, structure,

and component support to determine if the applicant had omitted system components with

intended functions delineated under 10 CFR 54.4(a) from the scope of license renewal. The

staff also reviewed the licensing basis documents to determine if all intended functions

delineated under 10 CFR 54.4(a) were specified in the LRA. If omissions were identified, the

staff requested additional information to resolve the discrepancies.

As documented under RAI 2.1-1 in SER Section 2.1, by letter dated April 29, 2005, the

applicant changed the methodology used to determine the nonsafety-related SCs that are

within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(2).

As a result of the implementation of the scoping methodology changes, the applicant identified

no new containment, structures, and supports component groups within the scope of license

renewal.

Screening. After completing its scoping evaluation, the staff reviewed the applicant's screening

results. For those SCs with intended functions, the staff sought to determine: (1) if the

function(s) are performed with moving parts or involve a change in configuration or properties,

or (2) if they are subject to replacement based on a qualified life or specific 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 containments, structures, and component supports 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.

The corresponding subsections of this SER (2.4.1 - 2.4.14) present the staff's review findings

with respect to the containments, structures, and component supports for both Units 1 and 2.

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2.4.1 Containment Units 1 and 2 Building Structure

2.4.1.1 Summary of Technical Information In the Application

In LRA Section 2.4.1, the applicant identified the structures and components of the Units 1 and

2 containment building structure that are subject to an AMR for license renewal. Both the

Units 1 and 2 containments are essentially identical in design and construction. The structures

consist of two prestressed, post-tensioned, reinforced concrete cylinders with flat base slabs

and shallow domed roofs. The structures provide biological shielding for both normal and

accident situations. Each containment structure is entirely housed in an unheated enclosure

(facade) that provides protection from the weather. The various components of the

containment structures include: the concrete wall structure, steel wall liner, reinforced concrete

and steel-framed internal structures, electrical penetrations, large equipment access, personnel

airlocks, and fuel access penetration. Major components include the liner plate, penetrations,

airlocks and equipment hatches.

The portions of the Units 1 and 2 containment building structure containing components subject

to an AMR include the walls, dome, foundations, tendons, internal structures, floors, ceilings,

beams, and columns.

Functions associated with the Units 1 and 2 containment building structure include the

following:

* provides a primary containment boundary by enclosing the entire reactor and coolant

system to ensure that an acceptable upper limit of leakage of radioactive materials to

the environment is not exceeded

* houses a substantial amount of safety-related mechanical and electrical equipment and

components

The failure of nonsafety-related systems, structures and components in the structure could

prevent the satisfactory accomplishment of a safety-related function. Specifically, the internal

structure of the containment structure houses and supports the refueling cavity, which utilizes

the reactor cavity seal ring during refueling. In addition, the Units 1 and 2 containment building

structure performs functions that support fire protection.

Intended functions within the scope of license renewal include the following:

* provides a spray shield or curbs for directing flow (e.g., safety injection flow to

containment sump)

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

* provides shelter or protection for safety-related components

* provides structural support for nonsafety-related components whose failure could

prevent satisfactory accomplishment of any of the required safety-related functions or

regulated event functions

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* provides a rated fire barrier to confine or retard a fire from spreading to or from adjacent

areas of the plant

* provides a barrier to protect against internal and external flooding events

* provides a heat sink during station blackout or design-basis accidents

* provides a barrier for protection against internally or externally generated missiles

* provides for pipe whip restraint

* provides shielding against radiation

In LRA Table 2.4.1-1, the applicant identified the following containment Units 1 and 2 building

structure component types that are within the scope of license renewal and subject to an AMR:

* buried concrete (foundation - basemat)

* indoor concrete (cylinder walls and buttresses, dome and ring girder)

* indoor concrete (internal structure - columns, beams, slabs, and walls)

* borated water elastomer (RV cavity seal ring)

* indoor elastomer (airlock door seals, penetrations - electrical)

* indoor grout (column baseplates; miscellaneous steel structures)

* indoor structural carbon steel fasteners (dome truss, miscellaneous steel structures,

cast-in-place anchor bolts)

* indoor structural carbon steel (airlocks and equipment hatches including bolting)

* indoor structural carbon steel (containment liner and keyway channels)

* indoor structural carbon steel (exposed portions of embedded steel; framing - columns,

beams, bracing, baseplates, dome truss, and crane supports; platforms, grating, stairs,

ladders, and checkered plates; CRDM missile shield)

* indoor structural carbon steel (penetrations - electrical)

* indoor structural carbon steel (penetrations - mechanical, including bolting)

* indoor structural carbon steel (post-tensioning tendons)

* indoor structural copper alloy (airlock bushings)

* indoor structural stainless steel fasteners (miscellaneous items)

* borated water structural stainless steel (refueling cavity liner; sandbox covers including

bolting; plates, bars, strips, and rods associated with the RC; fuel transfer tube including

bolting)

* indoor structural stainless steel (penetrations - electrical)

* indoor structural stainless steel (miscellaneous items, reactor cavity liner)

* buried structural steel piles (carbon steel h-piles - foundation)

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2.4.1.2 Staff Evaluation

The staff reviewed LRA Section 2.4.1 using the evaluation methodology described in SER

Section 2.4. The staff conducted its review in accordance with the guidance described in

NUREG-1 800, Section 2.4, "Scoping and Screening Results: Structures."

In conducting its review, the staff evaluated the structural or component functions described in

the LRA and FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant did not omit from the scope of license renewal any components with intendeo

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR in

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

The staff's review of LRA Section 2.4.1 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

RAI 2.4-1. The staff's review of LRA Section 2.4.1 and Table 2.4.1-1 identified the word "ALL"

at the end of each component group. In RAI 2.4-1, dated January 26, 2005, the staff requested

the applicant to clarify the usage of the word "ALL" for the component groups.

In its response, dated February 25, 2005, the applicant stated that the intent of "ALL" at the end

of each component group was to signify that "ALL" of the material/environment items

associated with the component group were included. No further meaning or intent was implied.

Based on the above discussion, the staff found this clarification acceptable. The staff's concern

described in RAI 2.4-1 is resolved.

RAI 2.4-3. The LRA Section 2.4 does not appear to contain information about thermal

insulation on piping and/or structures that perform an intended function. The staff is aware that

the concrete temperatures around the main steam and feedwater lines were found to be about

380 OF for an unknown period of time. Thermal insulation is usually used between the hot

piping and concrete to maintain the -maximum temperature of concrete below the threshold

levels of 150 OF for general areas and 200 OF for local areas around hot penetrations. Thermal

insulation is passive and long-lived, and serves an intended function in accordance with

10 CFR 54.4(a)(2). Therefore, in RAI 2.4-3, dated January 26, 2005, the staff requested the

applicant to: (1) identify the locations of the thermal insulation that serves an intended function

in accordance with 10 CFR 54.4(a)(2), (2) describe plant-specific operating experience related

to the degradation of thermal insulation, and (3) describe the scoping and screening results of

thermal insulation and provide the technical bases for its exclusion from the scope of license

renewal.

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In its response, dated February 25, 2005, the applicant stated:

Thermal insulation for structures is discussed in Section 2.1.3.1.2, page 2-45, of the

LRA.

2.1.3.1.2 Screening of Thermal Insulation

In response to NRC staff requests for additional information (RAls) on other

license renewal applications, a screening review has been performed of thermal

insulation. The review identified only one location where thermal insulation is

within the scope of license renewal. Insulation is installed on the main steam

and main feedwater containment penetrations, and is needed to maintain

steady-state concrete temperatures less than 150 OF. This insulation is enclosed

in the annulus and is not subject to wetting, and there are no plausible aging

effects that could warrant aging management.

The insulation for the containment penetrations is considered to be in-scope but having

no intended functions or aging effects. The initial request for plant-specific operating

experience regarding the degradation of thermal insulation on the containment

penetrations was contained in RAI 3.5-3. The operating experience was provided by

NMC letter dated August 26, 2004. In that letter, NMC committed to inspect the

penetrations that exhibited the high temperature (i.e., greater than 150 OF).

Based on the above discussion, the staff found the applicant's response to RAI 2.4-3

acceptable. The applicant has committed to inspect the penetrations that exhibited high

temperature (i.e., greater than 150 OF). The staff's concern described in RAI 2.4-3 is resolved.

2.4.1.3 Conclusion

The staff reviewed the LRA, its related structural or component information, and RAI responses

described above to determine whether any SSCs that should be within the scope of license

renewal were not identified by the applicant. No omissions were identified. In addition, the staff

performed a review to determine whether any components that should be subject to an AMR

were not identified by the applicant. No omissions were identified. On the basis of its review,

the staff concluded that there is reasonable assurance that the applicant adequately identified

the Units 1 and 2 containment building structure components that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and that the applicant adequately identified the

Units 1 and 2 containment building structure components that are subject to an AMR, as

required by 10 CFR 54.21 (a)(1).

2.4.2 Control Building Structure

2.4.2.1 Summary of Technical Information in the Application

In LRA Section 2.4.2, the applicant identified the structures and components of the control

building (CB) structure that are subject to an AMR for license renewal. The CB is a rectangular,

safety-related, seismic Class 1 structure that is constructed from reinforced concrete with

internal bracing that is provided by reinforced concrete walls, columns, and floors. The CB is

adjacent to the primary auxiliary building (PAB) and enveloped by the Units 1 and 2 turbine

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buildings (TBs). The CB is enclosed within the turbine buildings, but is considered an

independent structure since it has no fixed structural attachments to either the TBs, or the PAB.

The portions of the CB structure containing components subject to an AMR include the walls,

roof, foundations, floors, doors, ceilings, beams, and columns.

The CB structure provides structural support and housing for safety Class 1, 2, and 3 systems,

structures, and components (SSCs). The failure of nonsafety-related SSCs in the structure

could prevent the satisfactory accomplishment of a safety-related function. In addition, the CB

structure performs functions that support fire protection and station blackout.

Intended functions within the scope of license renewal include the following:

* provides shelter or protection for safety-related components

* provides structural support to nonsafety-related components whose failure could prevent

satisfactory accomplishment of any of the required safety-related functions or regulated

event functions

* provides a rated fire barrier to confine or retard a fire from spreading to or from adjacent

areas of the plant

* provides a barrier to protect against internal and external flooding events

* provides a heat sink during station blackout or design-basis accidents

* provides shielding against high energy line breaks

* provides a barrier for protection against internally or externally generated missiles

* provides shielding against radiation

* provides structural and/or functional support to safety-related equipment

In LRA Table 2.4.2-1, the applicant identified the following CB structure component types that

are within the scope of license renewal and subject to an AMR:

* buried concrete (foundation - spread footings)

* indoor concrete (walls, ceilings, floors, columns, equipment pedestals; spray walls

(AFWP room))

* indoor concrete (wall - east)

* indoor doors

* indoor elastomers (rubber flap - diesel generator room (DGR) louver; rubber sill, sweep -

flood doors; gasket and seals - control room doors)

* indoor glass (glass windows - control room wall (north, south, and east); glass windows -

computer room (east wall))

* indoor grout (miscellaneous steel structures)

* outdoor masonry block wall (DGR - east wall)

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* indoor masonry block walls (battery room, non-vital switchgear room (non-VSR), control

room - internal, DGR and AFW pump room tunnel)

* indoor structural carbon steel fasteners (subsoil drain cover; wall panels and plates,

bracing; HELB and flood barriers; door braces; platforms, stairs)

* outdoor structural carbon steel fasteners (missile shield - DGR; comer plates - DGR

(east wall))

* indoor structural carbon steel (HELB barriers - cable spreading room (CSR) north and

south wall, non-VSR - south wall and braces, and east wall barriers around cable trays;

SW guard pipe - battery room; condensate storage tank supply guard pipe - 1 E battery

room (26 EL); door braces - VSR south and west walls; wall plates - CSR north and

south walls; wall panels - control room north, south and east walls; flood barrier -

non-VSR (east wall); masonry wall bracing; platforms, stairs)

* outdoor structural carbon steel (missile barrier and bracing - DGR air intake)

* indoor structural cast iron (floor drain covers and flanges (DGR, vital switchgear room

(VSR), AFWP room)

* outdoor wood (missile shield - integral part of diesel generator air intake)

2.4.2.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2 and the FSAR. The staff's review, using the evaluation

methodology described in SER Section 2.4, was conducted in accordance with the guidance

described in NUREG-1 800, Section 2.4.

In conducting its review, the staff evaluated the structural or component functions described in

the LRA and FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant did not omit from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR in

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

The staff's review of LRA Section 2.4.2 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

RAI 2.4-4. LRA Table 2.4.2-1 lists outdoor wood as a component group within the scope of

license renewal and missile barrier as the intended function for the control building structure. In

RAI 2.4-4, dated January 26, 2005, the staff requested the applicant to explain what this

outdoor wood component is and how the wood component serves as a missile barrier.

In its response, dated February 25, 2005, the applicant stated that the emergency diesel

generator air-intake louvers are protected by a missile barrier. The missile of concern is from

environmental sources. The missile barrier is constructed from structural steel and the outside

face is made from C-channels. Treated wood timbers are bolted to the C-channels and are part

of the missile barrier along with the steel C-channel.

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Based on the above discussion, the staff found the applicant's response to RAI 2.4-4

acceptable, because the wood is a part of the steel missile barrier. The staff's concern

described in RAI 2.4-4 is resolved.

2.4.2.3 Conclusion

The staff reviewed the LRA, its related structural or component information, and RAI response

described above to determine whether any SSCs that should be within the scope of license

renewal were not identified by the applicant. No omissions were identified. In addition, the staff

performed a review to determine whether any components that should be subject to an AMR

were not identified by the applicant. No omissions were identified. On the basis of its review,

the staff concluded that there is reasonable assurance that the applicant adequately identified

the control building structure components that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and that the applicant adequately identified the control building

structure components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.4:3 Circulating Water Pumphouse Structure

2.4.3.1 Summary of Technical Information In the Application

In LRA Section 2.4.3, the applicant identified the structures and components of the circulating

water pumphouse (CWPH) structure that are subject to an AMR for license renewal. The

CWPH structure consists of four interconnected facilities: forebay, CWPH building, intake crib,

and discharge flumes. Only the forebay and CWPH building are within the scope of license

renewal. In an emergency, there are four separate flow paths into the forebay (two intake pipes

and two discharge flumes). However, only one flow path is needed. The nonsafety-related

intake crib is completely submerged offshore. It connects with the forebay's surge chambers

via two 14-foot-diameter pipes that are buried beneath the lakebed. The forebay channels the

water to the pump bay within the CWPH building. The CWPH building contains pumps for the

circulating water system, SW system, and fire protection system. Two nonsafety-related

discharge flumes are attached to the east wall of the forebay's seal wells and extend into Lake

Michigan. Circulating water discharge from the Units 1 and 2 condensers empties into its

respective seal well via two 12-foot-diameter pipes and then flows to the discharge flumes via

14-foot-diameter valves.

The portions of the CWPH structure containing components subject to an AMR include the

walls, roof, foundations, floors, doors, ceilings, beams, and columns.

The CWPH structure structurally supports and houses six safety-related SW pumps. In

addition, the CWPH structure performs functions that support fire protection.

Intended functions within the scope of license renewal include the following:

* provides shelter or protection for safety-related components

* provides structural and/or functional support to safety-related equipment

* provides a rated fire barrier to confine or retard a fire from spreading to or from adjacent

areas of the plant

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* provides a barrier to protect against internal and external flooding events

* provides a barrier to protect against internally or externally generated missiles

* provides a source of cooling water for plant shutdown

In LRA Table 2.4.3-1, the applicant identified the following CWPH structure component types

that are within the scope of license renewal and subject to an AMR:

* buried concrete (foundation - basemat)

* indoor concrete (floors; missile barrier; non-combustible wall (SW pumps))

* outdoor concrete (walls, roof)

* raw water concrete (forebay structure and pump bays)

* indoor doors (all doors throughout the building)

* indoor grout (column baseplates)

* indoor structural carbon steel fasteners (structural steel framing)

* indoor structural carbon steel(framing - columns, beams)

2.4.3.2 Staff Evaluation

The staff reviewed LRA Section 2.4.3 and the FSAR. The staff's review, using the evaluation

methodology described in SER Section 2.4, was conducted in accordance with the guidance

described in NUREG-1800, Section 2.4.

In conducting its review, the staff evaluated the structural or component functions described in

the LRA and FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant did not omit from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR in

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

The staff's review of LRA Section 2.4.3 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAls as discussed below.

RAI 2.4-5. LRA Section 2.4.3 states that the intake crib and the discharge flumes are

connected to the forebay and the CWPH structures and provide functions for water intake and

discharge, respectively. However, only the forebay and the CWPH structures are within the

scope of license renewal. In RAI 2.4-5, dated January 26, 2005, the staff requested the

applicant to provide justification for excluding the intake crib and the discharge flumes from

license renewal.

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In its response, dated February 25, 2005, the applicant stated:

The intake crib is located 1750 ft. from the shore in a water depth of 22 ft. Water flows

from the intake crib to the pumphouse forebay via two 14 ft. diameter, corrugated,

galvanized, structural plate pipes buried to a minimum depth of 3 ft. below the lake bed.

The water flows from a common Unit 1 and Unit 2 forebay through bar grates and

traveling screens (8) to the suction of the CW service water, and firewater pumps. The

water exits the plant through the two discharge flumes.

The Circulating Water Pumphouse is a seismic Class I structure common to Unit 1 and

Unit 2. It houses the firewater and service water pumps in addition to the CW pumps.

The intake crib, intake pipes, forebay bar grates, discharge flumes, and traveling

screens are nonsafety-related, non-QA, seismic class IlIl structures and components.

There are four separate and independent flow paths into the forebay. Included are two

14-ft. diameter offshore intake pipes and backflow from two CW discharge flow paths.

The CW discharge flow paths consist of backf low from the discharge flume into the

surge chamber via the sealwell. Any one of the four independent flow paths will provide

substantially more flow than the firewater and service water pump supply requirements.

The service water and firewater system need to pass less than 5% of the Circulating

Water Pumphouse total design capacity (i.e., 712,000 gpm). No credible simultaneous

failure of the four independent flow paths could occur to preclude lake water from

reaching the firewater and service water pumps.

AEC Safety Evaluation dated July 15, 1970, evaluated the failure of both 14-ft.

diameter offshore intake pipes. In this event, it was concluded that lake water for

service water pumps can be provided directly to the seal well from the CW discharge

flume. AOP-1 3A Circulating Water System Malfunction," provides this guidance in the

event of blockage of the intake crib and dropping forebay level.

In conclusion the non-safety-related, non-QA, and seismic class IlIl intake crib, intake

pipes, and discharge flumes do not affect any safety-related system structure or

component (SSC) intended functions in accordance with 10 CFR 54.4(a)(2) and

therefore are not within the scope of license renewal.

Based on the above discussion, the staff found the applicant's response to RAI 2.4-5

acceptable. The intake crib and the discharge flume do not affect any intended function of

safety-related SSCs. The staff's concern described in RAI 2.4-5 is resolved.

RAI 2.4-6. The staff was unable to identify whether the traveling water screens, as shown in

the license renewal drawing LR-M-212-SH-2, are included within the scope of license renewal.

In RAI 2.4-6, dated January 26, 2005, the staff requested the applicant to indicate if they are

in-scope and where in the LRA these are discussed. If the traveling screens are outside the

scope of license renewal, the staff requested the applicant to justify their exclusion from the

scope of license renewal.

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In its response, dated February 25, 2005, the applicant stated:

The traveling water screens are not within the scope of license renewal. The forebay

bar grates and traveling screens are non-safety-related, non-QA, seismic class IlIl

structures and components. The service water and firewater pumps are the essential

plant equipment that always require a water supply. The Circulating Water Pumphouse

structures and components are designed/sized for a maximum CW flow rate of 712,000

gpm (both units or 178,000 gpm per CW pump) plus the flow rates of the service water

and firewater pumps.

Typical flow rates for the service water system in accident conditions vary, up to a

maximum of 21,000 gpm (one unit in normal operation, second unit experiencing a

design basis accident). The flow rates of the service water and firewater pumps

represent less than 5% of the total design flow (i.e., 712,000 gpm) into the forebay.

Neither the non-safety-related forebay bar grates (gross filtration) or traveling screens

(finer filtration) could prevent passing the less than 5% total design flow rate from

reaching the suction of the firewater or service water pumps. It is not credible that a

total blockage condition could develop, (i.e., a non-safety affecting safety condition).

The bar grates and traveling screens are not relied on in a safety analyses or plant

evaluations to perform a function that demonstrates compliance with the NRC's

regulations for fire protection (FP).

In conclusion, the nonsafety-related, non-QA, seismic class III traveling screens are

out-of-scope of license renewal. Substantial clogging of these components will not

prevent the firewater or service water pumps from obtaining minimum supply

requirements.

Based on the above discussion, the staff found the applicant's response to RAI 2.4-6

acceptable. The traveling water screens do not affect any intended function of safety-related

SSCs. The staff's concern described in RAI 2.4-6 is resolved.

2.4.3.3 Conclusion

The staff reviewed the LRA, its related structural or component information, and RAI responses

described above to determine whether any SSCs that should be within the scope of license

renewal were not identified by the applicant. No omissions were identified. In addition, the staff

performed a review to determine whether any components that should be subject to an AMR

were not identified by the applicant. No omissions were identified. On the basis of its review,

the staff concluded that there is reasonable assurance that the applicant adequately identified

the circulating water pumphouse structure components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and that the applicant adequately identified the

circulating water pumphouse structure components that are subject to an AMR, as required by

10 CFR 54.21(a)(1).

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2.4.4 Diesel Generator Building Structure

2.4.4.1 Summary of Technical Information In the Application

In LRA Section 2.4.4, the applicant identified the structures and components of the diesel

generator building (DGB) structure that are subject to an AMR for license renewal. The DGB is

a rectangular, safety-related, seismic Class 1 structure with an attached, nonsafety-related,

seismic Class 3, stairway-passageway enclosure along the building's west side. The building is

an independent structure with no other buildings in its immediate vicinity. The safety-related,

seismic Class 1 portion of the DGB is constructed from reinforced concrete with internal bracing

provided by reinforced concrete walls and floors. The DGB houses the train 'B' emergency

diesel generators (EDGs), including their support equipment and distribution switchgear, the

fuel oil storage tanks, and the fuel oil transfer pumps that service all four EDGs.

The portions of the DGB structure containing components subject to an AMR include the walls,

roof, foundations, floors, doors, ceilings, beams, and columns.

The DGB structure provides structural support and housing to safety-related SSCs. The failure

of nonsafety-related SSCs in the structure could prevent the satisfactory accomplishment of a

safety-related function. In addition, the DGB structure performs functions that support fire

protection and station blackout.

Intended functions within the scope of license renewal include the following:

* provides shelter or protection for safety-related components

* provides structural support to nonsafety-related components whose failure could prevent

satisfactory accomplishment of any of the required safety-related functions or regulated

event functions

* provides structural and/or functional support to safety-related equipment

* provides a rated fire barrier to confine or retard a fire from spreading to or from adjacent

areas of the plant

* provides a barrier for protection against internally or externally generated missiles

In LRA Table 2.4.4-1, the applicant identified the following DGB structure component types that

are within the scope of license renewal and subject to an AMR:

* buried concrete (foundation - footings and basemat)

* indoor concrete (walls, floors, and ceilings)

* outdoor concrete (walls, roof)

* outdoor doors

* indoor doors

* indoor grout (platforms, stairs)

* indoor structural carbon steel fasteners (platforms, stairs; missile shields)

* indoor structural carbon steel fasteners (missile shields)

* indoor structural carbon steel (framing - crane rails supports; platforms, stairs)

* outdoor structural carbon steel (missile shields, wall plates at missile shields)

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2.4.4.2 Staff Evaluation

The staff reviewed LRA Section 2.4.4 and the FSAR. The staff's review, using the evaluation

methodology described in SER Section 2.4, was conducted in accordance with the guidance

described in NUREG-1800, Section 2.4.

In conducting its review, the staff evaluated the structural or component functions described in

the LRA and FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant did not omit from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR in

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

2.4.4.3 Conclusion

The staff reviewed the LRA and its related structural or component information to determine

whether any SSCs that should be within the scope of license renewal were not identified by the

applicant. No omissions were identified. In addition, the staff performed a review to determine

whether any components that should be subject to an AMR were not identified by the applicant.

No omissions were identified. On the basis of its review, the staff concluded that there is

reasonable assurance that the applicant adequately identified the diesel generator building

structure components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and that the applicant adequately identified the diesel generator building

structure components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.4.5 Facade Units 1 and 2 Structure

2.4.5.1 Summary of Technical Information In the Application

In LRA Section 2.4.5, the applicant identified the structures and components of the Units 1 and

2 facade structure that are subject to an AMR for license renewal. The Units 1 and 2 facade

structures are seismic Class 3 structures consisting primarily of steel framing and metal siding.

The facade's perimeter wall framing is supported vertically on reinforced concrete walls that are

supported by an independent, reinforced concrete foundation. The facade structures have no

intermediate floors other than a stair tower that provides access to upper elevations of the PAB

and the containment. The facades surround and enclose the reinforced concrete containment

structures and function primarily to provide the containments with a sheltered environment.

The portions of the Units 1 and 2 facade structure containing components subject to an AMR

include the walls, roof truss, foundations, beams, and columns.

The failure of nonsafety-related SSCs in the Units 1 and 2 facade structure could prevent the

satisfactoryaccomplishment of a safety-related function. Specifically, the structures provide no

physical protection from design-basis external hazards, but do provide weather protection for

equipment and personnel.

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Intended function within the scope of license renewal is to provide structural support to

nonsafety-related components whose failure could prevent the satisfactory accomplishment of

any of the required safety-related functions or regulated event functions.

In LRA Table 2.4.5-1, the applicant identified the following Units 1 and 2 facade structure

component types that are within the scope of license renewal and subject to an AMR:

* buried concrete (foundation - spread footings)

* indoor concrete (floor)

* outdoor concrete (retaining walls)

* indoor grout (column baseplates)

* indoor masonry block wall (elevators and stairs towers)

* indoor structural carbon steel fasteners (structural steel framing, steel framing for

elevator and stair towers)

* indoor structural carbon steel (framing - columns, beams; roof truss)

2.4.5.2 Staff Evaluation

The staff reviewed LRA Section 2.4.5 and the FSAR. The staff's review, using the evaluation

methodology described in SER Section 2.4, was conducted in accordance with the guidance

described in NUREG-1 800, Section 2.4.

In conducting its review, the staff evaluated the structural or component functions described in

the LRA and FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant did not omit from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR in

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

2.4.5.3 ConclusIon

The staff reviewed the LRA and its related structural or component information to determine

whether any SSCs that should be within the scope of license renewal were not identified by the

applicant. No omissions were identified. In addition, the staff performed a review to determine

whether any components that should be subject to an AMR were not identified by the applicant.

No omissions were identified. On the basis of its review, the staff concluded that there is

reasonable assurance that the applicant adequately identified the Units 1 and 2 facade

structure components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and that the applicant adequately identified the Units 1 and 2 facade structure

components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.4.6 Primary Auxiliary Building Structure

2.4.6.1 Summary of Technical Information in the Application

In LRA Section 2.4.6, the applicant identified the structures and components of the primary

auxiliary building (PAB) structure that are subject to an AMR for license renewal. The PAB is a

rectangular, multi-floored, reinforced concrete and steel, framed structure, consisting of a

central area and two wings (north and south). The PAB internal bracing is provided by

reinforced concrete walls, floors, and slabs, and structural steel framing. The reinforced

concrete PAB central area and portions of the reinforced concrete north and south wings are

seismic Class 1 structures. The PAB's steel superstructure is a seismic Class 3 structure.

Each PAB area is founded on its own basemat.

The portions of the PAB structure containing components subject to an AMR include the new

and spent fuel storage racks, walls, roof, foundations, floors, doors, ceilings, beams, and

columns.

The PAB provides structural support and housing to safety-related SSCs. The failure of

nonsafety-related SSCs in the structure could prevent the satisfactory accomplishment of a

safety-related function. In addition, the PAB performs functions that support fire protection.

Intended functions within the scope of license renewal include the following:

* maintains the subcriticality of spent fuel

* provides shelter or protection for safety-related components

* provides structural support to nonsafety-related components whose failure could prevent

satisfactory accomplishment of any of the required safety-related functions or regulated

event functions

* provides structural and/or functional support to safety-related equipment

* provides a rated fire barrier to confine or retard a fire from spreading to or from adjacent

areas of the plant

* provides a barrier to protect against internal and external flooding events

* provides a barrier for protection against internally or externally generated missiles

* provides shielding for protection against high-energy line breaks (HELBs)

* provides a pressure-retaining boundary so that sufficient flow at adequate pressure is

delivered

* provides a spray shield or curbs for directing flow

In LRA Table 2.4.6-1, the applicant identified the following PAB structure component types that

are within the scope of license renewal and subject to an AMR:

* borated water Boraflex (spent fuel storage racks)

* buried concrete (foundation - basemat)

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* indoor concrete (walls, ceilings, floors; spent fuel pool)

* outdoor concrete (walls)

* indoor doors

* borated water elastomer (spent fuel pool gates)

* indoor elastomers (all rubber sill, sweep-flood doors)

* indoor grout (columns baseplates, miscellaneous steel structures)

* indoor masonry block wall (block walls (8-ft, 26-ft, 46-ft elevation))

* indoor structural carbon steel fasteners (structural steel framing)

* buried structural carbon steel piles (spent fuel pool)

* indoor structural carbon steel (crane support girders; framing - columns, beams; roof

truss; platforms, stairs)

* borated water structural stainless steel (spent fuel pool (SFP), SFP canal, SFP gates,

spent fuel storage racks)

* indoor structural stainless steel (new fuel storage racks)

2.4.6.2 Staff Evaluation

The staff reviewed LRA Section 2.4.6 and the FSAR. The staff's review, using the evaluation

methodology described in SER Section 2.4, was conducted in accordance with the guidance

described in NUREG-1800, Section 2.4.

In conducting its review, the staff evaluated the structural or component functions described in

the LRA and FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant did not omit from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR in

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

2.4,6.3 Conclusion

The staff reviewed the LRA and its related structural or component information t6 determine

whether any SSCs that should be within the scope of license renewal were not identified by the

applicant. No omissions were identified. In addition, the staff performed a review to determine

whether any components that should be subject to an AMR were not identified by the applicant.

No omissions were identified. On the basis of its review, the staff concluded that there is

reasonable assurance that the applicant adequately identified the PAB structure components

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the

applicant adequately identified the PAB structure components that are subject to an AMR, as

required by 10 CFR 54.21 (a)(1).

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2.4.7 Turbine Building Units 1 and 2 Structure

2.4.7.1 Summary of Technical Information In the Application

In LRA Section 2.4.7, the applicant identified the structures and components of the Units 1 and

2 turbine building (TB) structure that are subject to an AMR for license renewal. The Units 1

and 2 TBs are rectangular, nonsafety-related, seismic Class 3 structures that are constructed

from structural steel and reinforced concrete, with internal bracing provided by structural steel

columns and beams. The TBs are located adjacent to the PAB. The TBs are in a line, with the

Unit 1 building situated south of Unit 2 building; the Unit 1 to Unit 2 interface is located over the

control building. The TBs enclose the control building, except for the control building's east and

west walls. Lateral bracing exists between the TB's structural steel framing, the adjacent,

seismic Class 3, PAB's steel superstructure, and the south service building's steel framing. The

TBs have no fixed structural attachments with the adjacent, seismic Class 1 structures of the

control building and the lower reinforced portion of the PAB.

The portions of the Units 1 and 2 TB structure containing components subject to an AMR

include the walls, roof, foundations, floors, ceilings, beams, and columns.

The structural steel frame and foundation of the nonsafety-related Units 1 and 2 TB structure

provide support to SSCs with safety-related functions. In addition, the Units 1 and 2 TB

structure performs functions that support fire protection.

Intended functions within the scope of license renewal include the following:

* provides a rated fire barrier to confine or retard a fire from spreading to or from adjacent

areas of the plant

* provides structural support to nonsafety-related components whose failure could prevent

satisfactory accomplishment of any of the required safety-related functions or regulated

event functions

* provides structural and/or functional support to safety-related equipment

In LRA Table 2.4.7-1, the applicant identified the following Units 1 and 2 TB structure

component types that are within the scope of license renewal and subject to an AMR:

* buried concrete (foundation - spread footings and basemat, floor)

* indoor concrete (floors and walls (north, 8-ft and 26-ft elevation), turbine generator lube

oil reservoir area curbing, lube oil storage tank area walls)

* outdoor concrete (foundation walls)

* indoor grout (column baseplates)

* indoor masonry block walls (lube oil storage room walls (Unit 2 only))

* indoor structural carbon steel fasteners (structural steel framing, HELB barriers, flood

louvers, rollup door braces)

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* indoor structural carbon steel (flood louvers - east wall; door bracing - east wall; HELB

barrier - north wall; crane rails supports; framing - columns, beams; roof truss)

2.4.7.2 Staff Evaluation

The staff reviewed LRA Section 2.4.7 and the FSAR. The staff's review, using the evaluation

methodology described in SER Section 2.4, was conducted in accordance with the guidance

described in NUREG-1800, Section 2.4.

In conducting its review, the staff evaluated the structural or component functions described in

the LRA and FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant did not omit from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR in

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

2.4.7.3 Conclusion

The staff reviewed the LRA and its related structural or component information to determine

whether any SSCs that should be within the scope of license renewal were not identified by the

applicant. No omissions were identified. In addition, the staff performed a review to determine

whether any components that should be subject to an AMR were not identified by the applicant.

No omissions were identified. On the basis of its review, the staff concluded that there is

reasonable assurance that the applicant adequately identified the Units 1 and 2 TB structure

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

that the applicant adequately identified the Units 1 and 2 TB structure components that are

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

2.4.8 Yard Structures

2.4.8.1 Summary of Technical Information In the Application

In LRA Section 2.4.8, the applicant identified the structures and components of the yard

structures that are subject to an AMR for license renewal. The yard structures include electrical

manholes and duct banks, tank foundations, SBO equipment foundations, and earthen berm

barriers. Electrical manholes and duct banks contain safety-related and nonsafety-related

cables. Manholes are reinforced concrete, box-type structures with a reinforced concrete or

cast iron cover. Duct banks are reinforced concrete structures that encase galvanized steel

and PVC pipes which serve as conduits for the electrical cables. In-scope SBO components

include electrical distribution items needed for coping and power restoration. Typical yard

structures consist of the equipment foundations, pads, and support structures. The gas turbine

generator (GTG) fuel oil tank foundations and surrounding earthen berms are also included.

Other miscellaneous yard structures are not within the scope of license renewal.

The portions of the yard structures containing components subject to an AMR include the

concrete manholes and duct banks, electrical equipment concrete foundations and steel

support structures, and the earthen berms.

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The yard structures house several electrical manholes and their associated duct banks, which

contain safety-related cables. These SSCs are vital to plant safety and provide suitable

protection against severe, external, environmental phenomena. In addition, the yard structures

perform functions that support fire protection and station blackout.

Intended functions within the scope of license renewal include the following:

* provides shelter or protection for safety-related components

* provides structural support to nonsafety-related components whose failure could prevent

satisfactory accomplishment of any of the required safety-related functions or regulated

event functions

* provides structural and/or functional support to safety-related equipment

* provides a rated fire barrier to confine or retard a fire from spreading to or from adjacent

areas of the plant

In LRA Table 2.4.8-1, the applicant identified the following yard structure component types that

are within the scope of license renewal and subject to an AMR:

* buried concrete (electrical duct banks, equipment foundations and support pads,

manholes)

* indoor concrete (manhole interior)

* outdoor concrete (equipment foundations and support pads, manholes and covers)

* outdoor structural carbon steel fasteners/outdoor (switchyard equipment frames)

* outdoor structural carbon steel (manhole covers, framing - 345k VAC distribution

system, bus ducts - high-voltage station auxiliary transformers to circuit breaker

cabinets, bus ducts - low-voltage station auxiliary transformers to 13.8k VAC switchgear

cabinet)

* outdoor structural cast iron (manhole frames and covers)

* buried masonry block wall (manholes)

2.4.8.2 Staff Evaluation

The staff reviewed LRA Section 2.4.8 and the FSAR. The staff's review, using the evaluation

methodology described in SER Section 2.4, was conducted in accordance with the guidance

described in NUREG-1800, Section 2.4.

In conducting its review, the staff evaluated the structural or component functions described in

the LRA and FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant did not omit from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR in

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

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The staff's review of LRA Section 2.4.8 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAls as discussed below.

RAI 2.4-8. LRA Section 2.4.8 states that yard transformer and tower concrete foundations, and

transformer fire walls are not within the scope of license renewal. In RAI 2.4-8, dated

January 26, 2005, the staff requested the applicant to explain the function of each item listed

above and provide justification for their exclusion.

In its response, dated February 25, 2005, the applicant stated:

The license renewal electrical power distribution drawing depicting the in-scope

systems/components are shown on LR drawing LR-Electrical-E1. The corresponding

civil structures that support the power distribution are depicted on LR drawing LR-E-1 00,

Sheet 1. An example of a yard transformer that is not in-scope would be the

Unit Auxiliary Transformers (XO2s). Consequently, the foundation for the X02s would

not be in-scope. The High Voltage Station Auxiliary Transformers (XO3s) and their

corresponding foundations are an example of an in-scope transformer.

Four high voltage transmission line towers provide power to the switchyard. Each tower

has a concrete foundation. These towers are outside the in-scope area as defined by

the portions of the switchyard that are part of the CLB for SBO in accordance with

10 CFR 50.63. As depicted on LRA drawing LR-Electrical-E1, these towers and their

associated foundations are not in-scope.

The transformer firewall is a structure constructed between the two Low Voltage Station

Auxiliary Transformers (XO4s). The firewall was installed in 1991 as a result of a

weakness from a property loss stand point and reliability of offsite power as cited by

Nuclear Mutual Limited Insurance (NML). This wall is not installed to comply with

10 CFR 50.48. Therefore, the firewall is not within the scope of license renewal.

Based on the above discussion, the staff found the applicant's response to RAI 2.4-8

acceptable. The applicant clarified which items are within the scope of license renewal, which

are outside the scope of license renewal, and provided the basis for those that are

outside-scope. The staff's concern described in RAI 2.4-8 is resolved.

RAI 2.4-2. LRA Section 2.4 does not appear to contain information about tanks and their

foundations. In RAI 2.4-2, dated January 26, 2005, the staff requested the applicant to provide

a list of all tanks and their foundations for each unit. Additionally, the staff re6Ouosted thel

applicant to: (1) identify the tanks and their foundations that are within thie SCo! of icef,4

renewal and define their intended functions, (2) identify the tanks and their foap i are

outside the scope of license renewal and the basis for their exclusion, and (3) specify Where the

AMR for each in-scope tank and tank foundation is located in the LRA. Iil

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In its response, dated February 25, 2005, the applicant stated:

Tanks are associated with the system in which they -reside. They are addressed and

scoped in the mechanical section of the LRA, Section 2.3. The tables in LRA

Section 2.3 have a component group, "Tanks." The license renewal drawings for the

systems are listed and tanks that are in-scope are highlighted on the drawings. Tanks

are not individually identified by component number in the LRA but the LRA basis

documentation does contain individual component information which is available for

review on-site.

Tank foundations are scoped in LRA Section 2.4 and are typically constructed of

concrete or steel. Tanks foundations and intended functions are typically presented in

LRA Section 2.4.8, uYard Structures," Section 2.4.10, "Component Supports Commodity

Group," or individual section for the building. Tank and tank foundation AMR

information is contained in the corresponding Sections 3.1 through 3.5 of the LRA.

Based on the above discussion, the staff found the applicant's response to RAI 2.4-2

acceptable in that tanks are addressed and scoped in the mechanical section, LRA Section 2.3.

However, the staff found unacceptable the omission of tank foundations from LRA Section 2.4.

The applicant should identify the tank foundations that are or should be within the scope of

license renewal and define their intended functions. The applicant should also specify the

appropriate AMR for each in-scope tank foundation and identify the tank foundations that are

not or should not be within the scope of license renewal and the basis for their exclusion. This

was identified as confirmatory item (Cl) 2.4-2.

In its response to Cl 2.4-2, by letter dated June 10,.2005, the applicant identified individual

tanks and their foundations that are within the scope of license renewal. Subsequently, the

applicant submitted a letter, dated June 29, 2005, to clarify the intended functions and AMR

information of those tank foundations that are within the scope of license renewal. This letter

stated that the intended function for tank foundations is either a safety-related or a

nonsafety-related support and that the AMR information is contained within the corresponding

LRA Section 3.5. Since tank foundations are not stated under the column of component types

in buildings of LRA Section 3.5, the applicant used examples to illustrate that the tank

foundations within the scope of license renewal are included in either concrete or steel

component types, and further stated that every in-scope tank foundation within a building or in

yard structures would be captured by those component items.

With all in-scope tanks and their foundations identified, intended functions stated, and the AMR

information clarified, the staff concluded that the applicant has properly documented the

necessary information related to the tanks and their foundations and considers the applicant's

response to RAI 2.4-2 to be acceptable. The staff's concern is resolved and, therefore, Cl

2.4-2 is closed.

2.4.8.3 Conclusion

The staff reviewed the LRA, its related structural or component information, and RAI responses

described above to determine whether any SSCs that should be within the scope of license

renewal were not identified by the applicant. No omissions were identified. In addition, the staff

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performed a review to determine whether any components that should be subject to an AMR

were not identified by the applicant. No omissions were identified. On the basis of its review,

the staff concluded that there is reasonable assurance that the applicant adequately identified

the yard structures components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and that the applicant adequately identified the yard structures components

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

2.4.9 Cranes, Hoists, and Lifting Devices

2.4.9.1 Summary of Technical Information In the Application

In LRA Section 2.4.9, the applicant identified the structures and components of the cranes,

hoists, and lifting devices that are subject to an AMR for license renewal. The cranes, hoists,

and lifting devices system consists of the fuel handling cranes and the load handling systems

that comply with NUREG-0612. The fuel handling cranes include the reactor cavity manipulator

cranes and the spent fuel pool (SFP) bridge crane. The applicant stated that the fuel handling

cranes are not within the scope of license renewal because their intended functions do not

support safety-related structures and components or have heavy load capacities. The

NUREG-0612 load handling systems include the containment cranes, auxiliary building main

crane, and the turbine building overhead crane. This license renewal system also includes the

emergency diesel generator G03 and G04 cranes and monorails in the diesel generator

building, the reactor coolant pump lifting slings, the reactor vessel head, and the internals lifting

rigs. The specific components comprising this license renewal system are the bridge and

trolley structural members of the heavy load cranes and lifting devices, which include the crane

rails and hardware.

The portions of the cranes, hoists, and lifting devices system containing components subject to

an AMR Include the bridge and trolley structural beams, girders, and rails associated with the

NUREG-0612 heavy load cranes and lifting devices.

Intended function within the scope of license renewal is to provide structural support to

nonsafety-related components whose failure could prevent the satisfactory accomplishment of

any of the required safety-related functions or regulated event functions.

In LRA Table 2.4.9-1, the applicant identified the following cranes, hoists, and lifting devices

that are within the scope of license renewal and subject to an AMR:

* structural carbon steel fasteners/indoor (rail hardware)

* structural carbon steel/indoor (bridge and trolley framing; crane rails, monorails; and

lifting rigs)

* structural stainless steel/borated water (reactor vessels internals lifting rig)

2.4.9.2 Staff Evaluation

The staff reviewed LRA Section 2.4.9 and the FSAR. The staff's review, using the evaluation

methodology described in SER Section 2.4, was conducted in accordance with the guidance

described in NUREG-1800, Section 2.4.

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In conducting its review, the staff evaluated the structural or component functions described in

the LRA and FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant did not omit from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR in

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

The staff's review of LRA Section 2.4.9 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAls as discussed below.

RAI 2.4-7. LRA Table 2.4.4-1 lists crane rails supports as a component group within the scope

of license renewal. In RAI 2.4-7, dated January 26, 2005, the staff requested the applicant to

explain whether the crane, rails, hoists, and lifting devices are also within the scope of license

renewal. If they are not, the applicant was requested to provide justification for their exclusion.

In its response, dated February 25, 2005, the applicant stated:

The boundary between the building structures and their associated cranes is at the rail

support I rail interface, (ie., all components from the rail and above) are associated with

the crane [sic]. The rail support system is considered part of the building structure.

Table 2.4.4-1, "Diesel Generator Building Structure," contains the Component Group,

Structural Carbon Steel/lndoor-AII,m which includes the structural steel that supports the

crane rails.

Cranes are discussed in Section 2.4.9, Cranes, Hoists, and Lifting Devices System," of

the LRA. The specific components comprising this license renewal system are the

passive load-bearing structural members (bridge and trolley), and/or structural beams,

and girders of these cranes, hoists, and lifting devices, including the crane rails and

hardware. Therefore, these passive components are considered in-scope.

All other components of the crane or hoist are considered active or have no

component-level intended functions. This includes, but is not limited to, control panels,

lights, switches, terminal boxes, motors, cameras, brakes, gears, and cables. These

components and subcomponents are considered out-of-scope.

Based on the above discussion, the staff found the applicant's response to RAI 2.4-7

acceptable. The applicant clarified that all passive load-bearing structural members of the

cranes, hoists, and lifting devices are within the scope of license renewal. The staff's concern

described in RAI 2.4-7 is resolved.

RAI 2.4-9. LRA Section 2.4.9 states that the reactor cavity manipulator cranes and the spent

fuel pool bridge crane are not within the scope of license renewal. In RAI 2.4-9, dated

4January 26, 2005, the staff requested the applicant to provide evidence that the collapse of

these cranes would not damage any safe shutdown equipment.

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In its response, dated February 25, 2005, the applicant stated:

At the end of refueling operations, the reactor cavity manipulator crane is stowed and

shut down. By operating instruction, 01 23, "Containment Fuel Transfer Equipment," the

manipulator crane is parked in its storage location and all power is removed. When

properly stowed during normal operations the manipulator crane is not considered a

Seismic non-safety-related affecting safety-related hazard. This crane is parked in a

location such that no safety-related equipment would be affected by structural failure of

the crane.

The SFP bridge crane does not interface with or impact any safety-related component.

In addition the bridge assembly is designed with hold down bars fitted around the rail to

prevent any type of tipping. The SFP bridge hoist handles fuel. The potential

radiological consequences for the postulated fuel handling accident as described in

FSAR Chapter 14.2.1 are well within the dose guidelines of 10 CFR 100.

Based on the above discussion, the staff found the applicant's response to RAI 2.4-9

acceptable. The applicant clarified that the manipulator crane and the SFP bridge crane do not

impact any safety-related components. The staff's concern described in RAI 2.4-9 is resolved.

2.4.9.3 Conclusion

The staff reviewed the LRA, its related structural or component information, and RAI responses

described above to determine whether any SSCs that should be within the scope of license

renewal were not identified by the applicant. No -omissions were identified. In addition, the staff

performed a review to determine whether any components that should be subject to an AMR

were not identified by the applicant. No omissions were identified. On the basis of its review,

the staff concluded that there Is reasonable assurance that the applicant adequately identified

the cranes, hoists, and lifting devices components that are within the scope of license renewal,

as required by 10 CFR 54.4(a), and that the applicant adequately identified the cranes, hoists,

and lifting devices components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.4.10 Component Supports Commodity Group

2.4.10.1 Summary of Technical Information in the Application

In LRA Section 2.4.10, the applicant identified the structures and components of the component

supports commodity group (CSUP) that are subject to an AMR for license renewal. The CSUP

contains component and equipment supports, pipe restraints, electrical raceways, and electrical

enclosures associated with Units 1 and 2, and the common plant systems and equipment. This

commodity group includes the grout under the base-plate and fasteners used to support or

anchor equipment. The CSUP excludes jet impingement barriers (e.g., HELB barriers) and the

miscellaneous plant structures and their details (e.g., stairs, platforms, crane rails). All of these

items were evaluated as parts of the structures in which they are contained.

The portions of the component supports commodity group containing components subject to an

AMR include the component equipment supports, pipe restraints, electrical raceways, and

electrical enclosures.

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The CSUP commodity group provides structural support, including fasteners and anchorages,

for safety-related SSCs. The commodity group also contains electrical enclosures and

raceways that can house safety-related electrical components. In addition, the failure of

nonsafety-related SSCs in the structure could prevent the satisfactory accomplishment of a

safety-related function.

Intended functions within the scope of license renewal include the following:

* provides structural support to nonsafety-related components whose failure could prevent

satisfactory accomplishment of any of the required safety-related functions or regulated

event functions

* provides structural and/or functional support to safety-related equipment

* provides for pipe whip restraint

In LRA Table 2.4.10-1, the applicant identified the following CSUP component types that are

within the scope of license renewal and subject to an AMR:

* indoor elastomer (equipment mount vibration isolators)

* indoor grout (equipment and supports baseplates)

* outdoor grout (equipment and supports baseplates)

* indoor high strength structural carbon steel fasteners (high strength structural fasteners

- reactor coolant system component supports)

* indoor structural carbon steel fasteners (ASME equipment, ASME pipe supports and

restraints)

* indoor structural carbon steel fasteners (equipment supports - pipe restraints,

mechanical equipment, HVAC ducts, panels and cabinets; raceways; miscellaneous

steel structures)

* outdoor structural carbon steel fasteners (G01/02 exhaust stack, equipment supports -

yard)

* indoor structural carbon steel (ASME pipe supports and restraints; ASME equipment

supports; framing - structural shapes; non-ASME pipe supports and restraints;

non-ASME equipment supports; HVAC duct supports; raceways - cable trays, metallic

conduit, wireways; electrical enclosures - panels, boxes, cabinets, consoles)

* outdoor structural carbon steel (GO1/02 exhaust stack, equipment supports - yard)

* indoor structural stainless steel fasteners (equipment/component attachments (primarily

nuclear steam supply system))

* indoor structural stainless steel (structural shapes (primarily NSSS and tubing))

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2.4.10.2 Staff Evaluation

The staff reviewed LRA Section 2.4.10 and the FSAR. The staff's review, using the evaluation

methodology described in SER Section 2.4, was conducted in accordance with the guidance

described in NUREG-1800, Section 2.4.

In conducting its review, the staff evaluated the structural or component functions described in

the LRA and FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant did not omit from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR in

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

2.4.10.3 Conclusion

The staff reviewed the LRA and its related structural or component information to determine

whether any SSCs that should be within the scope of license renewal were not identified by the

applicant. No omissions were identified. In addition, the staff performed a review to determine

whether any components that should be subject to an AMR were not identified by the applicant.

No omissions were identified. On the basis of its review, the staff concluded that there is

reasonable assurance that the applicant adequately identified the component supports

commodity group components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and that the applicant adequately identified the component supports

commodity group components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2A.1 I Fire Barrier Commodity Group

2.4.11.1 Summary of Technical Information in the Application

In LRA Section 2.4.11, the applicant identified the structures and components of the fire barrier

commodity group that are subject to an AMR for license renewal. The fire barrier commodity

group includes all of the fire stops and fire wraps used throughout the site that are credited in

the FPER. Fire stops are the fire barrier penetration seals and cable tray fire stops. Fire wraps

comprise an envelope system that is installed around electrical components, conduits, and

cabling to maintain safe shutdown functions by suppressing any possible fire damage. In

addition, structural steel member fire proofing is considered as a fire wrap.

The portions of the fire barrier commodity group containing components subject to an AMR

include fire barrier penetration seals, cable tray fire stops, and fire wraps.

The fire barrier commodity group performs functions that support fire protection.

Intended -function within the scope of license renewal is to provide a rated fire barrier to confine

or retard a fire from spreading to or from adjacent areas of the plant.

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In LRA Table 2.4.11-1, the applicant identified the following fire barrier commodity group

component types that are within the scope of license renewal and subject to an AMR:

* indoor calcium silicate board (cable trays - fire stop, penetration seals)

* indoor ceramic fiber (cable trays - fire stop, penetration seals)

* indoor ceramic fiber-board (penetration seals)

* indoor ceramic fiber-mat (cable trays - fire stop)

* indoor silicone-based material (sprayed-on mastic, cable trays - fire stop, penetration

seals)

* indoor stainless steel appurtenances (tape, banding, banding seals, and wire for fire

wraps and penetration seals)

* indoor structural carbon steel (fire damper frames; cable tray covers)

* indoor gypsum board (walls)

2.4.11.2 Staff Evaluation

The staff reviewed LRA Section 2.4.11 and the FSAR. The staff's review, using the evaluation

methodology described in SER Section 2.4, was conducted in accordance with the guidance

described in NUREG-1 800, Section 2.4.

In conducting its review, the staff evaluated the structural or component functions described in

the LRA and FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant did not omit from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR in

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

The staff's review of LRA Section 2.4.11 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

RAI 2.4.11-1. The NRC's "Fire Protection Safety Evaluation Report" dated August 2, 1979,

Section 4.9.1, states that "Cable tray penetration in existing walls, floors, and ceilings are

sealed with various configurations utilizing Flamemastic 71 A coating, Kaowool ceramic fiber

blanket, and Marinite insulation board." No reference is made to Flamemastic 71A and Marinite

insulation board in LRA Section 2.4.11 "Fire Barrier Commodity Group" or in PBNP "Fire

Protection Evaluation Report," Revision 3, April 2004, Section 5.1.2. This appears to be a

PBNP license condition. In RAI 2.4.11-1, dated September 10, 2004, the staff requested the

applicant to identify where these coatings are addressed in the LRA scoping, screening, and

AMR sections.

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In its response, dated October 8, 2004, the applicant stated:

Cable tray penetration seals were upgraded to a qualified three-hour rating in 1980 and

1981. Standard penetration details were designed and qualified by Insulation

Consultants & Management Services, Inc. (ICMS). The open item on cable tray

penetration seal qualification was closed by a supplemental SER dated

January22, 1981.

The ablative Flamemastic coating is a water-based compound of thermoplastic resins

(flame-retardant) and inorganic, incombustible fibers. Material application is generally

by spraying. Marinite fireproof panels are comprised of rigid boards, initially

incorporating asbestos fibers and later with inert fibers and reinforcing agents. These

penetration materials were supplemented and/or superseded by the ICMS penetrations

designs.

The LRA, Section 2.4.11, represents these materials, Marinite and Flamemastic,

respectively, with a "calcium silicate board" or "silicone based material component

group" designation. The aging management reviews for these components and

materials are presented in Table 3.5.2-11. The LRA, Section B2.1.10, Fire Protection

Program, details the periodic visual inspections of the fire barriers and their

penetrations, including all of the material discussed above.

Based on the above discussion, the staff found the applicant's response to RAI 2.4.11-1

acceptable. The applicant adequately explained that the cable tray penetration seal materials,

(i.e., coatings, Flamemastic 71A and Marinite insulation board) are included in the calcium

silicate board or silicone-based material component group designations in LRA Table 3.5.2-11.

Further, theapplicant explained that the-applicable AMR is described in LRA Section B2.1.10.

The staff concluded that the fire protection coatings were correctly included within the scope of

license renewal and subject to an AMR. Therefore, the staff's concern described in

RAI 2.4.11-1 is resolved.

2.4.11.3 Conclusion

The staff reviewed the LRA, its related structural or component information, and RAI response described above to determine whether any SSCs that should be within the scope of license

renewal were not identified by the applicant. No omissions were identified. In addition, the staff

performed a review to determine whether any containments, structures, and component

supports that should be subject to an AMR were not identified by the applicant. No omissions

were identified. On the basis of its review, the staff concluded that there is reasonable

assurance that the applicant adequately identified the components of the fire barrier commodity

group 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 fire barrier commodity group that are

subject to an aging management review, as required by 10 CFR 54.21 (a)(1).

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2.4.12 13.8 kV Switchgear Building Structure

2.4.12.1 Summary of Technical Information in the Application

In LRA Section 2.4.12, the applicant identified the structures and components of the 13.8 kV

switchgear building structure that are subject to an AMR for license renewal. The 13.8 kV

switchgear building structure is a rectangular, nonsafety-related, seismic Class 3, concrete and

masonry block structure. The building is an independent structure with no other buildings

located in its immediate vicinity. The 13.8 kV switchgear building structure houses

nonsafety-related electrical equipment including: 13.8k volts-alternating current (VAC) buses

H01, H02, and H03, and 13.8K VAC circuit breakers H52-1 0, H52-20, H52-21, H52-30, and

H52-31. The gas turbine generator (GTG) electrical power is supplied to the 13.8 kV VAC

power system via circuit breaker H52-1 0 and tie bus H01. GTG (G05) is relied upon as the

alternate AC power source during an SBO event and is relied upon to supply power to safely

shutdown loads through the alternate shutdown equipment during a fire in 4160 VAC

switchgear.

The portions of the 13.8 kV switchgear building structure containing components subject to an

AMR include the foundation and equipment supports.

The 13.8 kV switchgear building structure performs functions that support fire protection and

station blackout.

Intended function within the scope of license renewal is to provide structural support to

nonsafety-related components whose failure could prevent the satisfactory accomplishment of

any of the required safety-related functions or regulated event functions.

In LRA Table 2.4.12-1, the applicant identified the following 13.8 kV switchgear building

structure component types that are within the scope of license renewal and subject to an AMR:

* buried concrete (foundation - spread footing and basemat)

* indoor concrete (floor (integral with basemat))

* outdoor concrete (foundation - spread footing and basemat)

2.4.12.2 Staff Evaluation

The staff reviewed LRA Section 2.4.12 and the FSAR. The staff's review, using the evaluation

methodology described in SER Section 2.4, was conducted in accordance with the guidance

described in NUREG-1 800, Section 2.4.

In conducting its review, the staff evaluated the structural or component functions described in

the LRA and FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant did not omit from the scope of license renewal any components with intended

functions delineated under 10 CFR 54A(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR in

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

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The staff's review of LRA Section 2.4.12 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

RAI 2.4-10. LRA Section 2.4.12 states that the reinforced concrete foundation slab and

switchgear anchors are within the scope of license renewal, but the remaining portions of the

13.8 KV switchgear building structure are not. In RAI 2.4-10, dated January 26, 2005, the staff

requested the applicant to clarify if the foundation slab is supported by foundation footings. If

so, the staff believes foundation footings should also be within the scope of license renewal.

Since the interior walls, exterior masonry block and concrete walls, and the roof are not within

the scope of license renewal, the staff also requested evidence that their collapse would not

damage any safe shutdown equipment.

In its response, dated February 25, 2005, the applicant stated:

The 13.8 KV switchgear building slab is supported by foundation footings that are

considered in-scope. Specific scoping basis is applied to buildings and structures

associated with equipment of the regulated events of 10 CFR 54.4(a)(3). For the civil

discipline, the regulated events of concern include station blackout (SBO) and FP.

Refer to the LRA Section 2.4.12, System Function Listings for additional information.

The foundation and footings for the 13.8 KV switchgear building are listed in LRA

Table 2.4.1.2-1, 013.8 KV Switchgear Building Structure CONCRETE/OUTDOOR

-ALL: FOUNDATION - SPREAD FOOTING AND BASEMAT' Component Group.

A detailed explanation of the regulated events scoping basis is presented in the NMC

response to RAI 2.4-12 in this letter.

Note that the superstructure of the 13.8 KV Switchgear Building is managed as part of

the routine preventative maintenance practices at PBNP.

In conclusion, the collapse of the superstructure of the 13.8KV building would not

damage any safe shutdown equipment.

Based on the above discussion, the staff found the applicant's response to RAI 2.4-10

acceptable. The collapse of the superstructure of the 13.8KV building would not damage any

safe shutdown equipment. The staff's concern described in RAI 2.4-10 is resolved.

2.4.12.3 Conclusion

The staff reviewed the LRA, its related structural or component Information, and RAI response

described above to determine whether any SSCs that should be within the scope of license

renewal were not identified by the applicant. No omissions were identified. In addition, the staff

performed a review to determine whether any components that should be subject to an AMR -

were not identified by the applicant. No omissions were identified. On the basis of its review,

the staff concluded that there is reasonable assurance that the applicant adequately identified

the 13.8KV building structure components that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and that the applicant adequately identified the 13.8KV building

structure components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.4.13 Fuel Oil Pumphouse Structure

2.4.13.1 Summary of Technical Information In the Application

In LRA Section 2.4.13, the applicant identified the structures and components of the fuel oil

pumphouse structure that are subject to an AMR for license renewal. The fuel oil pumphouse

structure is a rectangular, safety-related, seismic Class 1, structure that is constructed from

reinforced concrete and concrete masonry block. This building is an independent structure with

no other structures in its immediate vicinity. The fuel oil pumphouse building houses

nonsafety-related mechanical and electrical equipment, including the gas turbine (GT) fuel oil

supply pump, which is required for GTG (GO5) operation. The G05 generator is relied upon as

the alternate AC (MC) power source during an SBO event and is also relied upon to supply

power to safely shutdown loads through the alternate shutdown equipment during a fire in 4160

VAC switchgear.

The portions of the fuel oil pumphouse structure containing components subject to an AMR

include the foundations and equipment supports.

The fuel oil pumphouse structure performs functions that support fire protection and station

blackout.

Intended function within the scope of license renewal is to provide structural support to

nonsafety-related components whose failure could prevent the satisfactory accomplishment of

any of the required safety-related functions or regulated event functions.

In LRA Table 2.4.13-1, the applicant identified the following fuel oil pumphouse structure

component types that are within -the scope of license renewal and subject-to an AMR:

* buried concrete (foundation - basemat, walls)

* indoor concrete (ceiling (25-ft, 6-in elevation)

* outdoor concrete (foundation - basemat)

2.4.13.2 Staff Evaluation

The staff reviewed LRA Section 2.4.13 and the FSAR. The staff's review, using the evaluation

methodology described in SER Section 2.4, was conducted in accordance with the guidance

described in NUREG-1800, Section 2.4.

In conducting its review, the staff evaluated the structural or component functions described in

the LRA and FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant did not omit from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR in

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

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The staff's review of LRA Section 2.4.;13 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

RAI 2.4-11. LRA Section 2.4.13 states that the above-grade block wall portions of the

superstructure, including roof, of the fuel oil pumphouse structure are not within the scope of

license renewal. In RAI 2.4-11, dated January 26, 2005, the staff requested the applicant to

provide evidence that their collapse would not damage any safe shutdown equipment.

In its response, dated February 25, 2005, the applicant stated:

The SSCs In the fuel oil pump house are not safety-related and do not support safe

shutdown equipment.

Specific scoping basis is applied to buildings and structures associated with equipment

of the regulated events of 10 CFR 54.4(a)(3). For the civil discipline, the regulated

events of concern include SBO and FP. Refer to the LRA Section 2.4.13, System

Function Listing for additional information. A detailed explanation of the regulated

events scoping basis Is presented in the NMC response to RAI 2.4-12 in this letter.

It should be noted that the superstructure of the Fuel Oil Pumphouse structure is

managed as part of the routine preventative maintenance practices at PBNP.

In conclusion, the collapse of the Fuel Oil Pump House superstructure will not damage

any safe shutdown equipment.

Based on the above discussion, the staff found the applicant's response to RAI 2.4-11;

acceptable. -The collapse of the fuet oil pump -house superstructure will not damage any safe

shutdown equipment. The staff's concern described in RAI 2.4-11 Is resolved.

2.4.13.3 Conclusion

The staff reviewed the LRA, its related 'structural or component Information, and RAI response

described above to determine whether any SSCs that should be within the scope of license

renewal were not identified by the applicant. No omissions were identified. In addition, the staff

performed a review to determine whether any components that should be subject to an AMR

were not identified by the applicant. No omissions were identified. On the basis of its review,

the staff concluded that there is reasonable assurance that the applicant adequately identified

the fuel oil pumphouse structure components that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and that the applicant adequately identified the fuel oil pumphouse

structure components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.4.14 Gas Turbine Building Structure

2.4.14.1 Summary of Technical Information In the Application

In LRA Section 2.4.14, the applicant identified the structures and components of the GT

building structure that are subject to an AMR for license renewal. The GT building structure is a

rectangular, nonsafety-related, seismic Class 3 structure that is constructed from pre-fabricated

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metal walls and roof panels, which are attached to a structural steel frame. The building's

structural steel frame is supported by a reinforced concrete basemat and foundation. The

building is an independent structure with no other buildings located in its immediate vicinity.

The GT building houses the nonsafety-related GTG (G05) and its associated mechanical and

electrical equipment. The G05 generator is relied upon as the MC power source during an

SBO event and is also relied upon to supply power to safely shut down loads through the

alternate shutdown equipment during a fire in the 4160 VAC switchgear.

The portions of the GT building structure containing components subject to an AMR include the

foundations and equipment pedestals.

The gas turbine building structure performs functions that support fire protection and station

blackout.

Intended function within the scope of license renewal is to provide structural support to

nonsafety-related components whose failure could prevent the satisfactory accomplishment of

any of the required safety-related functions or regulated event functions.

In LRA Table 2.4.14-1, the applicant identified the following GT building structure component

types that are within the scope of license renewal and subject to an AMR:

* buried concrete (foundation - basemat)

* indoor concrete (floor; equipment pedestals)

* outdoor concrete (foundation - basemat)

2.4.142 Staff Evaluation

The staff reviewed LRA Section 2.4.14 and the FSAR. The staff's review, using the evaluation

methodology described in SER Section 2.4, was conducted in accordance with the guidance

described in NUREG-1 800, Section 2.4.

In conducting its review, the staff evaluated the structural or component functions described in

the LRA and FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant did not omit from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR in

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

The staff's review of LRA Section 2.4.14 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

RAI 2.4-12. -LRA Section 2.4.14 states that generator G05 and its associated mechanical and

electrical equipment is housed in the GT building structure, and is relied upon as the MC

power source during an SBO. It is also relied upon to supply power to safe shutdown loads

through the alternate shutdown equipment during a fire in the 4160 VAC switchgear. LRA

Section 2.4.14 further states that only the concrete foundation slab and the turbine-generator

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concrete equipment pedestals are within the scope of license renewal, and the remaining

portions of the structure, which include the steel superstructure, are not within the scope of

license renewal. In RAI 2.4-12, dated January 26, 2005, the staff requested the applicant to

provide evidence that the functions of generator G05 and its associated mechanical and

electrical equipment will not be impaired due to the collapse of the remaining portions of the GT

building structure.

In its response, dated February 25, 2005, the applicant stated:

Presented below is the basis for scoping buildings and structures associated with

equipment of the regulated events of 10 CFR 54.4(a)(3). In particular, for the civil

discipline, this pertains to SBO and FP.

The following are selected excerpts from the license renewal standard review plan

NUREG-1800, Section 2.1.3.1.3, dealing with regulated events scoping methodology.

... Systems, structures, and components (SSCs) relied on in safety analyses or

plant evaluations to perform functions that demonstrate compliance with the

requirements of the fire protection, environmental qualification, pressurized

thermal shock (PTS), anticipated transients without scram (ATWS), and station

blackout (SBO) regulations are identified.

The scoping criteria in 10 CFR 54.4(a)(3) require an applicant to consider U[all

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

demonstrates compliance with the [specified] Commission regulations[.]" In

addition, Section IlI.c(iii) (60 FR 22467) of the SOC states that the NRC intended

to limit the potential for unnecessary expansion of the review for SSCs that meet

the scoping criteria under 10 CFR 54.4(a)(3) and provides additional guidance

that qualifies what is meant by those SSCs relied on in safety analyses or plant

evaluations to perform a function that demonstrates compliance with the

Commission regulations" in the following statement:

... the Commission intends that this [referring to 10 CFR 54.4(a)(3)]

scoping category include all systems, structures, and components whose

function is relied upon to demonstrate compliance with these

Commission's regulations.

Therefore, all SSCs that are relied upon in the plant's CLB (as defined in 10 CFR 54.3),

plant-specific experience, industry-wide experience (as appropriate), and safety

analyses or plant evaluations to perform a function that demonstrates compliance with

the NRC's regulations identified under 10 CFR 54.4(a)(3) are required to be included

within the scope of the rule. For example, if a non-safety-related diesel generator is

required for safe shutdown under the FP plan, the diesel generator and all SSCs

specifically required for that diesel to comply with and operate within the NRC's

regulations based on the applicant's design specifications for that diesel shall be

included within the scope of license renewal under 10 CFR 54.4(a)(3). This may

include, but should not be limited to, the cooling water system or systems required for

operability, the diesel support pedestal, and any applicable power supply cable

specifically required for safe shutdown in the event of a fire.

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In addition, the last sentence of the second paragraph in the SOC, Section IlI.c.(iii)

provides the following guidance for limiting the scoping criteria under 10 CFR 54.4(a)(3)

as it applies to the use of hypothetical failures:

Consideration of hypothetical failures that could result from system

interdependencies, that are not part of the current licensing bases and that have

not been previously experienced is not required.

The SOC does not provide any additional guidance relating to the use of hypothetical

failures or the need to consider second-, third-, or fourth-level support systems for

scoping under 10 CFR 54.4(a)(3). Therefore, in the absence of this guidance,

hypothetical failures or second-, third-, or fourth-level support systems need not be

considered in determining the SSCs within the scope of the rule under

10 CFR 54.4(a)(3). For example, if a nonsafety-related diesel generator is relied upon

only to remain functional to demonstrate compliance with the NRC SBO regulations, the

applicant need not consider the following SSCs: (1) an altemate/backup cooling water

system, (2) non-seismically-qualified building walls, or (3) an overhead segment of

non-seismically qualified piping (in a Seismic Il/I configuration). This guidance is not

intended to exclude any support system (identified by an applicant's CLB, actual

plant-specific experience, industry-wide experience, as applicable, safety analyses or

plant evaluations) that is specifically required for compliance with or operation within the

applicable NRC regulation.

The applicant is required to identify the systems, structures, and components whose

functions are relied on to demonstrate compliance with these regulated events (that is,

whose functions were credited in the analysis or evaluation). Mere mention of a system,

structure, or component in the analysis or evaluation does not constitute support of an

intended function as required by the regulation.

PBNP uses the nonsafety-related gas turbine generator G-05 as the Altemate AC

(MC) source in response to the SBO event. G-05 support systems and structures, all

non-safety-related include but are not limited to:

* G-05 foundation and building

* G-05 fuel oil, tank and tank foundation, fuel oil piping

* G-05 cooling water, pipe, tank and foundation (a closed system)

* G-05 electrical cable, conduit, tray and duct banks

* G-05 associated electrical distribution equipment and their foundations

G-05 and its direct support systems are within the scope of license renewal. Direct

support system/structures are those that are essential to the operability of the specific

SSCs that are relied upon to perform the required functions for the regulated event.

Those systems and structures that are not essential, nor provide direct support, are

considered the second, or third-level support systems/structures.

The CLB contains no safety analyses or plant evaluations that credits the building or

requires second or third level failure analysis for G-05 or its building. Based on this and

the scoping methodology described above, the building superstructure is not within the

scope of license renewal. The concrete pedestal/foundation that supports G-05 is within

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the scope of license renewal, for it provides direct support and is essential to the

operation of G-05. This same logic is applied to the fuel oil tank foundation, fuel oil

transfer pump foundation, electrical distribution equipment foundations, and the duct

banks. The Fuel Oil Pumphouse and 13.8 KV Switchgear buildings (but not their

superstructures) are, therefore, in-scope.

In conclusion, the building foundations that support G-05 and its support equipment are

in-scope. The building superstructure is out-of-scope of license renewal. Refer to LRA

Section 2.4.14, "System Function Listing" for additional information.

Note that the superstructure of the Gas Turbine Building Structure is managed as part of

the routine preventative maintenance practices at PBNP (i.e., good building

maintenance or life-cycle management).

Based on the above discussion, the staff found the applicant's response to RAI 2.4-12

acceptable. The applicant provided the basis for excluding from the scope of license renewal

the superstructure of the gas turbine building structure. The staff's concern described in

RAI 2.4-12 is resolved.

2.4.14.3 Conclusion

The staff reviewed the LRA, its related structural or component information, and the RAI

response described above to determine whether any SSCs that should be within the scope of

license renewal were not identified by the applicant. No omissions were identified. In addition,

the staff performed a review to determine whether any components that should be subject to an

AMR were not identified by the applicant. No omissions were identified. On the basis of its

review, the staff concluded that there is reasonable assurance that the applicant adequately

identified the gas turbine building structure components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and that the applicant adequately identified the gas

turbine building structure components 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

This section documents the staff's review of the applicant's scoping and screening results for

electrical systems and instrumentation and controls (I&C) systems. Specifically, LRA

Section 2.5 discusses the following passive, long-lived electrical components potentially subject

to an AMR:

* commodity group descriptions

* 120 VAC vital instrument power system

* 125 VDC power system

* 4160 VAC power system

* 480 VAC power system

* control rod drive and indication system and nuclear process instrumentation

* miscellaneous AC power and lighting system

* offsite power system

* reactor protection system including anticipated transient without scram

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* engineered safety features actuation system

* plant communications system

* 13.8k VAC power system

* radiation monitoring system

In accordance with the requirements of 10 CFR 54.21 (a)(1), the applicant must identify and list

passive, long-lived electrical and l&C systems and 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 there were no omissions of electrical and l&C systems components that

meet the scoping criteria and are subject to an AMR.

Staff Evaluation Methodoloav. The staff's evaluation of the information provided in the LRA

was performed in the same manner for all electrical and I&C systems. The objective of the

review was to determine if the components and supporting structures for a specific electrical

and I&C system that appeared to meet the scoping criteria specified in the Rule were identified

by the applicant as within the scope of license renewal in accordance with 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).

Scoaina. To perform its evaluation, the staff reviewed the applicable LRA section and

associated component drawings, focusing its review on components that had not been

identified as within the scope of renewal. The staff reviewed relevant licensing basis

documents, including the FSAR, for each electrical and l&C system component to determine if

the applicant had omitted components with intended functions delineated under 10 CFR 54.4(a)

from the scope of license renewal. The staff also reviewed the licensing basis documents to

determine if all intended functions delineated under 10 CFR 54.4(a) were specified in the LRA.

If omissions were identified, the staff requested additional information to resolve the

discrepancies.

As documented under RAI 2.1-1 in SER Section 2.1, by letter dated April 29, 2005, the

applicant changed the methodology used to determine the nonsafety-related SSCs that are

within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(2).

As a result of the implementation of the scoping methodology changes, the applicant identified

no new electrical and instrumentation control component groups within the scope of license

renewal.

Screening. After completing its scoping evaluation, the staff reviewed the applicant's screening

results. For those SCs with intended functions, the staff sought to determine: (1) if the

function(s) are performed with moving parts or involve a change in configuration or properties,

or (2) if they are subject to replacement based on a qualified life or specific 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 systems 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.

After applying the scoping and screening methodology, the applicant categorized the

components requiring AMR into passive commodity groups. In LRA Section 2.5.1, the applicant

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identified the SCs of the electrical and l&C systems that are subject to an AMR for license

renewal.

The corresponding subsections of this SER (2.5.1 - 2.5.1.8, respectively) present the staff's

review findings with respect to the electrical and l&C systems for both Units 1 and 2.

2.5.1 Commodity Group Descriptions

In LRA Section 2.5.1, the applicant described the components and systems included in the

commodity group:

* insulated cables and connections

* electrical penetration assemblies

* electrical phase bus

* switchyard bus

* transmission conductors

* high-voltage insulators

* uninsulated ground conductors

* panels and junction boxes

The commodity group is within the scope of license renewal because it meets

10 CFR 54.4(a)(1) by providing electrical power to safety Class 1, 2, and 3 components; some

SSCs in the system are considered to be within the scope of license renewal because their

failure could affect the capability of safety-related SSCs in accordance with 10 CFR 54.4(a)(2);

others are within the scope of license renewal because they support fire protection, anticipated

transient without scram, and station blackout in accordance with 10 CFR 54.4(a)(3).

Intended function within the scope of license renewal is to electrically connect specified sections

of an electrical circuit to deliver voltage, current, or signal. Additional intended functions are to

electrically isolate and provide structural support to transmission conductors, phase bus, and

switchyard buses.

In LRA Table 2.5-1, the applicant identified the following commodity group component types

that are within the scope of license renewal and subject to an AMR:

* electrical cables and connections not subject to 10 CFR 50.49 EQ requirements

* electrical cables and connections used in instrumentation circuits not subject to

10 CFR 50.49 EQ requirements that are sensitive to reduction in conductor insulation

* electrical connections not subject to 10 CFR 50.49 EQ requirements that are exposed to

borated water leakage

* electrical penetration assemblies

* high-voltage insulators

* inaccessible medium-voltage cables and connections not subject to 10 CFR 50.49 EQ

requirements

* phase bus

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* switchyard buses and connections

* transmission conductors

2.5.1.1 Insulated Cables and Connections

2.5.1.1.1 Summary of Technical Information in the Application

LRA Section 2.5.1 states that cables and their associated connectors provide electrical

connections to deliver electrical energy either continuously or intermittently to various

equipment and components throughout the plant to enable them to perform their intended

functions. It states that the cables and connectors associated with the 10 CFR 50.49 EQ

program are addressed either as short-lived and periodically replaced, or as long-lived TLAA

candidates; therefore, these are not included in the set of cables and connectors that require

additional aging management review.

The applicant evaluated PBNP cables and connectors as commodities across system

boundaries. This is termed the spaces approach in NUREG-1800, Section 2.5.3.1. LRA

Table 2.5-1 defines component types that are subject to aging management and lists their

intended functions. The LRA states that these cables and connectors are within the scope of

license renewal and are subject to aging management review.

2.5.1.1.2 Staff Evaluation

The staff reviewed LRA Section 2.5.1 using the evaluation methodology described in SER

Section 2.5. The staff conducted its review in accordance with the guidance described in

NUREG-1800, Section 2.5, "Scoping and Screening Results: Electrical and Instrumentation

and Controls Systems."

In conducting its review, the staff evaluated the structural or component functions described in

the LRA and FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant did not omit from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR in

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

The applicant evaluated the cables and connectors as commodities across system boundaries

on a plant-wide basis. LRA Section 2.5.1 states that "plant-wide" generally includes all cables

and connectors throughout PBNP to provide complete coverage of cables and connectors in

the scope of license renewal. In the LRA, the applicant indicated that the passive function of

the cables and connectors is to conduct electricity, and the cables and connectors are subject

to an AMR. The staff agrees that the applicant correctly identified the cables and connectors as

components that perform their function without moving parts or a change in configuration or

properties (passive and long-lived) and are, therefore, subject to an AMR.

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2.5.1.1.3 Conclusion

During its review of the information provided in the LRA and the FSAR, the staff did not identify

any omissions or discrepancies in the applicant's scoping and screening results for insulated

cables and connections. In addition, the staff performed a review to determine whether any

components that should be subject to an AMR were not identified by the applicant. No

omissions were identified. On the basis of its review, the staff concluded that the applicant

adequately identified the insulated cables and connections components that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant adequately

identified the insulated cables and connections components that are subject to an AMR, as

required by 10 CFR 54.21(a)(1).

2.5.1.2 Electrical Penetration Assemblies

2.5.1.2.1 Summary of Technical Information in the Application

LRA Section 2.5.1 describes containment electrical penetrations as passive, long-lived

component assemblies that perform a containment boundary function and provide an electrical

connection between two sections of the electricaVl&C circuits for conducting electrical power

(voltage and current), either continuously or intermittently throughout the plant to enable them

to perform their intended functions. The pigtail at each end of the penetration is connected to

the field cable in various ways. Therefore, the boundary of the electrical penetrations include

these pigtails. Containment electrical penetrations that are associated with 10 CFR 50.49 EQ

program are addressed as short-lived and periodically replaced, or as long-lived TLAA

components. The containment electrical penetrations that are classified as short-lived and

periodically replaced, or TLAA components, are not included in the set of penetrations requiring

aging management review.

2.5.1.2.2 Staff Evaluation

The staff reviewed LRA Section 2.5.1 using the evaluation methodology described in SER

Section 2.5. The staff conducted its review in accordance with the guidance described in

NUREG-1 800, Section 2.5.

In conducting its review, the staff evaluated the structural or component functions described in

the LRA and FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant did not omit from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR in

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

The electrical penetrations identified by the applicant requiring an AMR are nonsafety-related,

non-EQ, and used plant-wide to conduct electrical power (voltage and current), either

continuously or intermittently between two sections of the electricaVl&C circuits supplying power

to various equipment in the containment. The staff reviewed these component categories

against the requirements in 10 CFR 54.4(a)(1) and 10 CFR 54.4(b) and found that those

categories are encompassed by the requirements. The staff reviewed the information in the

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FSAR and found that the applicant identified the containment electrical penetrations that are

within the scope of license renewal.

2.5.1.2.3 Conclusion

During its review of the information provided in the LRA and the FSAR, the staff did not identify

any omissions or discrepancies in the applicant's scoping and screening results for electrical

penetration assemblies. In addition, the staff performed a review to determine whether any

components that should be subject to an AMR were not identified by the applicant. No

omissions were identified. On the basis of its review, the staff concluded that the applicant

adequately identified the electrical penetration assemblies components that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant adequately

identified the electrical penetration assemblies components that are subject to an AMR, as

required by 10 CFR 54.21 (a)(1).

2.5.1.3 Electrical Phase Bus

2.5.1.3.1 Summary of Technical Information in the Application

LRA Section 2.5.1 describes phase buses (isolated, non-segregated, segregated) and their

standoffs as a component assembly conducting electrical power (voltage and current), either

continuously or intermittently between various equipment and components throughout the plant,

to enable them to perform their intended functions. The phase bus bars are a pre-assembled

raceway design, with bus bars mounted on insulated supports (standoffs). The intended

function of the standoffs is to support the electrical phase buses. In the LRA, the applicant

identified non-segregated phase buses within the scope of license renewal for the 13.8k VAC,

4.16k VAC, and 480 VAC power systems.

2.5.1.3.2 Staff Evaluation

The staff reviewed LRA Section 2.5.1 using the evaluation methodology described in SER

Section 2.5. The staff conducted its review in accordance with the guidance described in

NUREG-1 800, Section 2.5.

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had

identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR in

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

The phase buses identified by the applicant consist of non-segregated phase buses that are

used in the 13.8k VAC, 4.16k VAC, and 480 VAC plant-wide to conduct electrical power

(voltage and current), either continuously or intermittently between various equipment and

components. The staff reviewed these component categories against the requirements in

1 0 CFR 54.4(a)(1) and 10 CFR 54.4(b) and found that those categories are encompassed by

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the requirements. The staff reviewed the information in the FSAR and found that the applicant

identified the phase bus within the scope of license renewal.

2.5.1.3.3 Conclusion

During its review of the information provided in the LRA and the FSAR, the staff did not identify

any omissions or discrepancies in the applicant's scoping and screening results for electrical

phase bus. In addition, the staff performed a review to determine whether any components that

should be subject to an AMR were not identified by the applicant. No omissions were identified.

On the basis of its review, the staff concluded that the applicant adequately identified the

electrical phase bus components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and that the applicant adequately identified the electrical phase bus

components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.5.1.4 Switchyard Bus

2.5.1.4.1 Summary of Technical Information in the Application

LRA Section 2.5.1 describes switchyard bus as a passive, unenclosed, long-lived component

that is used to connect two or more elements of an electrical power circuit such as switches and

transmission conductors. In the LRA, the applicant stated that the switchyard bus within the

scope of license renewal is the portion of the offsite power system interconnection between the

Unit 1 circuit switcher and the high-voltage station auxiliary transformer, and between the Unit 2

circuit switcher and the high-voltage station auxiliary transformer.

2.5.1.4.2 Staff Evaluation

The staff reviewed LRA Section 2.5.1 using the evaluation methodology described in SER

Section 2.5. The staff conducted its review in accordance with the guidance described in

NUREG-1 800, Section 2.5.

In conducting its review, the staff evaluated the system functions described in the LRA and

FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did not

omit from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had

identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR in

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

As identified by the applicant, the switchyard bus associated within the scope of license renewal

is the portion of the offsite power system interconnections between the Unit 1 circuit switcher

and the high-voltage station auxiliary transformer, and between the Unit 2 circuit switcher and

the high-voltage station auxiliary transformer. The staff reviewed these component categories

against the requirements in 10 CFR 54.4(a)(1 ) and 10 CFR 54.4(b) and found that those

categories are encompassed by the requirements. The staff reviewed the information in the

FSAR and found that the applicant identified the switchyard bus within the scope of license

renewal.

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2.5.1.4.3 Conclusion

During its review of the information provided in the LRA and the FSAR, the staff did not identify

any omissions or discrepancies in the applicant's scoping and screening results for switchyard

bus. In addition, the staff performed a review to determine whether any components that

should be subject to an AMR were not identified by the applicant. No omissions were identified.

On the basis of its review, the staff concluded that the applicant adequately identified the

switchyard bus components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and that the applicant adequately identified the switchyard bus components

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

2.5.1.5 Transmission Conductors

2.5.1.5.1 Summary of Technical Information in the Application

LRA Section 2.5.1 describes transmission conductors as uninsulated, stranded electrical cables

used in switchyards, switching stations, and transmission lines to connect two or more

elements of electrical power breakers, transformers, and passive switchyard bus. In the LRA,

the applicant stated that the transmission conductors that are within the scope of license

renewal are the short connections from each unit's high-voltage station auxiliary transformer

surge arresters to sections of aluminum switchyard bus. These conductors are aluminum

jumper cables with a steel core (ACSR) in short sections between rigidly supported connecting

equipment.

2.5.1.5.2 Staff Evaluation

The staff reviewed LRA Section 2.5.1 using the evaluation methodology described in SER

Section 2.5. The staff conducted its review in accordance with the guidance described in

NUREG-1800, Section 2.5.

In conducting its review, the staff evaluated the structural or component functions described in

the LRA and FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant did not omit from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR in

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

The transmission conductors identified by the applicant that are within the scope of license

renewal are the short connections from each unit's high-voltage station auxiliary transformer

surge arresters to sections of aluminum switchyard bus. These conductors are short sections

of ACSR between rigidly supported connecting equipment. The staff reviewed these

component categories against the requirements in 10 CFR 54.4(a)(1) and 10 CFR 54.4(b) and

found that those categories are encompassed by the requirements. The staff reviewed the

information in the FSAR and found that the applicant identified the transmission conductors

within the scope of license renewal.

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2.5.1.5.3 Conclusion

During its review of the informationrprovided in the LRA and the PSAR, the staff did not identify

any omissions or discrepancies in the applicant's scoping and screening results for

transmission conductors. In addition, the staff performed a review to determine whether any

components that should be subject to an AMR were not identified by the applicant. No

omissions were identified. On the basis of its review, the staff concluded that the applicant

adequately identified the transmission conductors components that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and that the applicant adequately identified the

transmission conductors components that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.5.1.6 High-Voltage Insulators

2.5.1.6.1 Summary of Technical Information in the Application

LRA Section 2.5.1 describes high-voltage insulators as a component used to support and

insulate high-voltage electrical components in the switchyard, transmission lines such as

transmission conductors, and switchyard bus. The high-voltage insulators serve as an

intermediate support between a supporting structure, such as a support pedestal or

transmission tower, and the switchyard bus or transmission conductor. In the LRA, the

applicant stated that the high-voltage insulators that are within the scope of license renewal are

associated with the in-scope portion of the offsite power system as station post insulators

providing support for the switchyard bus connecting the unit high-voltage station auxiliary

transformers and the circuit switchers, and they support the circuit switchers themselves.

2.5.1.6.2 Staff Evaluation

The staff reviewed LRA Section 2.5.1 using the evaluation methodology described in SER

Section 2.5. The staff conducted its review in accordance with the guidance described in

NUREG-1800, Section 2.5.

In conducting its review, the staff evaluated the structural or component functions described in

the LRA and FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant did not omit from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR in

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

As identified by the applicant, the high-voltage insulators are associated with the in-scope

portion of the offsite power system as station post insulators providing support for the

switchyard bus connecting the high-voltage station auxiliary transformers and the circuit

switchers, and they support the circuit switchers themselves. The staff reviewed these

component categories against the requirements in 10 CFR 54.4(a)(1) and 10 CFR 54.4(b) and

found that those categories are encompassed by the requirements. The staff reviewed the

information in the FSAR and found that there the applicant identified the high-voltage insulators

within the scope of license renewal.

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2.5.1.6.3 Conclusion

During its review of the information provided in the LRA and the FSAR, the staff did not identify

any omissions or discrepancies in the applicant's scoping and screening results for high-voltage

insulators. In addition, the staff performed a review to determine whether any components that

should be subject to an AMR were not identified by the applicant. No omissions were identified.

On the basis of its review, the staff concluded that the applicant adequately identified the

high-voltage insulators components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and that the applicant adequately identified the high-voltage insulators

components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.5.1.7 Uninsulated Ground Conductors

2.5.1.7.1 Summary of Technical Information in the Application

LRA Section 2.5.1 describes the uninsulated ground conductors as electrical conductors (e.g.,

copper cable, copper bar) that are uninsulated (bare) and are used to make ground

connections for electrical equipment. Uninsulated ground conductors are connected to

electrical equipment housings and electrical enclosures as well as metal structural features

such as cable tray equipment and building structural steel.

In the LRA, the applicant stated that uninsulated ground conductors are always isolated or

insulated from the electrical operating circuits and are not required for those circuits or

equipment to perform their intended functions. Therefore, uninsulated ground conductors are

not within the scope of license renewal.

2.5.1.7.2 Staff Evaluation

The staff reviewed LRA Section 2.5.1 using the evaluation methodology described in SER

Section 2.5. The staff conducted its review in accordance with the guidance described in

NUREG-1 800, Section 2.5.

In conducting its review, the staff evaluated the structural or component functions described in

the LRA and FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant did not omit from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR in

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

The uninsulated ground conductors identified by the applicant are electrical conductors that are

uninsulated and used to make ground connections for electrical equipment. These conductors

are connected by impression or fusion using various types of metals and inorganic materials

that have no aging effects. Therefore, the staff concluded that uninsulated ground conductors

are not within the scope of license renewal.

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2.5.1.7.3 Conclusion

During its review of the information provided in the LRA and the FSAR, the staff did not identify

any omissions or discrepancies in the applicant's scoping and screening results for uninsulated

ground conductors. In addition, the staff performed a review to determine whether any

components that should be subject to an AMR were not identified by the applicant. No

omissions were identified. On the basis of its review, the staff concluded that the applicant

adequately identified the uninsulated ground conductors components as not within the scope of

license renewal.

2.5.1.8 Panels and Junction Boxes

2.5.1.8.1 Summary of Technical Information in the Application

LRA Section 2.5.1 describes panels and junction boxes as commodities that include control

boards, electrical panels, switchgear, cabinets, junction boxes, and other electrical enclosures.

This commodity is considered a part of the component supports commodity group and provides

the aging management review of all structural support components and other equipment within

the scope of license renewal.

2.5.1.8.2 Staff Evaluation

The staff reviewed LRA Section 2.5.1 using the evaluation methodology described in SER

Section 2.5. The staff conducted its review in accordance with the guidance described in

NUREG-1800, Section 2.5.

In conducting its review, the staff evaluated the structural or component functions described in

the LRA and FSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant did not omit from the scope of license renewal any components with intended ;

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR in

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

The staff's review of LRA Section 2.5.1 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

RAI 2.5.1. LRA Section 2.5 lists panels and junction boxes as a system within the scope of

license renewal. In addition, panels and junction boxes are described under "commodity group"

as commodities that include control boards, electrical panels, switchgear, cabinets, junction

boxes, and other electrical enclosures. However, in LRA Table 2.5-1, panels and junction

boxes are not listed as components subject to an AMR. In RAI 2.5.1, dated

November 18, 2004, the staff requested the applicant to clarify if there are any electrical

passive components such as connections, wiring, and hardware that could degrade because of

aging mechanisms due to moisture and corrosion within the cabinets, junction boxes, and other

electrical enclosures.

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In its response, dated January 25, 2005, the applicant stated that panels and junction boxes

were evaluated regarding whether they contain any active components or have only passive

components within them. The applicant further stated that if they contain any active

components, then the contents are exempt from an AMR, but if they contain only passive

components, such as cable connections (e.g., connectors or splices) or terminal strips, these

components are subject to an AMR within the scope of those specific commodities. The

applicant stated that penetrations into panels and junction boxes are sealed, and if appropriate,

a weep hole is provided to drain moisture or boric acid.

Based on the above discussion, the staff found the applicant's response to RAI 2.5.1

acceptable. The applicant confirmed that all the panels and junction boxes were evaluated and

are being managed. The staff's concern described in RAI 2.5.1 is resolved.

2.5.1.8.3 Conclusion

During its review of the information provided in the LRA, FSAR, and RAI response described

above, the staff did not identify any omissions or discrepancies in the applicant's scoping and

screening results for panels and junction boxes. In addition, the staff performed a review to

determine whether any components that should be subject to an AMR were not identified by the

applicant. No omissions were identified. On the basis of its review, the staff concluded that the

applicant adequately identified the panels and junction box components that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant adequately

identified the panels and junction boxes components that are subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.6 Conclusion for Scopina and Screenina

The staff has reviewed the information in LRA Section 2, "Scoping and Screening Methodology

for Identifying Structures and Components Subject to Aging Management Review, and

Implementation Results." The staff determined the applicant's scoping and screening'

methodology 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 SSC's 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).

On the basis of its review, the staff concluded that the applicant 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 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 staff has concluded that there is reasonable assurance that

the activities authorized by the renewed license will continue to be conducted in accordance

with the CLB, and that any changes made to the CLB in order to comply with 10 CFR 54.29(a)

are in accordance with the Act and the Commission's regulations.

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SECTION 3

AGING MANAGEMENT REVIEW RESULTS

This section of the SER contains the staff's evaluation of the applicant's aging management

programs (AMPs) and aging management reviews (AMRs). In LRA Appendix B, the applicant

described the 27 AMPs that it relies on to manage or monitor the aging of long-lived, passive

components and structures.

In LRA Section 3, the applicant provided the results of the AMRs for those structures and

components that were identified in LRA Section 2 as being within the scope of license renewal

and subject to an AMR.

3.0 Applicant's Use of the Generic Aaing Lessons Learned Report

In preparing its license renewal application (LRA), Nuclear Management Company (NMC or the

applicant) credited NUREG-1 801, "Generic Aging Lessons Learned (GALL) Report," dated

July 2001. The GALL Report contains the staff's generic evaluation of existing plant programs

and documents the technical basis for determining where existing programs are adequate

without modification and where existing programs should be augmented for the period of

extended operation. The evaluation results documented in the GALL Report indicate that many

of the existing programs are adequate to manage the aging effects for particular 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 an LRA to demonstrate the

programs at its facility correspond to those reviewed and approved in the report.

The purpose of the GALL Report is to provide the staff with a summary of staff-approved AMPs

to manage or monitor the aging of structures and components that are subject to an AMR. If an

applicant commits to implementing these staff-approved AMPs, the time, effort, and resources

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

effectiveness of the license renewal review process. The GALL Report also serves as a

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

staff determined will adequately manage or monitor aging during the period of extended

operation.

The GALL Report identifies (1) systems, structures, and components (SSCs), (2) structure and

component (SC) materials, (3) the environments to which the SCs are exposed, (4) the aging

effects associated with the materials and environments, (5) the AMPs that are credited with

managing or monitoring the aging effects, and (6) recommendations for further applicant

evaluations of aging management for certain component types.

To determine whether using the GALL Report would improve the efficiency of the license

renewal review, the staff conducted a demonstration project to exercise the GALL process and

to determine the format and content of a safety evaluation (SE) based on this process. The

results of the demonstration project confirmed that the GALL process will improve the efficiency

and effectiveness of the LRA review while maintaining the staff's focus on public health and

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

Nuclear Power Plant," dated July 2001 (SRP-LR), was prepared based on both the GALL model

and lessons learned from the demonstration project.

The staff performed its LRA review in accordance 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 guidance provided in NUREG-1 800, and the guidance

provided in NUREG-1 801.

In addition to its LRA review, the staff conducted an onsite audit and review of selected AMRs

and associated AMPs as described in the "Audit and Review Report for Plant Aging

Management Reviews and Programs, Point Beach Nuclear Plant, Units I and 2," dated

April 11, 2005 (ML051020288). The onsite audits and reviews are designed to maximize the

efficiencies of the staff's LRA review. The need for formal correspondence between the staff

and the applicant was reduced and the result was an improvement in the review's efficiency. In

addition, the applicant could respond to questions and the staff could readily evaluate the

applicant's responses.

3.0.1 Format of the LRA

NMC submitted an application that followed the standard LRA format, as agreed to between the

staff and the Nuclear Energy Institute (see letter dated April 7, 2003, ML030990052). This

revised LRA format incorporates lessons learned from the staff's reviews of the previous five

LRAs. These previous applications used a format developed from information gained during a

demonstration project, between the staff and the Nuclear Energy Institute (NEI), conducted to

evaluate the use of the GALL Report in the staff's review process.

The organization of LRA Section 3 parallels SRP-LR Chapter 3. The AMR results information

in LRA Section 3 is presented in the following two table types.

(1) Table 1: Table 3.x.1 - where U3U indicates the LRA Section number, "f indicates the

subsection number from the GALL Report, and "1I indicates that this is the first table

type in LRA Section 3.

(2) Table 2: Table 3.x.2-y - where u3U indicates the LRA Section number, Y indicates the

subsection number of the GALL Report, "2m indicates that this is the second table type in

LRA Section 3, and "y" indicates the system table number.

The content of the previous applications and the PBNP application is essentially the same. The

intent of the revised format used for the PBNP application was to modify the tables in Chapter 3

to provide additional information to assist the staff in its review. In Table 1 the applicant

summarized the portions of the application t considered to be consistent with the GALL Report.

In Table 2, the applicant identified the linkage between the scoping and screening results in

Chapter 2 and the AMRs in Chapter 3.

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3.0.1.1 Overview of Table I

Table 3.x.1 (Table 1) provides a summary comparison of how the facility aligns with the

corresponding tables of the GALL Report, Volume 1. The table is essentially the same as

Tables 1 through 6 provided in the GALL Report, Volume 1, except that the nType column has

been replaced by an item Numbern column and the "Item Number in GALL' column has been

replaced by a "Discussionm column. The 'Item Number' column provides the reviewer with a

means to cross-reference from Table 2 to Table 1. The "Discussionm column is used by the

applicant to provide clarifying/amplifying information. The following are examples of information

that might be contained within this column:

* further evaluation recommended - information or reference to where that information is

located;

* the name of a plant-specific program being used;

* exceptions to the GALL Report (NUREG-1 801) assumptions;

* discussion of how the line item is consistent with the corresponding line item in

NUREG-1 801, Volume 1, when that may not be intuitively obvious; and

* discussion of how the line item is different from the corresponding line item in the

NUREG-1 801, Volume 1 (e.g., when there is exception taken to an AMP that is listed in

NUREG-1801, Volume 1).

The format of Table 1 provides the reviewer with a means of aligning a specific Table 1 row with

the corresponding NUREG-1 801, Volume 1 table row, thereby allowing for the ease of checking

consistency.

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 being subject to an AMR. The LRA contains a Table 2 for each

of the components or systems within a system grouping (e.g., reactor coolant systems,

engineered safety features, auxiliary systems). For example, the engineered safety features

group contains tables specific to the containment spray system, containment isolation system,

and emergency core cooling system. Table 2 consists of the following nine columns:

(1) Component Type - The first column identifies the component types from LRA Section 2

that are subject to AMR. They are listed in alphabetical order.

(2) Intended Function - The second column contains the license renewal intended functions

(including abbreviations, where applicable) for the listed component types. Definitions

and abbreviations of Intended functions are contained within the "Intended Functions"

table of LRA Section 2.

(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. Internal and external service environments are indicated and a list of

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these environments is provided in the Internal Service Environments and External

Service Environments' tables of LRA Section 3.

(5) Aging Effect Requiring Management - As part of the AMR process, the applicant

determines any aging effects requiring management for the material and environment

combination in order to maintain the intended function of the component type. These

aging effects requiring management are listed in column five.

(6) Aging Management Programs - The sixth column lists the AMPs the applicant used to

manage the identified aging effects.

(7) GALL Volume 2 Item - Each combination of component type, material, environment,

aging effect requiring management, and AMP that is listed in Table 2, is compared to

NUREG-1 801, Volume 2, with consideration given to the standard notes, to identify

inconsistencies. When they are identified, they are documented by noting the

appropriate NUREG-1 801, Volume 2 item number in column seven of Table 2. If there

is no corresponding item number in NUREG-1 801, Volume 2, this row in column seven

is left blank. That way, a reviewer can readily identify where there is correspondence

between the plant-specific tables and the NUREG-1801, Volume 2 tables.

(8) Table 1 Item - Each combination of component, material, environment, aging effect

requiring management, and AMP that has been identified in NUREG-1 801, Volume 2

item number must also have a Table 3.x.1 line item reference number. The

corresponding line item from Figure 3.0-1 is listed in column eight of Table 2. If there is

no corresponding item in NUREG-1 801, Volume 1, this row in column eight is left blank.

That way, the information from the two tables can be correlated.

(9) Notes - In order to realize the full benefit of NUREG-1 801, each applicant should identify

how the information in Table 2 aligns with the information in NUREG-1 801, Volume 2.

This is accomplished through a series of notes. All note references with letters are

standard notes that will be the same from application to application throughout the

industry. Any plant-specific notes, which are in addition to the standard notes, will be

identified by a number.

3.0.2 Staff's Review Process

The staff conducted the following three types of evaluations of the AMRs and associated AMPs.

(1) For items that the applicant stated were consistent with the GALL Report, the staff

conducted either an audit or a technical review to determine consistency with the GALL

Report.

(2) For items the applicant stated were consistent with the GALL Report with exceptions

and/or enhancements, the staff conducted either an audit or a technical review of the

item to determine consistency with the GALL Report. In addition, the staff conducted

either an audit or a technical review of the applicants technical justification for the

exceptions and the adequacy of the enhancements.

(3) For other items, the staff conducted a technical review pursuant to 10 CFR 54.21 (a)(3).

The staff performed audits and technical reviews of the applicant's AMPs and AMRs. These

audit and technical reviews determined whether the effects of aging on structures and

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components can be adequately managed so that their intended functions can be maintained

consistently with the plant's current licensing basis (CLB) for the period of extended operation

as required by 10 CFR Part 54, Requirements for Renewal of Operating Licenses for Nuclear

Power Plants."

The staff performed onsite audits during the weeks of April 26 and June 7, 2004, to verify

selected AMPs and AMR results that the applicant claimed were consistent with the GALL

Report were actually consistent as claimed. The staff conducted a public exit meeting on

July 15, 2004. Details of the staff's onsite audit are documented in the "Audit and Review

Report for Plant Aging Management Reviews - Point Beach Nuclear Plant, Units 1 and 2,"

dated April 11, 2005 (ML051020288).

3.0.2.1 Review of AMPs

For those AMPs for which the applicant claimed consistency with the GALL AMPs, the staff

conducted either an audit or a technical review to verify that the applicant's AMPs were

consistent with those in the GALL Report. 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 effect(s) for which it was

credited.

For AMPs that were not evaluated in the GALL 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 SRP-LR Appendix A.

(1) Scope of the Program - The scope of the program should include the specific SCs

subject to an AMR for license renewal.

(2) Preventive Actions - Preventive actions should prevent or mitigate aging degradation.

(3) Parameters Monitored or Inspected - The parameters monitored or inspected should be

linked to the degradation of the particular structure or component intended functions(s).

(4) Detection of Aging Effects - Detection of aging effects should occur before there is a

loss of structure or component intended functions(s). This includes aspects such as

method or technique (Le., visual, volumetric, surface inspection), frequency, sample

size, data collection and timing of new/one-time inspections to ensure timely detection of

aging effects.

(5) Monitoring and Trending - Monitoring and trending should provide predictability of the

extent of degradation, and timely corrective or mitigative actions.

(6) Acceptance Criteria - Acceptance criteria, against which the need for corrective action

will be evaluated, should ensure that the structure or component intended function(s)

are maintained under all CLB design conditions during the period of extended operation.

(7) Corrective Actions - Corrective actions, including root cause determination and

prevention of recurrence, should be timely.

(8) Confirmation Process - The confirmation process should ensure that preventive actions

are adequate and that appropriate corrective actions have been completed and are

effective.

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(9) Administrative Controls - Administrative controls should provide a formal review and

approval process.

(10) Operating Experience - Operating experience of the AMP, including past corrective

actions resulting in program enhancements or additional programs, should provide

objective evidence to support the conclusion that the effects of aging will be managed

adequately so that the SC intended function(s) will be maintained during the period of

extended operation.

Details of the staff's audit evaluation of program elements (1) through (6) are documented in its

audit and review report and are summarized in SER Section 3.0.3.

The staff reviewed the applicant's quality assurance program and documented its evaluations in

SER Section 3.0.4. The staff's evaluation of the quality assurance program included

assessment of the following program elements: (7) corrective actions, (8) confirmation process,

and (9) administrative controls.

The staff reviewed the information conceming program element (10), operating experience, and

documented this evaluation in its audit and review report. This information is summarized in

SER Section 3.0.3.

The staff also reviewed the final safety analysis report (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

LRA Table 2 contains information concerning whether or not the AMRs align with the AMR

information identified in the GALL Report. For a given AMR in Table 2, the staff reviewed the

intended function, material, environment, aging effect requiring management, and AMP

combination for a particular component type within a system. The AMRs that correlate between

a combination in Table 2 and a combination in the GALL Report were identified by a referenced

item number in column seven, "GALL, Volume 2 Item." The staff also conducted onsite audits

to verify the correlation. A blank column seven indicates that the applicant was unable to locate

an appropriate corresponding combination in the GALL Report. The staff conducted a technical

review of these combinations that were not consistent with the GALL Report. The next column,

"Table 1 Item," provided a reference number that indicated the corresponding row in Table 1.

3.0.2.3 FSAR Supplement

Consistent with the SRP-LR, for the AMRs and associated AMPs that it reviewed, the staff also

reviewed the FSAR supplement that summarizes the applicant's programs and activities for

managing the effects of aging for the period of extended operation, as required by

10 CFR 54.21 (d).

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3.0.2.4 Documentation and Documents Reviewed

In performing its review, the staff relied heavily on the LRA, the LRA supplements, the SRP-LR,

and the GALL Report.

Also, during the onsite audit, the staff examined the applicant's justification, as documented in

the staff's PBNP audit and review report, to verify that the applicants activities and programs

will adequately manage the effects of aging on SCs. The staff also conducted detailed

discussions and interviews with the applicant's license renewal project personnel and others

with technical expertise relevant to aging management.

3.0.3 Aging Management Programs

Table 3.0.3-1 presents the AMPs credited by the applicant and described in LRA Appendix B.

The table also indicates the GALL Report AMP that the applicant claimed its AMP was

consistent with (if applicable) and the SSCs for managing or monitoring aging. The section of

the SER in which the staff's evaluation of the program is documented is provided.

Table 3.0.3-1 PBNP's Aging Management Programs

-PBINP AMP GALL GALL LRA Systems or Strutures that Staffs SER

(LRA Section) ComparIson AMP(s) Creddit the AMP Section

ASME Section Xi, Consistent with XI.M1 Reactor coolant system 3.0.3.2.1

Subsections IWB, exceptions and XI.M3

IWC, and IWD enhancements

Inservice Inspection

Program

(B2.1.1)

ASME Section Xi, Consistent with XI.S1 Containments, structures, and 3.0.3.2.2

Subsections IWE exceptions and XI.S2 component supports

and IWL Inservice enhancements XI.S4

Inspection Program

(B2.1.2)

ASME Section XI, Consistent with XL.S3 Containments, structures, and 3.0.3.2.3

Subsection IWF exceptions and component supports

Inservice Inspection enhancements -

Program (B2.1.3)

Bolting Integrity Consistent with X1 .M18 Reactor coolant system; engineered 3.0.3.2.4

Program exceptions and safety features; auxiliary systems;

(B2.1.4) enhancements steam and power conversion system

Boraflex Monitoring Consistent with XI.M22 Containments, structures, and 3.0.3.2.5

Program enhancements component supports (B2.1.5)

3-7
P t LR trcw 6mht e~ ^:PBNP AMP G ALL A tems or trutGALL s ureerri tatStf'SER

(LRA Sectin Cmaio AMs)reit teAMPSeto

Boric Acid Corrosion Consistent with XI.M10 Reactor coolant system; engineered 3.0.3.2.6

Program enhancements safety features; auxiliary systems;

(B2.1.6) steam and power conversion system;

containments, structures, and

component supports; electrical and

instrumentation and controls

Buried Services Consistent with XL.M34 Auxiliary systems 3.0.3.2.7

Monitoring Program enhancements

(62.1.7)

Cable Condition Consistent with Xl.E1 Electrical and instrumentation and 3.0.3.2.8

Monitoring Program exceptions and XL.E2 controls

(B2.1.8) enhancements XL.E3

Closed-Cycle Cooling Consistent with XL.M21 Reactor coolant system; engineered 3.0.3.2.9

Water System exceptions and safety features; auxiliary systems

Surveillance Program enhancements

(62.1.9)

Fire Protection Consistent with XL.M26 Auxiliary systems; containments, 3.0.3.2.10

Program exceptions and XL.M27 structures, and component supports

(62.1.10) enhancements

Flow-Accelerated Consistent with XI.M17 Reactor coolant system; steam and 3.0.3.2.11

Corrosion Program exceptions and power conversion system

(62.1.11) enhancements

Fuel Oil Chemistry Consistent with XI.M30 Auxiliary systems 3.0.3.2.12

Control Program exceptions and

(62.1.12) enhancements

One-Time Inspection Consistent with XL.M32 Reactor coolant system; engineered 3.0.3.2.13

Program exceptions and XL.M33 safety features; auxiliary systems;

(62.1.13) enhancements steam and power conversion system

Open-Cycle Cooling Consistent with XI.M20 Auxiliary systems; steam and power 3.0.3.2.14

(Service) Water exceptions and conversion system

System Surveillance enhancements

Program

(B2.1.14)

Periodic Surveillance Plant-specific Reactor coolant system; engineered 3.0.3.3.1

and Preventive safety features; auxiliary systems;

Maintenance steam and power conversion system;

Program containments, structures, and

(62.1.15) component supports

Reactor Coolant Consistent with XI.M1 1 Reactor coolant system 3.0.3.2.15

System Alloy 600 exceptions and

Inspection Program enhancements

(62.1.16)

Reactor Vessel Consistent with Xl.M13 Reactor coolant system 3.0.3.2.16

Internals Program exceptions and XI.M1 6

(B2.1.17) enhancements

3-8
PBNP AMP GALL GALL L Stems IA or Structures that S ER

(LRA Section) Comparison AMP(s) D -CredittheAMP Section

Reactor Vessel Consistent with XI.M31 Reactor coolant system 3.0.3.2.17

Surveillance Program exceptions and

(B2.1.18) enhancements

Steam Generator Consistent with XI.M19 Reactor coolant system 3.0.3.2.18

Integrity Program enhancements

(62.1.19)

Structures Monitoring Consistent with XI.M23 Containments, structures, and 3.0.3.2.19

Program exceptions and XI.S5 component supports

(B2.1.20) - enhancements XI.S6

Xl.S7

Systems Monitoring Plant-specific and XI.M29 Reactor coolant system; engineered 3.0.3.3.2

Program in part, Is safety features; auxiliary systems;

(B2.1.21) consistent with steam and power conversion system

exceptions and

enhancements

Tank Internal Plant-specific Auxiliary systems; steam and power 3.0.3.3.3

Inspection Program conversion system

(B2.1.22) _

Thimble Tube Plant-specific Reactor coolant system 3.0.3.3.4

Inspection Program

(B2.1.23)

Water Chemistry Consistent with XI.M2 Reactor coolant system; engineered 3.0.3.2.20

Control Program exceptions and safety features; auxiliary systems;

(B2.1.24) enhancements steam and power conversion system;

containments, structures, and

component supports

Environmental Consistent with X.E1 Electrical and Instrumentation and 3.0.3.2.21

Qualification enhancements Controls

Program

(63.1)

Fatigue Monitoring Consistent with X.M1 Metal Fatigue (LRA Section 4.3) 3.0.3.2.22

Program enhancements (B3.2)

Pre-Stressed Consistent with X.S1 Loss of Preload (LRA Section 4.5) 3.0.3.2.23

Concrete enhancements

Containment Tendon

Surveillance Program

(63.3)

3.0.3.1 AMPs That Are Consistent with the GALL Report

In LRA Appendix B, the applicant indicated that most of its AMPs are consistent, but with

exceptions and/or enhancements, to the GALL Report. The staff's evaluation of these

programs is documented in SER Section 3.0.3.2. The Periodic Surveillance and Preventive

Maintenance Program, System Monitoring Program, Tank Internal Inspection Program, and

Thimble Tube Inspection Program are considered as PBNP plant-specific. The staff's

evaluation of these programs is documented in SER Section 3.0.3.3.

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3.0.3.2 AMPs That Are Consistent with the GALL Report with Exceptions or

Enhancements

In LRA Appendix B, the applicant indicated that the following AMPs were, or will be consistent

with the GALL Report with exceptions and/or enhancements:

* ASME Section Xl, Subsections IWB, IWC, and IWD Inservice Inspection Program

(B2.1.1)

* ASME Section Xi, Subsections IWE and IWL Inservice Inspection Program (B2.1.2)

* ASME Section Xl, Subsections IWF Inservice Inspection Program (B2.1.3)

* Bolting Integrity Program (B2.1.4)

* Boraflex Monitoring Program (B2.1.5)

* Boric Acid Corrosion Program (B2.1.6)

* Buried Services Monitoring Program (B2.1.7)

* Cable Condition Monitoring Program (B2.1.8)

* Closed-Cycle Cooling Water System Surveillance Program (B2.1.9)

* Fire Protection Program (B2.1.10)

* Flow-Accelerated Corrosion Program (B2.1.11)

* Fuel Oil Chemistry Control Program (B2.1.12)

* One-Time Inspection Program (B2.1.13)

* Open-Cycle Cooling (Service) Water System Surveillance Program (B2.1.14)

* Reactor Coolant System Alloy 600 Inspection Program (B2.1.16)

* Reactor Vessel Internals Program (B2.1.17)

* Reactor Vessel Surveillance Program (B2.1.18)

* Steam Generator Integrity Program (B2.1.19)

* Structures Monitoring Program (B2.1.20)

* Water Chemistry Control Program (B2.1.24)

* Environmental Qualification Program (B3.1)

* Fatigue Monitoring Program (B3.2)

* Pre-Stressed Concrete Containment Tendon Surveillance Program (B3.3)

For AMPs that the applicant claimed are consistent with the GALL Report with exceptions

and/or enhancements, the staff performed an audit to confirm that those attributes or features

of the program for which the applicant claimed consistency with the GALL Report were indeed

consistent. The staff also reviewed the exceptions and/or enhancements to the GALL Report to

determine whether they were acceptable and adequate.

The staff determined that the applicant used the word "enhancement" to describe two types of

revisions to plant procedures or program activities. First, the applicant used "enhancement" to

describe a programmatic revision to achieve consistency with the GALL Report. The staff

reviewed these programmatic revisions pursuant to the process described in the staff's audit

and review plan.

The applicant also used the word "enhancement" to describe revisions that were required only

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by the applicant's internal administrative implementing documents. -This type of administrative

revision is not necessary to demonstrate consistency with the GALL Report criteria. Therefore,

the staff considered this type of revision to be an administrative enhancement that does not

require staff review.

The results of the staff's audit and reviews of the applicant's AMPs are documented in the

following sections.

3.0.3.2.1 ASME Section Xl, Subsections IWB, IWC, and IWD Inservice Inspection Program

Summary of Technical Information in the Application. The applicant's ASME Code Section Xl,

Subsections IWB, IWC, and IWD Inservice Inspection Program is described in LRA

Section B2.1.1, "ASME Section Xl, Subsections IWB, IWC, and IWD Inservice Inspection

Program." In the LRA, the applicant stated that this is an existing program that is consistent,

with exceptions and enhancements; with GALL AMP XI.M1, "ASME Section XI, Subsections

IWB, IWC, & IWD," and GALL AMP XI.M3, "Reactor Head Closure Studs."

The applicant stated that the ASME Code Section Xl, Subsections IWB, IWC, and IWD

Inservice Inspection Program is credited for managing the aging effects in Class 1, 2, and 3

piping, components and their integral attachments. Specifically, inspections are performed to

identify and correct degradation in Class 1, 2, and 3 piping, components and their integral

attachments. The program includes periodic visual, surface and/or volumetric examinations

and leakage tests of all Class 1, 2, and 3 pressure-retaining components, and their integral

attachments, including welds, pump casings, valve bodies, and pressure-retaining bolting.

These components and their integral attachments are identified in ASME Code Section Xl,

"Rules for Inservice Inspection of Nuclear Power Plant Components," or commitments requiring

augmented inservice inspections, and are within the scope of license renewal. This program is

in accordance with 10 CFR 50.55a and NRC-approved code cases and relief requests.

In LRA Section 2.1.1.3.8, the applicant addressed its approach of one-time Inspection of small

bore piping for Class 1 piping welds. The applicant stated that the risk-informed inservice

inspection (RI-ISI) program inspections of piping welds less than 4-inch nominal pipe size

(NPS) will include volumetric examinations, with exception of socket welded connections. A

surface examination will be substituted for inspection of socket welds until a meaningful

volumetric inspection technique is created for the geometry presented by socket welds.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. Details of the staff's audit evaluation are documented in the

staff's audit and review report. Furthermore, the staff reviewed the exceptions and associated

justifications to determine whether the AMP, with exceptions, remains adequate to manage the

aging effects for which it is credited.

In LRA Section B2.1.1, the applicant stated that its ASME Code Section Xi, Subsections IWB,-

IWC, and IWD Inservice Inspection Program is consistent with GALL AMP XI.M1, with

exceptions and enhancements.

The ASME Code Section Xl, Subsections IWB, IWC, and IWD Inservice Inspection Program

takes exceptions to the "scope of the program" program element for GALL AMP XI.Ml. The

applicant identified exceptions to IWB-1220, IWC-1220, but not IWD-1220. Specifically, the

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applicant's exceptions included (1) use of the exemption criteria found in IWB-1 220 of the

ASME Code Section Xl, 1989 Edition, as required by 10 CFR 50.55a, and (2) use of the

exemptions associated with IWC-1 220 of ASME Code Section Xl 1998 Edition through 2000

Addenda (98A00) for the auxiliary feedwater system piping, vessels, pumps, valves and their

connections in piping between 4-inch and 1 '/2-inch NPS. The applicant also stated that these

exceptions will result in fewer components being exempted from the ASME Code requirements.

For the first exception, 1 0 CFR 50.55a(b)(2)(xi) states that for Class 1 piping, applicants are not

permitted to apply the criteria that allows exemption from inspection of the components listed in

IWB-1220 of ASME Code Section Xi, 1989 Addenda through the latest edition. Rather,

10 CFR 50.55a(b)(2)(xi) directs the applicant to perform inspections of the components listed in

IWB-1220 of ASME Code Section Xl, 1989 Edition without the exceptions. This exception to

the GALL Report is consistent with the requirements of 10 CFR 50.55a and was in the scope of

the ASME Code evaluation documented in the GALL Report Volume 2, Chapter 1. On the

basis of its review and ASME Code evaluation performed as part of the GALL Report, the staff

found this exception acceptable.

For the second exception, the ASME Code 98A00 deleted the IWC-1220 exception that was

permitted by the ASME Code 1995 Edition through 1996 Addenda (95A96). Section 50.55a of

10 CFR was amended in 2001 to adopt ASME Code 98A00. In the Federal Register statement

of consideration (67 FR 60520) for this rulemaking, the staff documented its evaluation of

ASME Code 98A00 to determine if the recommendations and conclusions of the GALL Report

are also applicable for AMPs that rely on the ASME Code which are incorporated into

10 CFR 50.55a by the final rule. For ASME Code 98A00, the staff found that the GALL Report

remains valid and justified the use of ASME Code 98A00 as an alternative to ASME Code

95A96 without the need for the applicant to submit to the NRC its plant-specific justification

associated with license renewal. On the justification of its review, the staff found this exception

acceptable. Furthermore, the basis for this finding applies to all exceptions to ASME Code

Section Xl, Subsections, which identify the exception of using the ASME Code 98A00 version

rather than the ASME Code 95A96 version, as identified in the GALL Report.

The ASME Code Section Xl, Subsections IWB, IWC, and IWD Inservice Inspection Program

takes exceptions to the "parameters monitored or inspected" and "detection of aging effects"

program elements for GALL AMP XL.M1, in that the applicant will use the ASME Code 98A00,

Section Xl. Specifically, the applicant's ISI Program (1) is currently based on the ASME Code

98A00 Section Xl, (2) will implement risk-informed ISI (RI-ISI) for examination categories B-F,

B-J, C-F-1, and C-F-2, (3) will modify the sequence of examinations for welds, (4) will examine

only one of the three vessels comprising the regenerative heat exchanger for Category B-D, (5)

will use technical specification surveillance testing as an alternative to the system leakage test

of Class 3 pressure-retaining components of the emergency diesel generator support systems

for Category D-B, (6) will use alternative requirements of ASME Code Cases N-533-1, N-566-1,

and apply N-616, and (7) will only perform visual examination for Class 1 pump casing welds,

as specified in ASME Code 98A00.

The ASME Code Section Xl, Subsections IWB, IWC, and IWD Inservice Inspection Program

also takes exception to the "parameters monitored or inspected" and "detection of aging

effects' program elements for GALL AMP XI.M3, in that the applicant will use the ASME Code

Section Xl, 98A00. In addition, it takes two exceptions to the 'monitoring and trending" program

element for GALL AMP XL.M1. Specifically, the applicant stated that (1) IWB-2420(b) of ASME

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Code 98A00 allows use of the acoustic emission to monitor growth of existing flaws in lieu of

successive examinations during the next three inspection periods and (2) the exception

modifies the sequence of the examination established in the previous inspection interval in a

manner that reduces scaffolding, insulation and radiation inspection.

The staff's review of LRA Section B2.1.1 identified an area in which additional information was

necessary to complete the review of the applicant's program elements. The applicant

responded to the staff's request for additional information (RAI) as discussed below.

RAI B2.1. Several currently approved relief requests, shown in RAI Table 1, were reviewed by

the project team during the audit and review of the ASME Code Section XI, Subsections IWB,

IWC, and IWD Inservice Inspection Program and ASME Code Section Xl, Subsections IWE

and IWL Inservice Inspection Program. The relief requests were presented as the bases for

taking exceptions to the following GALL Report AMPs:

* GALL Section XI.M1, UASME Section Xl Inservice Inspection, Subsections IWB, IWC,

and IWD"

* GALL Section Xl.M3, "Reactor Head Closure Studs"

* GALL Section XI.S1, "ASME Section Xl, Subsection IWE"

* GALL Section XL.S2, UASME Section Xl, Subsections IWL"

Relief requests are approved by the NRC as described in 10 CFR 50.55a, Codes and

Standards. Relief requests only apply to CLB issues and are time-limited. Consequently, citing

approved requests cannot be used as a basis for taking exception to the GALL since they may

not be renewed.

Each exception to the GALL Report must be evaluated for NRC approval based on the

technical bases that are associated with aging management regardless of whether there is an

approved, related relief request. Also, it should be noted that approval of an exception to GALL

with respect to a plant's AMP does not mean that a relief request that covers the same issue

will be approved during the period of extended operation. The 10 CFR 50.55a process must

still be used for relief request approval. Citing a relief request does not provide an acceptable

basis to take an exception to GALL.

In RAI B2.1, dated March 30, 2005, the staff requested the applicant to provide the technical

bases, as they relate to aging management, without referencing relief requests, for the

exceptions taken to the ASME Code Section Xl, Subsections IWB, IWC, and IWD Inservice

Inspection Program and the ASME Code Section Xl, Subsections IWE and IWL Inservice

Inspection Program. This was identified as open item (01) B2.1.

In Its response to 01 B2.1, by letter dated July 5, 2005, the applicant withdrew the following

alternatives, initially credited as exceptions in the LRA:

* Altering the Date of the Start of the Fourth inspection Interval

* Altemate Requirements to Repair and Replacement Documentation Requirements and

Inservice Inspection Summary Report Preparation and Submission as Required by

IWA-4000 and IWA-6000 (Code Case N-532-1)

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* Alternate Requirements for VT-2 Visual Examination of Class 1, 2, and 3 Insulated

Pressure-Retaining Bolted Connections (Code Case N-533-1)

* Corrective Action for Leakage Identified at Bolted Connections (Code Case N-566-1)

* Successive Inspections (Code Case N-624)

* Alternative to Welding and Brazing Performance Qualification Requirements (Code

Case N-600)

* Relief from Regenerative Heat Exchanger Examinations

* Emergency Diesel System VT-2 Examination

* Request for Alternative to ASME Section Xl, Appendix VIII, Supplement 10

The applicant clarified in its letter that these alternatives are not exceptions to the GALL Report,

as they are either administrative and did not affect aging management, or the aging effect was

managed by another AMP cited in the LRA. The staff found each of the bases provided in the

applicant's RAI response acceptable and agreed that these alternatives are not exceptions to

the GALL Report. The staff found the withdrawal of these alternatives acceptable.

In addition, in its July 5, 2005, letter, the applicant withdrew its exception concerning the use of

ASME Code, Section Xl, 1998 Edition with Addenda through 2000. The staff found this

withdrawal acceptable based on the understanding that Westinghouse performed a fracture

toughness analysis for Class I pump casing welds, as discussed in the original LRA

Section 4.4.3. This Westinghouse analysis addressed Code Case N-481, which was endorsed

by the staff in RG 1.147 and found to be an acceptable alternative to volumetric examinations.

The staff found the combination of VT-1 examination per A2000 and flaw tolerance analysis to

be technically acceptable to manage the aging effects of Class 1 pump casing welds.

With respect to the Alternative Requirements for VT-2 Visual Examination of Class 1, 2, and 3

Insulated Pressure-Retaining Bolted Connections, Section XI, Division 1 (Code Case N-616),

the applicant withdrew its exception and provided the following commitment:

As a part of the ASME Section XI, Subsections IWB, IWC, and IWD Inservice Inspection

Program, the requirements of Code Case N-616 will be supplemented by a VT-2 visual

examination performed each outage for Class 1 systems and each inspection period for

Class 2 and 3 systems with the insulation removed from the bolted connections. The

connections are not pressurized during these examinations.

With the inclusion of the above commitment, the staff found the aging management program

consistent with the GALL Report AMP XI.M1, HASME Section Xl Inservice Inspection,

Subsection IWB, IWC and IWD." The staff found the withdrawal of this exception acceptable.

In addition, the applicant provided, in part, the following technical basis in support of its GALL

Report exception for the Risk-informed Examination of Class I and Class 2 Piping Butt Welds

(Code Case N-578 and EPRI TR-1 12657):

This alternative implements a Risk-informed Inservice Inspection (RI-ISI)-Program for

ASME Class 1 and 2 piping welds (Categories B-F, B-J, C-1-1, and C-F-2 only), for both

PBNP Units 1 and 2. The RI-ISI program provides an acceptable alternative to the

piping ISI requirements with regards to (1) the number of locations, (2) the locations of

3-14
inspections, and (3) the method of inspection. The RI-ISI program maintains the

fundamental requirements of ASME Section Xl, such as the examination technique,

examination frequency, and acceptance criteria. Although the RI-ISI program reduces

the number of required examination locations in some cases, it maintains an acceptable

level of quality and safety by focusing inspections on the most safety significant welds

with nondestructive examination (NDE) techniques that are more focused towards

finding the type of expected degradation as well as the types of flaws and degradation

found during traditional inspections.

A systematic approach was used to identify component susceptibility to common

degradation mechanisms and to categorize these degradation mechanisms into the

appropriate degradation categories with respect to their potential to result in a

postulated leak or rupture in the pressure boundary. An evaluation to determine the

susceptibility of components to a particular degradation mechanism that may be a

precursor to a leak or rupture in the pressure boundary, and an independent

assessment of the consequences of a failure at that location were performed. Industry

and plant-specific piping failure information (i.e., operating experience) was used to

identify piping degradation mechanisms and failure modes, and consequence

evaluations performed using PRAs to establish safety ranking of piping segments for

selecting new inspection locations. The degradation mechanisms identified in the RI-ISI

program include thermal fatigue, thermal transients, intergranular stress-corrosion

cracking (IGSCC), and primary water stress-corrosion cracking (PWSCC). The

consequences of pressure boundary failures were evaluated and ranked on their impact

on core damage and early release. Therefore, redistributing the welds to be inspected

with consideration of the safety significance of the segments provides assurance that

segments whose failure have a significant impact on plant risk receive an acceptable

and improved level of inspection.

... This altemative is also credited for the inspection of small bore piping prior to the

period of extended operation instead of the One-Time Inspection Program, as

recommended in NUREG-1801 Section XI.M32. The RI-ISI program will require

examination of a sample of susceptible risk significant small bore (< 4 inch) ASME

Class 1 and 2 piping. The RI-ISI program will require volumetric examination of

non-socket welds and surface examination of socket welds in the sample.

Approximately twenty small bore piping locations per unit will be examined under the

RI-ISI program. Therefore, the RI-ISI program provides an acceptable alternative with

regards to (1) the number of locations, (2) the locations of inspections, and (3) the

method of inspection for small bore ASME Class 1 and 2 piping.

The staff found this exception to the management of aging effects acceptable because:

* It is applicable only to ASME Class 1 and 2 piping welds (Categories B-F, B-J, C-F-1,

and C-F-2),

* The RI-ISI program maintains the ASME Section Xl, fundamental requirements for the

examination technique, examination frequency, and acceptance criteria,

* It inspects a sample of locations that are the most safety significant with consideration of

industry and plant-specific piping operating experience, and

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* It manages the aging effects of thermal fatigue, thermal transients, IGSCC, and

PWSCC, which are the aging effects of interest in the LRA AMRs.

Furthermore, the staff found the use of the RI-ISI methods an appropriate method to identify the

location and inspection method of small bore pipes. The use of this AMP as an exception to

using the One-Time Inspection AMP defined in the GALL Report results in a larger number of

smallbore pipes being volumetrically inspected and, therefore, provides a greater population of

inspection results to determine if an active aging effect is occurring in the small bore piping.

Based on the discussion above, the staff concluded that the applicant's response to RAI B2.1 is

acceptable. The staff's concerns with respect to the ASME Section Xl, Subsections IWB, IWC,

and IWD exceptions are resolved; further discussions on remaining exceptions related to

Subsections IWE, and IWL, and Subsection IWF are documented in SER Sections 3.0.3.2.2

and 3.0.3.2.3, respectively. The staff concluded that this part of 01 B2.1 is closed.

In LRA Section B2.1.1 the applicant stated that its ASME Code Section Xi, Subsections IWB,

IWC, and IWD Inservice Inspection Program is consistent with GALL AMP XI.M1 and GALL

AMP XI.M3, with enhancements. The applicant stated that, for the detection of aging effects"

program element, enhancements include revisions to existing activities credited for license

renewal to ensure that inspections for the applicable aging effects are performed and any noted

indications are appropriately evaluated. Enhancements to plant process control procedures will

be made to ensure that use of flaw tolerance evaluation or the enhanced volumetric

examination of welded connections and cast austenitic stainless steel (CASS) in Class 1

components. A new leak-before-break (LBB) analysis, based on thermally aged material

properties, was performed throughout the period of extended operation.

Operating ExKerience. The staff reviewed the applicant's operating experience for the ASME

Code Section Xl, Subsections IWB, IWC, and IWD Inservice Inspection Program. The staff

found that the plant-specific operating experience indicates that visual inspections have proven

to be effective in managing the aging effects of ASME Code Section Xl, Subsections IWB,

IWC, and IWD Inservice Inspection Program components.

The applicant stated that review of industry operating experience related to the ASME Code

Section Xl, Subsections IWB, IWC, and IWD Inservice Inspection Program revealed numerous

instances of primary pressure boundary degradation and that the instances of degradation

generally fall into the following categories: (1) boric acid corrosion caused by leakage at

mechanical connections, (2) cracking caused by thermal fatigue, (3) degradation of bolting

caused by stress corrosion cracking (SCC) of high-strength bolts or boric acid corrosion, and

(4) leaks or cracks caused by PWSCC of Alloy 600 components.

The applicant also stated that most of the indications found by examinations required by its ISI

programs have been evidence of borated water leakage at mechanical joints such as flange

connections and valve bonnets. The applicant stated that a search of condition reports and

maintenance work orders on reactor vessel head closure studs revealed that no degradation of

the studs or nuts had been detected.

The applicant stated that a review of plant-specific operating experience revealed two instances

where ISI examinations discovered flaws through means other than the system leakage test.

3-16
Unacceptable flaw indications were discovered in each reactor vessel outlet nozzle-to-shell

weld during the ultrasonic examination of reactor vessel welds at Unit 1 in 1984. The applicant

performed a fracture mechanics evaluation that demonstrated that the flaws posed no threat to

continued safe operation of the reactor vessel. The applicant stated that subsequent

inspections resized the flaws using more accurate techniques and that the flaws were

determined to be within code allowances.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical staff to verify that the plant-specific operating experience did not reveal

any degradation not bounded by industry experience. On the basis of its review of the above

industry and plant-specific operating experience, the staff concluded that the ASME Code

Section Xl, Subsections IWB, IWC, and IWD Inservice Inspection Program will adequately

manage the aging effects that are identified in the LRA for which this AMP is credited.

FSAR Supplement. In LRA Section Al5.2.1, the applicant provided the FSAR supplement for

the ASME Code Section Xl, Subsections IWB, IWC, and IWD Inservice Inspection Program.

The staff reviewed these sections and determined that the information in the FSAR supplement

provides an adequate summary of the program activities. The staff found these sections of the

FSAR supplement meet the requirements of 10 CFR 54.21 (d).

Conclusion. On the basis of its review and audit of the applicant's program, the staff found that

those program elements for which the applicant claimed consistency with the GALL Report are

consistent with the GALL Report.- In addition, the staff reviewed the exceptions and the

associated justifications and determined that the AMP, with the exceptions, is adequate to

manage the aging effects for which it is credited. The staff found that the applicant had

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff also reviewed the FSAR supplement for this AMP

and founo that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.0.3.2.2 ASME Section Xl, Subsections IWE and IWL Inservice Inspection Program

Summary of Technical Information in the ADmlication. The applicant's ASME Code Section Xl,

Subsections IWE and IWL Inservice Inspection Program is described in LRA Section B2.1.2

"ASME Section Xl, Subsections IWE and IWL Inservice Inspection Program." The applicant

stated that this is an existing program that is consistent with GALL AMP XI.S4, "10 CFR Part 50

Appendix J." This program is also consistent, with exceptions and enhancements, with GALL

AMP XI.S1, "ASME Section Xi, Subsection IWE," and GALL AMP XI.S2, "ASME Section Xl,

Subsection IWL."

The applicant stated that the ASME Code Section Xl, Subsections IWE and IWL Inservice

Inspection Program, is credited for managing the aging effects of (1) steel liners of concrete

containments and their integral attachments; containment hatches and airlocks; seals, gaskets,

and moisture barriers; and pressure-retaining bolting; and (2) reinforced concrete containments

and unbonded post-tensioning systems. The primary inspection methods employed are visual

examinations with limited supplemental volumetric and surface examinations, as necessary.

Tendon anchorages and wires are examined visually. Tendon wires are tested to verify that

minimum mechanical property requirements are met. Tendon corrosion protection medium is

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analyzed for alkalinity, water content,- and soluble ion concentrations. Prestressing forces are

measured in sample tendons. Measured tendon lift-off forces are compared to predicted

tendon forces calculated in accordance with RG 1.35.1, "Determining Prestressing Forces for

Inspection of Prestressed Concrete Containments." The applicant stated that this program is in

accordance with 10 CFR 50.55a and NRC-approved code cases and relief requests. In

addition, the applicant stated that this program is credited by the Bolting Integrity Program, for

the inspection of pressure-retaining bolting associated with the containment pressure boundary.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. Details of the staff's audit evaluation are documented in the

staff's audit and review report. Furthermore, the staff reviewed the exceptions and associated

justifications to determine whether the AMP, with the exceptions, remains adequate to manage

the aging effects for which it is credited.

In LRA Section B2.1.2, the applicant stated that its ASME Code Section Xl, Subsections IWE

and IWL Inservice Inspection Program Is consistent with GALL AMP XL.S4 and is consistent

with GALL AMPs XI.S1 and XI.S2, with exceptions.

The applicant takes exception to the "parameters monitored or inspected" and "acceptance

criteria" program elements in that the applicant's program is based on different versions of the

American Concrete Institute (ACI) Code for concrete degradation. Specifically, the GALL AMP,

ASME Code Section Xl, Subsections IWE, and IWL Inservice Inspection Program cites ACI

201.1 R-68, Guide for Making a Condition Survey of Concrete in Service," instead of ACI

201.1 R-77 as a reference for concrete degradation. GALL AMP XI.S2 cites ACI 201.1 R-77 as

a source of information. The applicant also stated that the earlier version is consistent with the

1992 Addenda of IWL-251 0 and Table IWA-1 600-1.

The staff found that the earlier ACI version is identical to the later ACI version except for date of

issue. Also the earlier version is part of the applicant's CLB. On the basis that the earlier ACI

version is identical to the later ACI version except for date of issue, the staff found this

exception acceptable.

The applicant also takes exception to the "detection of aging effects" program elements for

GALL AMPs XI.S1 and XL.S2 in that (1) qualification of NDE personnel to a written practice in

accordance with SNT-TC1A is performed instead of CP-189, which is required by IWA-2300,

and (2) relaxation of illumination and direct examination distance requirements of IWA-2210

and allowing general visual inspection of inaccessible concrete surfaces instead of the VT-3

examination required by IWL-251 0(a), for GALL AMP XL.S2 only. The applicant justified these

exceptions based on an NRC-approved relief request.

The staff found that the applicant relied on ASME Code relief requests as its justification for the

exceptions. The staff found that use of an NRC-approved relief request is not an appropriate

basis for justifying an exception to the GALL Report. As discussed in the GALL Report,

Volume 2, Chapter 1, the staff evaluated the ASME Code 95A96 version pursuant to the ten

program elements to assure that the aging effects will be adequately managed. The staff,

when it approved a relief request per the requirements of 10 CFR 50.55a, did not evaluate the

exception to assure that the aging effect will be adequately managed during the period of

extended operation.

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The ASME Code Section Xl, Subsections IWE, and IWL Inservice Inspection Program relied on

the approved relief request as part of the justification for the exceptions. In RAI B2.1, as

discussed in SER Section 3.0.3.2.1, the staff requested the applicant to clarify the use of the

relief request and to provide technical justification for these exceptions. This was identified as

open item (01) B2.1.

In its response to 01 B2.1, by letter dated July 5, 2005, the applicant withdrew the following

alternatives, initially credited as exceptions in the LRA:

* Elimination of VT-3 Examinations of Seals and Gaskets

* No Successive Examination of Repairs

* Elimination of Required Bolt Torque or Tension Tests

* Elimination of the Need for Venting of Leak Chase Channels During Integrated Leak

Rate Tests

* Allowing the Qualification and Certification of NDE Personnel to a Written Practice in

Accordance with SNT-TC1 A Instead of CP-1 89

* -Relaxing the Illumination and Direct Examination Distance Requirements of IWA-2210

* Allowing a General Visual Inspection of Inaccessible Concrete Surfaces Instead of the

VT-3 Examination Required by IWL-2510(a)

The applicant clarified in its letter that each of these alternatives are not exceptions to the GALL

Report as they are either administrative, and did not affect aging management, or the aging

effect was managed by another AMP cited in the LRA. The staff found each of the bases

identified in the applicant's RAI response acceptable and agreed that these altematives are not

exceptions to the GALL Report. The staff found the withdrawal of these alternatives

acceptable.

Based on the discussion above, the staff concluded that the applicant's response to RAI B2.1 is

acceptable. The staff's concerns with respect to the ASME Section Xi, Subsections IWE and

IWL exceptions are resolved. Further discussions on remaining exceptions related to

Subsections IWA, IWB and IWC and Subsection IWF are documented in SER

Sections 3.0.3.2.1 and 3.0.3.2.3, respectively. The staff concluded that this part of 01 B2.1 is

closed.

In LRA Section B2.1.2, the applicant stated that its ASME Code Section Xl, Subsections IWE

and IWL Inservice Inspection Program is consistent with GALL AMPs XL.S4, XI.S1, and XI.S2,

with enhancements. The applicant stated that, for the "detection of aging effects" program

element, enhancements include modification to procedures to clarify that (1) test results are

documented in accordance with 10 CFR Part 50, Appendix J and (2) yield strength for tendon

wire samples will be determined in accordance with IWL-2523.2. The staff considered these

types of enhancements to be administrative enhancements that do not require staff reviei

Oerating Exnerience. The staff reviewed the applicant's operating experience for the ASME

Code Section Xl, Subsections IWE and IWL Inservice Inspection Program.

The applicant stated that plant-specific operating experience has shown that degradation has

occurred. For example, the applicant has identified the following: failed tendon wires, missing

3-19
or broken components found in the tendon hardware, degraded concrete in containment

structure, corroded containment liner, and corrosion of penetrations inside of containment.

These occurrences of degradation have been evaluated and corrective action has been taken.

The staff reviewed documented industry experience, specifically NRC Information Notice

(IN) 97-10, "Liner Plate Corrosion in Concrete Containments," and IN 99-10, "Degradation of

Prestressing Tendon Systems in Prestressed Concrete Containments." The staff determined

that the plant-specific operating experience described in the LRA is bounded by the

documented industry experience discussed in the INs.

Furthermore, the applicant also stated that during preparations for the 28th-year tendon

surveillance, it was discovered that the designated "common" or "control" tendons (i.e., those

tendons in each group that are tested every surveillance in order to establish the trend of

prestress force for that group) had been retensioned during each preceding surveillance.

Periodic retensioning of these tendons did not allow an accurate determination of prestress

force relaxation trends. New common tendons, which had not been previously retensioned,

were selected for the 28th-year surveillance. These tendons will be tested in future

surveillances to establish valid prestress force trends. The NRC was advised of this situation in

a letter from Mark P. Findlay (NMC) to Document Control Desk (NRC), dated June 29, 1999,

"Dockets 50-266 AND 50-301 Reselection of Control Tendons in the Point Beach Nuclear Plant,

Units 1 and 2."

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical staff to verify that the plant-specific operating experience did not reveal

any degradation not bounded by industry experience. On the basis of its review of the above

industry and plant-specific operating experience, the staff concluded that the ASME Code

Section Xi, Subsections IWE and IWL Inservice Inspection Program will adequately manage

the aging effects that are identified in the LRA for which this AMP is credited.

FSAR Supplement. In LRA Section Al 5.2.2, the applicant provided the FSAR supplement for

the ASME Code Section Xi, Subsections IWE and IWL Inservice Inspection Program. The staff

reviewed these sections and determined that the information in the FSAR supplement provides

an adequate summary of the program activities. The staff found these sections of the FSAR

supplement meet the requirements of 10 CFR 54.21 (d).

Conclusion. On the basis of its review and audit of the applicant's program, the staff found that

those program elements for which the applicant claimed consistency with the GALL Report are

consistent with the GALL Report. In addition, the staff reviewed the exceptions and the

associated justifications and determined that the AMP, with the exceptions, is adequate to

manage the aging effects for which it is credited. The staff found that the applicant had

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21(a)(3). The staff also reviewed the FSAR supplement for this AMP

and found that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

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3.0.3.2.3 ASME Section Xl, Subsection IWF Inservice Inspection Program

Summary of Technical Information in the ADolication. The applicant's ASME Code Section Xl,

Subsection IWF Inservice Inspection Program is described in LRA Section B2.1.3, UASME

Section Xl, Subsection IWF Inservice Inspection Program." The applicant stated that this is an

existing program that is consistent, with exceptions and enhancements, with GALL AMP XL.S3,

UASME Section Xl, Subsection IWF."

The applicant stated that the ASME Code Section Xl, Subsection IWF Inservice Inspection

Program, is credited for managing the aging effects for Class 1, 2, and 3 component supports.

The primary inspection method employed is visual examination. Criteria for acceptance and

corrective action are in accordance with ASME Code Section Xl, Subsection IWF. Degradation

that potentially compromises the function or load capacity of the supports, including bolting, is

identified for evaluation. Supports requiring corrective action are re-examined during the next

inspection period. The applicant stated that this program is in accordance with 10 CFR 50.55a

and NRC-approved code cases and relief requests. This program is credited by the Bolting

Integrity Program for the inspection of bolting and fasteners within the scope of ASME Code

Section Xi, Subsection IWF.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. Details of the staff's audit evaluation are documented in the

staff's audit and review report. Furthermore, the staff reviewed the exceptions and associated

justifications to determine whether the AMP, with the exceptions, remains adequate to manage

the aging effects for which it is credited.

LRA Section B2.1.3 states that the ASME Code Section Xl, Subsection IWF Inservice

Inspection Program is consistent with GALL AMP XI.S3, with exceptions. The ASME Code

Section Xi, Subsection IWF Inservice Inspection Program takes exception to the "scope of the

program" program element in that, (1) the program uses the ASME Code Section Xi, 98A00,

whereas GALL AMP XL.S3 references the ASME Code, 1989 through 1995 Editions with

Addenda through 1996, and (2) MC supports are not addressed.

The applicant stated that there are no MC supports within the scope of license renewal;

therefore, it is not necessary to list inspection criteria for MC support in this AMP. As

documented in the audit and review report, the staff reviewed the information provided in the

LRA and held discussions with the applicant's technical staff. The staff confirmed the absence

of MC falling within the scope of license renewal. On this basis, the staff found this exception

acceptable.-

The ASME Code Section Xi, Subsection IWF Inservice Inspection Program also takes

exception to the "scope of the program" and "detection of aging effect" program elements in

that the IWF-2420 successive inspection criteria have been modified to sequence the

examinations established in the previous inspection interval to be changed in a manner that

reduces scaffold, insulation, and radiation exposure.

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In its response to 01 B2.1, under the ASME Code, Section Xl, Subsections IWB, IWC, and

IWD, and Subsections IWE and IWL, by letter dated July 5, 2005, the applicant withdrew the

alternatives listed below. These alternatives affected exceptions initially credited under

Subsection IWF.

* Altering the Date of the Start of the Fourth Inspection Interval

* Use of ASME Code, Section Xi, 1998 Edition with Addenda through 2000

* Successive Inspections (Code Case N-624)

The applicant clarified in its letter that these alternatives are not exceptions to the GALL Report

as they are either administrative and did not affect aging management or the AMR aging effect

was managed by another aging management program cited in the LRA. The staff found each

of the bases identified in the applicant's RAI response acceptable and agreed that these

alternatives are not exceptions to the GALL Report. The staff found the withdrawal of these

alternatives acceptable. Further discussions on remaining exceptions related to Subsections

IWB, IWC, and IWD and Subsections IWE and IWL are documented in SER Sections 3.0.3.2.1

and 3.0.3.2.2, respectively.

In LRA Section B2.1.3, the applicant stated that its ASME Code Section Xl, Subsection IWF

Inservice Inspection Program is consistent with GALL AMP XI.S3, with enhancements. The

applicant stated that, for the "parameters monitored or inspected" program element,

enhancements include revising existing implementing documents to include cracks as

recordable conditions for component supports. The staff considered this type of enhancement

to be an administrative enhancement that does not require staff review.

Operating Experience. The staff reviewed the applicant's operating experience for the ASME

Code Section Xl, Subsection IWF Inservice Inspection Program. The applicant stated that it

performed a review of industry and plant-specific operating experience. IN 80-36 notified

utilities of the potential for SCC of high-strength component support bolts. High-strength (>150

ksi yield) component support bolting is used in pinned connections associated with the steam

generator (SG), reactor coolant pump, and reactor vessel supports and is loaded only in shear.

SCC of these bolts is not a concern because the bolts have no preload stress and are not

located in an aggressive environment.

The applicant also stated that the most common relevant condition discovered by the ASME

Code Section Xl, Subsection IWF Inservice Inspection Program has been loose fasteners in

supports. Loose fasteners are a maintenance issue rather than a sign of age-related

degradation. The applicant also stated that, to date, these examinations have been effective in

managing aging effects for ASME Code Class 1, 2, and 3 component supports.

Furthermore, the applicant stated that two pipe supports in the auxiliary feedwater pump room

were found with gaps between the baseplate and the concrete wall that exceeded the criteria

specified in plant procedures. A condition report was issued, and an operability determination

performed to evaluate the supports' capability to adequately transfer the design loads to the

building structure. The operability determination concluded that the support was operable and

that no further action was required; the condition report was closed. Additional information

regarding the high strength bolts inspection history is documented under RAI B2.1.4-3 of the

'parameters monitored or inspected" of the Bolting Integrity Program in SER Section 3.0.3.2.4.

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The staff reviewed the operating experience provided In the LRA and interviewed the

applicant's technical staff to verify that the plant-specific operating experience did not reveal

any degradation not bounded by industry experience. On the basis of its review of the above

industry and plant-specific operating experience, the staff concluded that the ASME Code

Section Xi, Subsection IWF Inservice Inspection Program will adequately manage the aging

effects that are identified in the LRA for which this AMP is credited.

FSAR SupDlement. In LRA Section Al 5.2.3, the applicant provided the FSAR supplement for

the ASME Code Section Xi, Subsection IWF Inservice Inspection Program. The staff reviewed

these sections and determined that the information in the FSAR supplement provides an

adequate summary of the program activities. The staff found these sections of the FSAR

supplement meet the requirements of 10 CFR 54.21 (d).

Conclusion. On the basis of its review and audit of the applicant's program, the staff found that

those program elements for which the applicant claimed consistency with the GALL Report are

consistent with the GALL Report. In addition, the staff reviewed the exceptions and the

associated justifications and determined that the AMP, with the exceptions, is adequate to

manage the aging effects for which it is credited. The staff found that the applicant had

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff also reviewed the FSAR supplement for this AMP

and found that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

3.0.3.2.4 Bolting Integrity Program

Summary of Technical Information in the Application. The applicant's Bolting Integrity Program

is described in LRA Section B2.1.4, "Bolting Integrity Program." The applicant stated that this is

an existing program that is consistent, with exceptions and enhancements, with GALL AMP

XI.M18, "Bolting Integrity."

The applicant stated that the Bolting Integrity Program is credited for managing the aging

effects associated with bolting through the performance of periodic inspections. The program

also includes repair/replacement controls for ASME Code Section Xi related bolting and generic

guidance regarding material selection, thread lubrication, and assembly of bolted joints. The

program considers the guidelines delineated in NUREG-1 339, "Resolution of Generic Safety

Issue 29: Bolting Degradation or Failure in Nuclear Power Plants," for a Bolting Integrity

Program; EPRI NP-5769, "Degradation and Failure of Bolting in Nuclear Plants," (with the

exceptions noted in NUREG-1 339) for safety-related bolting; and EPRI TR-1 04213, "Bolted

Joint Maintenance & Application Guide," for nonsafety-related bolting.

The Bolting Integrity Program credits seven separate AMPs for the inspection of bolting. The

seven AMPs are: (1) ASME Code Section Xi, Subsections IWB, IWC, and IWD Inservice

Inspection Program, (2) ASME Code Section Xl, Subsections IWE and IWL Inservice

Inspection Program, (3) ASME Code Section Xl, Subsection IWF Inservice Inspection Program,

(4) Systems Monitoring Program, (5) Structures Monitoring Program, (6) Reactor Vessel

Internals Program, and (7) Periodic Surveillance and Preventive Maintenance Program.

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Staff Evaluation. In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information

included in LRA Section B2.1.4 regarding the applicant's demonstration that the Bolting Integrity

Program will ensure that the effects of aging, as discussed above, will be adequately managed

so that the intended functions will be maintained consistent with the CLB throughout the period

of extended operation.

The staff reviewed the Bolting Integrity Program against the AMP elements found in the GALL

Report, SRP-LR Section A.1.2.3 and SRP-LR Table A.1-1, and focused on how the program

manages aging effects through the effective incorporation of 10 elements (i.e., program scope,

preventive actions, parameters monitored or inspected, detection of aging effects, monitoring

and trending, acceptance criteria, corrective actions, confirmation process, administrative

controls, and operating experience). The Bolting Integrity Program takes exceptions to the

following program elements: (1) scope of the program, (2) preventive actions, (4) detection of

aging effects, (5) monitoring and trending, and (6) acceptance criteria.

The applicant indicated that the corrective actions, confirmation process, and administrative

controls are part of the site-controlled quality assurance program. The staff's evaluation of the

quality assurance program is discussed in SER Section 3.0.4. The remaining seven elements

are discussed below.

LRA Section B2.1.4 states that the Bolting Integrity Program is consistent with GALL AMP

XL.M18, with enhancements. The applicant stated that, for the "parameters monitored or

inspected" program element, enhancements include revising existing implementing documents

to include specific inspections for the aging effects being managed by this program. The staff

considered this type of enhancement to be an administrative enhancement that does not

require staff review.

(1) Scope of the Program - The applicant stated that the Bolting Integrity Program covers all

bolting and fasteners within the scope of license renewal, including safety-related

bolting, bolting for Nuclear Steam Supply System (NSSS) component supports, bolting

for other pressure-retaining components, and structural bolting. The Bolting Integrity

Program manages the aging effects associated with bolting through the performance of

periodic inspections. The program also includes repair/replacement controls for ASME

Code Section XI-related bolting and generic guidance regarding thread lubrication and

assembly of bolted flanges.

The GALL Report recommendations and guidelines for a comprehensive Bolting

Integrity Program that encompasses all safety-related bolting are delineated in

NUREG-1 339. The applicant's program considers the guidelines delineated in

NUREG-1339 for a Bolting Integrity Program, EPRI report NP-5769 (with the exceptions

noted in NUREG-1 339) for safety-related bolting, and EPRI report TR-1 04213 for the

bolting. Due to the broad scope of the EPRI documents, the applicant indicated that the

Bolting Integrity Program uses them as reference information and guidance only. The

applicant's use of these documents is discussed in the preventive actions section below.

The staff confirmed that the "scope of the program" program element satisfies the

criterion defined in the GALL Report and SRP-LR Section A.1.2.3.1. The staff

concluded that this program attribute is acceptable.

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(2) Preventive Actions - The applicant stated that the program takes the following

exceptions to the GALL AMP XI.M1 8:

* In lieu of checking bolt torque and uniformity of gasket compression during the

initial inservice inspection (ISI) after assembly, these parameters may be

checked as part of maintenance activities.

* Enhancements to the existing plant implementation documents dealing with

bolted joints will be made to incorporate recommendations as deemed

appropriate based upon review of NUREG-1339, EPRI NP-5769, and EPRI

TR-1 04213.

Checking Bolt Toraue and Uniformity of Gasket Compression. As a preventive action,

the GALL Report indicates that initial ISI of bolting for pressure-retaining components

after assembly should include a check of the bolt torque and uniformity of the gasket

compression after assembly. The applicant indicated that these parameters may be

checked as part of maintenance activities, but the initial ISI would only include an

inspection for leakage from reactor coolant system (RCS) components.

The staff's review of LRA Section B2.1.4 identified areas in which additional information

was necessary to complete the review of the applicant's program elements. The

applicant responded to the staff's RAIs as discussed below.

RAI B2.1.4-1. In RAI B2.1.4-1, dated February 7, 2005, the staff requested the

applicant to describe the maintenance procedures that are used to check bolt torque

and uniformity of gasket compression. Additionally, the staff requested the applicant to

provide the frequency of the maintenance activity.

In its response, dated March 4, 2005, the applicant stated the following:

Maintenance Instruction (Ml) 32.1 provides generic guidance regarding bolt

torque values and uniform gasket compression on typical bolted joints and is

used in the development of the work control package if requirements are not

otherwise specified by drawings or equipment technical information. Note that

the majority of bolted joints at PBNP are designed to ensure the uniformity of

gasket compression by the use of metal-to-metal joints, either through the use of

a gasket crush ring or a gasket recess in the joint flange. The frequency of the

maintenance activity is dependant on the need to disassemble and reassemble

the joint as part of a corrective maintenance activity of the joint itself or to

support corrective or periodic maintenance of associated components.

Since bolt torque and uniformity of gasket compression are checked in accordance with

a plant maintenance instruction, the staff concluded that bolt torque and uniformity of

gasket compression do not need to be checked during initial ISI. The staff's concerns

described in RAI B2.1.4-1 are resolved.

NUREG-1339. EPRI NP-5769. and EPRI TR-104213. GALL AMP XI.M18 indicates that

it relies on recommendations for a comprehensive Bolting Integrity Program, as

delineated in NUREG-1 339, and industry recommendations, as delineated in the EPRI

3-25
NP-5769, with the exceptions noted in NUREG-1339 for safety-related bolting. The

GALL Report relies on industry recommendations for comprehensive bolting

maintenance, as delineated in the EPRI TR-104213 for pressure-retaining bolting and

structural bolting. The applicant indicated that enhancements to the existing plant

implementation documents dealing with bolted joints will be made to incorporate

recommendations as deemed appropriate based upon review of NUREG-1 339, EPRI

NP-5769, and EPRI TR-104213. The applicant has not identified exceptions to these

NUREG and EPRI documents.

RAI B2.1.4-2. In RAI B2.1.4-2, dated February 7, 2005, the staff requested the

applicant to provide specific exceptions to the program. The staff should be informed of,

and approve, specific exceptions to the bolting recommendations in these NUREG and

EPRI documents. The applicant must provide this information for staff review and

approval prior to issuance of the extended license. This was identified as open item (01)

B2.1.4-2.

The staff's concern was referred to the Region IlIl staff, who performed its AMR/AMP

onsite inspection during the weeks of March 7 and 21, 2005. In its response to

01 B2.1.4-2, by letter dated April 8, 2005, the applicant provided specific exceptions to

EPRI NP-5769. The applicant's discussion and the staff's evaluation are documented

below.

Thread Lubrication. The applicant stated that NMC does not utilize a single lubricant for

all bolting material on site because of multiple needs and vendor recommendations.

The use of thread lubricants is controlled via the use of Maintenance Instructions

(Ml) 32.1, 'Flange and Closure Bolting," and Ml 29.1, 'Use of Thread Lubricants and

Sealants." These documents have been reviewed and will be revised as necessary to

more clearly state that lubricants containing molybdenum disulfide should not be used

unless evaluated on a case-by-case basis with consideration given for the potential of

SCC.

EPRI NP-5769 recommends that utilities use a single lubricant for all bolting materials

onsite to facilitate control. Lubricants containing molybdenum disulfide are not

recommended, except on a case-by-case basis. The staff considers the use of multiple

lubricants acceptable because the use of lubricants is controlled through maintenance

procedures. The applicant's clarification of the use of molybdenum disulfide meets the

intent of the EPRI recommendation.

Locking Devices for Component Supports. The applicant stated that this section

describes design requirements for component support threaded fastener locking

devices and specifically precludes the use of disk or helical spring locking devices.

These requirements were derived from ASME Section III, Subsection NF. PBNP is not

an ASME Section III code of record plant and will not apply these specific requirements

but will continue to use locking devices per the design codes, standards, and

specifications applicable to PBNP.

The code of record for PBNP piping is ASA B31.1 - 1955 Edition for the RCS piping and

USAS B31.1 - 1967 Edition for other piping. B31.1 - 1967 Edition, Section 121.1.3,

'Hanger Adjustments,' and B31.1 - 1955 Edition, Section 605(f) contain a specific

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requirement for suitable locking devices on hanger screw thread (and equivalent)

adjustments. NMC will continue to comply with these code requirements for PBNP.

Bolt preload, as a technique for a locking device for threaded fasteners, is employed at

PBNP in certain applications. High strength bolting design and installation was in

accordance with AlSC-Specification for the Design, Fabrication, and Erection of

Structural Steel for Buildings, (April 1963). Section 1.23, "Fabrication," and specifically

Section 1.23.5, "Riveted and High Strength Bolted Construction-Assembling," details the

requirements for bolt tensioning and hence fastener locking. High strength structural

bolting at PBNP is in accordance with ASTM A325 and A490.

ASME Section III, Subsection NF - Supports, incorporates the requirements of high

strength bolting from the AISC specification. Even though PBNP is not an ASME

Section III designed plant for piping, PBNP meets the design requirements for

preloading for high strength fasteners as used in component support design and

installation.

Based on the clarification provided above, the staff found this acceptable.

Torguing Reguirements for Quenched and Tempered Bolting. The applicant stated that

the recommended torque values specified in Table 1-2 of the EPRI document were

derived from page 383 of the Crane Co. Catalogue No. 60 published in 1960, and

applies a +/- 10 percent tolerance on the torque values. NMC currently uses the

guidance provided in Ml 32.1 and Form PBF-9142, which contains information that is

derived from a more recent Crane Co. catalog and applies a +/- 5 percent tolerance on

the torque values. The torque values in the more recent guidance differ slightly from the

earlier information for the larger diameter bolting-material. The torque values in Ml 32.1

and Form PBF-9142 are used by maintenance personnel for flange and closure bolting

unless torque values are imposed by other documents such as drawings, applicable

specifications, or instruction manuals.

The staff considers the use of alternative torque values acceptable because they are

controlled by maintenance procedures and are derived from industrial standards.

Flanged Joints with Flexitallic Gaskets or Soft Rubber, or Other Pliable Gaskets. The

applicant stated that the first paragraph in this section of NP-5769 states that the torque

values specified in Table 1-2 are also recommended for soft, rubber, and other pliable

gaskets. At PBNP, NMC does not normally use bolt torque values as the controlling

factor for pressure-retaining joints that use rubber gasket material over the full face of

the joint (i.e., do not have a metal-to-metal interface to control compression) unless

specifically evaluated or recommended for the application. Use of the torque values

specified in Table 1-2 of Volume II of EPRI NP-5769 may result in over compression of

rubber gasket material. Appropriate tightening of closure bolts for pressure-retaining

joints that use full face rubber gasket material is controlled by verifying the evenness of

the gasket compression without over compressing the gasket material. This is similar to

the "skill-of-the-craft" guidance provided in Section 3.7.1 of EPRI TR-104213.

Based on the clarification provided above, the staff found this acceptable because the

applicant is using alternative industry guidance in EPRI TR-104213.

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Procedures and Personnel. The applicant stated that NP-5769 states that NDE

personnel performing or interpreting NDE, including visual examinations specified by

codes, are qualified to SNT-TC-1 A-1 975. PBNP uses NDE personnel qualified and

certified to later revisions of SNT-TC-1 A or ANSI/ASNT CP-1 89, which is more

restrictive than SNT-TC-1 A. This is discussed in the 1998 Edition through 2000

Addenda of ASME Section Xl, IWA-231 0. NMC will continue to follow the requirements

of 10 CFR 50.55a or request relief, as necessary for PBNP. The referenced section of

Volume II, Section 1 of EPRI-5769 invokes the application of latter editions of various

ASME Codes, including Section Xl.

Based on the clarification provided above, the staff found this acceptable because the

applicant will meet the requirements of 10 CFR 50.55a.

Re-Use of Bolting Material. The applicant stated that this section of NP-5769 states that

any bolt or nut tightened by the turn-of-nut method shall not be reused. NMC will clarify

this requirement to apply only to component support bolting installed in accordance with

AISC or similar design specifications in which the tum-of-nut method may result in the

bolting material being stressed beyond yield.

Based on the clarification provided above, the staff found this acceptable.

Non-ASME Section III Bolting Material. The applicant stated that PBNP is a B31.1 plant

and does not specify ASME Class IlIl requirements for non-ASME Class IlIl bolting. NMC

does however require a Certified Material Test Report (CMTR) or a Certificate of

Conformance (COC) for the procurement of all QA bolting material. Augmented quality

(AQ) bolting is procured to catalog description/part number or material specification and

is verified to meet those standards through generation of a purchase order to an

approved vendor; reviewing the vendor supplied packing lists, labeling and supplemental

documents; and by performing a visual examination consisting of part number

verification, marking verification and dimensional verification as applicable.

EPRI NP-5769 indicates that Non-ASME Section III Bolting Material should be procured

with a manufacture's certification that the material is in accordance with the material

specification, type, grade, or class, and heat-treated condition, as applicable. The staff

found that this clarification is consistent with the procurement requirements of EPRI

NP-5769 and, therefore, acceptable.

Hardness Test. The applicant stated that NMC does not perform hardness tests of

random samples of bolting material during receipt inspection at PBNP. With few

exceptions, (e.g., Hilti Quickbolts), safety-related bolting used at PBNP is provided with

a CMTR. NMC reviews the CMTR and confirms that either the hardness or actual

tensile or proof load test falls within the acceptable range for the material. Hardness,

tensile strength, and proof load information is not provided if the material is procured

only with a COC. NMC would only perform hardness tests if the provided information

was suspect based on site or industry operating experience.

EPRI NP-5769 recommends that the utility hardness test a random number of items

from each lot of safety-related fasteners, as part of the receipt or preinstallation

inspection. The hardness test is a check to ensure that the fasteners have not been

3-28
heat-treated to a hardness that is not within specification or that the alloying elements

(i.e. carbon) do not exceed specification. If hardness is too high, fasteners could be

susceptible to stress corrosion cracking. If the hardness is too low, the fasteners may

not meet minimum mechanical properties. This test should be performed prior to

installation to ensure the fasteners meet hardness specification requirements. This is

typically done by licensees as part of their incoming quality assurance program.

Subsequently, the staff indicated to the applicant that PBNP should meet the

recommendations for random hardness testing in EPRI NP-5769. In its response, dated

July 19, 2005, the applicant withdrew this exception and stated that PBNP will conduct

hardness testing of random samples of bolting materials as part of the receipt inspection

process as recommended in EPRI NP-5769 during the period of extended operation at

PBNP. Based on this clarification, the staff found this acceptable.

The staff evaluated the applicant's response to RAI B2.1.4-2 and its specific exceptions

to EPRI NP-5769 and found them acceptable. The staff's concern is resolved and,

therefore, 01 B2.1.4-2 is closed.

(3) Parameters Monitored or Inspected - The applicant stated that the inspection program

for high strength (2 150 ksi yield strength) bolting in NSSS component supports

associated with the SG, reactor coolant pump and reactor vessel supports would be

inspected and tested in accordance with ASME Code requirements; but would not be

inspected and tested in accordance with the additional recommendations in GALL AMP

XI.M18 for high strength bolts. GALL Report XI.M18 indicates that all high strength

bolting used in NSSS component supports should be inspected to the requirements for

ASME Code Class 1 components, examination category B-G-1. ASME Code Class 1

components, examination category B-G-1 requires all bolting to be volumetrically

examined. The ASME Code requires NSSS bolting to be visually examined (VT-3

examination); but does not require a volumetric examination of the bolting. The

applicant indicated that volumetric examinations of the high strength bolting in NSSS

component supports are not necessary because these bolts are not susceptible to SCC

because they are loaded only in shear, they have no preload and they are not located in

an aggressive environment.

RAI B2.1.4-3. In RAI B2.1.4-3, dated February 7, 2005, the staff requested the

applicant to provide data that demonstrate that the bolting, loaded within the maximum

shear stress, would not be susceptible to SCC. Additionally, the staff requested the

applicant to identify the inspection history for its bolts that demonstrate that they are not

susceptible to SCC.

In its response, dated March 4, 2005, the applicant stated the following:

A review of plant drawings and specifications for the supports of Class 1

components was performed to determine the design of the connection and bolt

preload requirements. A490 bolting/material is used in two types of applications

for the supports of Class 1 components. It functions as a bolt in bolted

connections and as a pin in pinned connections (bearing-type). The PBNP

support drawings detail the use of jam nuts in combination with the bolt nuts for

many of the pins and embedded anchor bolts. The use of jam nuts clearly

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signify that preload was to be excluded. The conclusion drawn is that bolt

preload was not intended and that the bolts were not placed in a state of high

tensile stress. As a point of reference, the AISC allowable working stress for

A490 fasteners is 54 ksi in tension and 32 ksi in shear (threads excluded from

shear plane). The bolted connections were most likely tightened (preloaded) in

accordance with AISC specifications.

Contaminants such as sulfates, fluorides, or chlorides can provide the necessary

environment for SCC. Materials respond differently to environmental (aqueous

mediums) and stress conditions. The general environment in a reactor

containment building is closely controlled to exclude sulfate,-fluoride, or chloride

contaminants. Moist environments and effects of boric acid corrosion are

avoided. In the past SCC in the presence of bolt lubricants has been a problem.

Molybdenum disuffide (MoS2) has experienced decomposition, resulting in the

introduction of H2S contaminants needed to promote SCC failure. NMC takes

care in the selection of lubricants to preclude lubricant-induced SCC.

Plant-specific operating experience history for the supports of Class 1

components is also important information. Currently, 1998 Edition with Addenda

through 2000 of ASME Code Section Xl is required to be implemented at PBNP.

Under Examination Category F-A, item number F1.40, the bolting on these

component supports are examined periodically. The inspection method is VT-3.

Personnel are trained and qualified in accordance with ANSI-ASNT CP-1 89

(IWA-231 0). This qualification requires written tests to prove the examiner has

the knowledge required for examinations and a practical test to ensure they

understand the components they are examining.

The requirement is to examine 100 percent of the supports. For components

other than piping, within a system of similar design, function, and service, the

supports of only one of the multiple components are required to be examined.

This would mean the supports of one RCP and one steam generator, and the

reactor pressure vessel (RPV), would be examined each ten-year interval. The

examination requirement includes all bolted connections to the component, to

the building structure, and any intervening elements. The acceptance standards

(IWF-341 0) state that any deformations or structural degradations of fasteners,

springs, clamps, or other support items, and missing, detached, or loosened

support items are unacceptable for continued service until repaired, replaced, or

accepted by evaluation or test. If the acceptance criteria cannot be met, then

additional examinations (IWF-2430) shall be performed. This would include the

immediately adjacent component supports and additional supports within the

system, equal in number and of the same type and function as those scheduled

for examination during the inspection period (periods usually include two

outages). This would require PBNP to look at the supports on the other RCP

and steam generator.

The Boric Acid Program also takes a critical look at bolting. Whenever boric acid

is found, the requirement is to look at the flow path of where the boric acid has

traveled. If boric acid is found on bolting, the boric acid will be removed and a

visual examination performed on the fasteners to determine if any degradation

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has occurred. NMC will follow plant procedures for repair or replacement if the

evaluation determines the bolting is not acceptable.

The inspection history results are reported in the applicant's response to RAI B2.1.4-3.

Since 1991, reactor coolant pump supports and SG supports have been inspected on

numerous occasions. No recordable indications have been observed. The Region IlIl

staff, on their AMRIAMP onsite inspection during the weeks of March 7 and 21, 2005,

will confirm that there were no failures of high strength bolts. This was identified as

confirmatory item (Cl) B2.1.4-3.

The inspection history for high strength bolts was verified by the Region IlIl staff, during

their AMR/AMP onsite inspection. Section D.1 of the DRS Aging Management

Inspection Report, dated May 2, 2005, states the following:

The inspectors requested specific searches of the plant specific operating

experience and verified that the applicant performed adequate historic reviews to

determine aging effects. The inspectors determined that the licensee did not

have any documented occurrences of failure in high strength structural bolting.

During plant walkdowns, the inspectors specifically looked for cases where

structural bolting appeared loose, missing or failed; no problems were identified.

Following submittal of the LRA, the licensee did identify two cases where

component bolts were replaced. In one case, the licensee discovered a

longitudinal crack in a reactor coolant pump seal package bolt. The licensee

replaced the bolt and sent the cracked bolt off for laboratory analysis. The crack

was determined to be a manufacturing defect and not related to aging

degradation. The second case was replacement of all the bolting on the Unit 2

pressurizer after indications were identified during the inservice inspection. The

indication disposition report and a subsequent corrective action procedure (CAP)

document analyzed the indications and determined that the majority of the

indications were minor, appeared most likely due to normal installation and

removal of the bolts, and did not affect the integrity of the bolting. However, one

bolt had two minor crack like" indications. The licensee did not determine the

cause of these indications; however as the bolts were replaced and no

pressurizer leakage had occurred during the previous operating cycle, the

inspectors concluded that the licensee's Inservice inspection program had

adequately addressed the issue.

The staff found this acceptable since the inspectors confirmed that the applicant did not

have any documented occurrences of failure in high strength structural bolting. The

staff's concern is resolved and, therefore, Cl B2.1.4-3 is closed.

Since the applicant has not observed any degradation of bolting using ASME Code

inspection methods and frequency, the staff concluded that the applicant demonstrated

that the bolting has not been susceptible to SCC, that volumetric examination of the high

strength bolting in NSSS component supports is not necessary, and that the applicant's

program will be successful in monitoring degradation of high strength component

support bolting during the period of extended operation.

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The staff confirmed that the "parameters monitored or inspected program" element

satisfies the criterion defined in the GALL Report and SRP-LR Section A.1.2.3.2. The

staff concluded that this program attribute is acceptable.

(4) Detection of Aging Effects - The applicant stated that this element is consistent with

GALL Report XL.M18, except that high strength NSSS component support bolting would

not be inspected and tested in accordance with the recommendations in GALL

Report Xl.M1 8 and that structural bolting would not be subjected to the augmented

testing discussed in GALL Report Xi.M1 8.

In addition, the applicant indicated that PBNP uses the ASME Code Section Xl 98A00

instead of the ASME Code 95A96 referenced in GALL Report XI.M18. Since

10 CFR 50.55a endorses the ASME Code 98A00, Section Xl, the staff concluded that it

is acceptable to use the ASME Code 98A00, Section Xl.

With respect to the discussion covering the structural bolting and fasteners under the

"detection of aging effects" program element, the applicant elected to take exceptions to

the corresponding NUREG-1 801 AMP element and stated that, "Components that are

within the scope of license renewal and are not within the scope of the ASME

Code Section Xl ISI programs are visually inspected for signs of degradation and are

only inspected more closely when signs of degradation are present." The applicant

further indicated that, "PBNP does not plan to perform additional tests such as hammer

tests, in situ ultrasonic tests, or proof tests by tension or torquing," without providing a

plant-specific basis for the exceptions taken.

RAI B2.1.4-6. In RAI B2.1.4-6, dated February 23, 2005, the staff requested the

applicant to provide the following information:

* In the context of PBNP's implementation of its aging management of in-scope

structural bolting and fasteners, explain with examples the definition or meaning

of the phrase: "when signs of degradation are present."

* List PBNP's basis for taking the above stated exceptions to the corresponding

NUREG-1801 AMP element, including a discussion of past plant-specific

operating experience and/or inspection data-based justifications.

* Given a discovery or an identification of a credible or a significant degradation of

in-scope structural bolting or fastener(s) meeting the definition of the first bullet

above, please explain the specific steps that would be taken and a list of

applicable plant-specific program(s) or procedures that will be used, per PBNP's

current AMP(s) for structural bolting and fasteners, to dispose in a timely manner

the identified degraded event.

In its response, dated March 15, 2005, the applicant stated that the Bolting Integrity

Program credits the Structures Monitoring Program and the ASME Code IWF Program

for the inspection of structural bolting. As described in LRA Section B2.1.20 under

"Parameters Monitored or Inspected," the types of degradation addressed by the visual

inspection include corrosion, rust, looseness, physical damage or deformation, lack of

full thread engagement, missing or out of place parts, and improper washers. The

applicant indicated that visual inspection is considered adequate to detect the types of

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degradation. These visual inspections apply to ASME Code (IWF) and non-ASME

Code structural bolting. As discussed in the applicant's clarification to RAI B.2.1.4-3 in

its letter dated March 4, 2005, PBNP has not identified any high strength structural

bolting susceptible to cracking. There have been no incidents of loss of intended

function of a component or system due to structural bolting degradation, and the

Structures Monitoring Program requires that significant degradation of structural bolting will be documented and entered into the PBNP corrective action program. As part of the

corrective action program process, degradation noted in these inspections will be

evaluated, and appropriate actions relative to the significance of the degradation will be

taken. Appropriate actions may include replacement, increased monitoring, or both.

The staff found the above response acceptable. The applicant (1) adequately explained

key signs of degradation in structural bolting, (2) indicated that there have been no

incidents of loss of intended function of a component or system due to structural bolting

degradation, (3) asserted, based on its operating experience, that performing visual

inspection is adequate to detect the types of degradation described above, and

(4) confirmed that its Structures Monitoring Program requires that significant

degradation of structural bolting will be documented and entered into the corrective

action program. As part of the corrective action program process, degradation noted in

these inspections will be evaluated, and appropriate actions relative to the significance

of the degradation will be taken. Therefore, the staff's concerns described in

RAI B2.1.4-6 are resolved.

The staff confirmed that the "detection of aging effects" program element satisfies the

criterion defined in the GALL Report and SRP-LR Section A.1.2.3.4. The staff

concluded that this program attribute is acceptable.

(5) Monitoring and Trending - The applicant stated that this element is consistent with GALL

Report XI.M1 8, except that the frequency of inspection of leaking pressure-retaining

components (not covered by ASME Code Section Xl) will not be in accordance with

GALL Report XI.M18. GALL Report XI.M1 indicates that these components should be

inspected daily. If they have leaks and if the leak rate does not increase, the inspection

frequency may be decreased to weekly or biweekly. The applicant indicated that the

frequency of inspection of leaking pressure-retaining non-ASME Code components will

be in accordance with the plant maintenance and/or corrective action process.

RAI B2.1.44. In RAI B2.1.4-4, dated February 7,2005, the staff requested the

applicant to identify how the plant maintenance and/or the corrective' action program

determines the frequency of inspection of these components. Additionally, the staff

requested the applicant to identify if any of these components haveleverriost their

intended function prior to repair. -- I

In its response, dated March 4, 2005, the applicant stated the following ;i

Documentation of leaking components is done via the corrective actioripr cess

or the corrective maintenance process. All corrective action Anri corrective

maintenance requests that have the potential to affect equipment operability are

reviewed by a Senior Reactor Operator. The condition is evaluated and the

appropriate actions relative to the significance of the condition are taken. The

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appropriate actions may include an expeditious repair, scheduled future repair

with periodic monitoring until the repair is completed, scheduled future repair with

no periodic monitoring, or no specific actions. Significant increases in leakage

would most likely be noted via operator rounds during normal plant operations

and/or observation of reduction of inventory in closed systems or increased flows

in various drainage systems. As noted in Section B2.1.4 of the license renewal

application, a review of plant-specific operating experience identified no

instances of loss of intended function of a component or system due to fastener

degradation.

The staff agreed that the frequency of inspection of non-ASME Code bolting should be

in accordance with the applicant's corrective action process or the corrective

maintenance process because this program has proven successful. The staff's

concerns described in RAI B2.1.4-4 are resolved.

The staff confirmed that the umonitoring and trending" program element satisfies the

criteria defined in the GALL Report and SRP-LR Section A.1.2.3.5. The staff concluded

that this program attribute is acceptable.

(6) Acceptance Criteria - The applicant stated that this element meets the intent of the

corresponding element in GALL Report XI.M1 8. The applicant indicated that cracks in

component support bolting will be repaired when scheduled as part of the plant

maintenance and/or corrective action process. GALL Report XI.M1 8 indicates that

cracked bolts in component supports should be replaced immediately.

RAI B2.1.4-5. In RAI B2.1.4-5, dated February 7, 2005, the staff requested the

applicant to identify how the plant maintenance and/or corrective action program

determines when cracked component support bolting is replaced. Additionally, the staff

requested the applicant to identify if these components have ever lost their intended

function prior to repair.

In its response, dated March 4, 2005, the applicant stated the following:

The corrective action process is used upon discovery of cracked bolting in a

support that is in-scope in accordance with 10 CFR 54.4. As a result an

immediate operability determination for cracked support bolting is made by a

Senior Reactor Operator. As part of this operability determination an Operability

Recommendation can be requested from Engineering to further document the

support's functionality and operability. This operability determination process is

used for any corrective action or corrective maintenance documented

degradation that has the potential to affect equipment operability. The corrective

action process will ensure the appropriate response including shutdown of

operating units if necessary to comply with PBNP Technical Specifications, other

CLB requirements or to establish the conditions necessary to allow the repair.

The degradation documented by the corrective action process for an operable

support with a cracked bolt will be evaluated and appropriate priority set for

repair or replacement. In all cases, the appropriate response for cracked

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support bolts is to initiate actions in accordance with PBNP's corrective action

process, which includes corrective maintenance.

As noted in Section B2.1.4 of the license renewal application, a review of

plant-specific operating experience identified no instances of loss of intended

function of a component or system due to fastener degradation.

The staff agreed that the plant maintenance and/or corrective action process is

expected to be adequate for scheduling the repair of cracked component support bolting

because this process has been proven successful. The staff's concerns described in

RAI B2.1.4-5 are resolved.

The staff confirmed that the "acceptance criteria" program element satisfies the criteria

defined in the GALL Report and SRP-LR Section A.1.2.3.6. The staff concluded that

this program attribute is acceptable.

(10) Operating Experience - The applicant stated that a review of industry operating

experience revealed numerous instances of primary pressure boundary degradation.

There have been various NRC communications including information notices, bulletins,

and generic letters on bolting degradation. Most instances of degradation fall into two

categories: (1) boric acid corrosion caused by leakage at mechanical joints; and (2)

degradation of high strength bolting caused by stress corrosion cracking. General

corrosion of bolting and fasteners has also occurred for structural bolting located in a

humid environment.

The applicant stated that plant-specific operating experience includes boric acid

wastage on one body-to-bonnet check valve stud. General corrosion was also found on

structural steel bolting. There were also a few instances of improper bolting material

and torque values being used. There were no incidents of loss of intended function of a

component or system due to fastener degradation.

Furthermore, the applicant stated that a review of NRC inspection reports, quality

assurance (QA) audit/surveillance reports,- and self-assessments, since 1999, revealed

no issues or findings that could impact the effectiveness of the Bolting Integrity Program. As additional operating experience is obtained, lessons learned may be used

to adjust this program.

During the audit, the staff reviewed the operating experience provided in the LRA and

interviewed the applicant's technical staff to verify that the plant-specific operating

experience did not reveal any degradation not bounded by industry experience.

On the basis of its review of the above industry and plant-specific operating experience,

the staff concluded that the Bolting Integrity Program will adequately manage the aging

effects that are identified in the LRA for which this AMP is credited.

The staff confirmed that the "operating experience" program element satisfies the

criteria defined in the GALL Report and SRP-LR Section A.1.2.3.10. The staff

concluded that this program attribute Is acceptable.

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FSAR SuDplement. In LRA Section Al 5.2.4, the applicant provided the FSAR supplement for

the Bolting Integrity 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 found this section of the FSAR supplement meet the requirements 10 CFR 54.21 (d).

Conclusion. On the basis of its review, the above discussed RAI responses, and its audit of the

applicant's program, the staff found that those program elements for which the applicant

claimed consistency with the GALL Report are consistent with the GALL Report. In addition,

the staff reviewed the exceptions and the associated justifications and determined that the

AMP, with the exceptions, is adequate to manage the aging effects for which it is credited. The

staff found that the applicant had demonstrated that the effects of aging will be adequately

managed so that the intended functions will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the

FSAR supplement for this AMP and found that it provides an adequate summary description of

the program, as required by 10 CFR 54.21 (d).

3.0.3.2.5 Boraflex Monitoring Program

Summary of Technical Information in the A12Dlication. The applicant's Boraflex Monitoring

Program is described in LRA Section B2.1.5, "Boraflex Monitoring Program." The applicant

stated that this is an existing program. As modified by letter dated April 1, 2005, the applicant

stated that the program is consistent, with enhancements, with GALL AMP XI.M22, 'Boraflex

Monitoring."

The applicant stated that the Boraflex Monitoring Program is credited for managing the aging

effects of a reduction of neutron absorption capabilities due to a change in material properties

(i.e., shrinkage, gap formation, and boron dissolution) resulting from gamma irradiation and a

convective aqueous environment for the Boraflex material in the spent fuel racks. This program

provides for blackness testing and areal density measurements of the Boraflex material in the

spent fuel storage racks to confirm the in-service Boraflex performance. In addition, the

applicant stated that tracking of the spent fuel pool (SFP) silica levels provides a qualitative

indication of boron carbide loss. Neutron attenuation or blackness testing will be performed to

determine gap formation, while areal density measurements will be used to ascertain the

physical loss of boron carbide. Monitoring by analysis of criticality will also be performed to

assure that the required 5 percent subcriticality margin is maintained. Based on the results of

these inspections and analysis, the applicant stated that appropriate measures will be taken to

ensure the Boraflex will continue to perform its intended function. This program addresses the

concerns described in NRC Generic Letter (GL) 96-04,"Boraflex Degradation in Spent Fuel Pool

Storage Racks."

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. Details of the staff's audit evaluation are documented in the

staff's audit and review report. Furthermore, the staff reviewed the exceptions and associated

justifications to determine whether the AMP, with the exceptions, remains adequate to manage

the aging effects for which it is credited.

In LRA Section B2.1.5, the applicant stated that its Boraflex Monitoring Program is consistent

with GALL AMP XL.M22, with exceptions. The Boraflex Monitoring Program takes exception to

the "detection of aging effect" program element such that for certain accelerated samples tests,

3-36
the applicant performs these tests at a minimum frequency of five years. GALL AMP XI.M22

recommends that certain accelerated samples be tested every two years.

The applicant stated that tests are conducted as follows: Two SFP storage locations had

received freshly discharged spent fuel assemblies each refueling for approximately 9 years,

which caused accelerated cumulative exposure levels to the bordering Boraflex panels. Four of

these panels are tested during each scheduled surveillance. The results of the Boraflex areal

density testing and Boraflex panel blackness testing are evaluated as part of the Boraflex

Monitoring Program to determine if a change in test frequency or methodology is warranted.

As documented in the audit and review report, the applicant clarified the lack of accelerated

individual sample testing. The applicant stated that in April 1989, PBNP submitted a

surveillance program to the NRC, which was approved in February 1990, establishing

blackness testing on 10 full-length Boraflex panels. Four of the panels included accelerated

exposure, having received freshly discharged fuel assemblies during the previous 9 years,

thereby receiving an accelerated gamma dose of 1 .5E10 rads, which is equivalent to that

received by the average panel in 30 years. Subsequent Boraflex panel blackness testing has

been performed and completed in August 1991, September 1996, and August 2001.

PBNP's CLB is such that the plant does perform testing of accelerated samples"; however, as

noted above, a number of full-length panels are subjected to accelerated exposure.

The GALL Report states that the results based on test coupons have been found to be

unreliable in determining the degree to which the actual Boraflex panels have been degraded.

The staff believes that this indicates that the accelerated samples are of limited value to an

AMP. Based on this statement and on the applicant's testing of intentionally high exposure

full-length panels, the staff concluded that testing of accelerated samples" is not required to

provide reasonable assurance that aging effects will be appropriately managed in light of the

blackness testing of full-length high-flux Boraflex panels during the period of extended

operation. The staff further concluded that using the above exceptions is acceptable and

ensures that the effects of aging will be managed in such a way that the intended functions of

the affected SCs will be maintained consistent with the CLB for the period of extended

operation.

In LRA Section B2.1.5, the applicant stated that Its Boraflex Monitoring Program is consistent

with GALL AMP XL.M22, with enhancements. The applicant stated that, for the "parameters

monitored or inspected" and "detection of aging effect" program elements, enhancements

include creation of (1) a new procedure to perform and control Boraflex areal density and

blackness testing and (2) a new procedure for trending and analysis of the results of the SFP

silica sampling by using the EPRI RACKLIFE predictive code or its equivalent, and

determination of panels with "accelerated" exposure during the period of extended operation.

The staff considered these types of enhancements to be administrative enhancements that do

not require staff review.

The applicant discusses its time-limited aging analyses (TLAA) for the spent fuel storage rack

boraflex in LRA Section 4.6. In its TLAA analysis, the applicant committed to perform areal

density and blackness tests on certain accelerated Boraflex panels during the period of

extended operation once every 2 years. The staff's evaluation of this TLAA is documented in

SER Section 4.6.

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Operating Experience. The staff reviewed the applicant's operating experience for the Boraflex

Monitoring Program.

The applicant stated that experience with Boraflex panels indicates that coupon surveillance

programs are not reliable. Therefore, Boraflex integrity is measured and correlated, through a

predictive code, with the silica levels in the pool water during the period of extended operation.

The applicant stated that these actions provide reasonable assurance that degradation of

Boraflex sheets is adequately monitored so that appropriate actions can be taken in a timely

manner i significant loss of neutron-absorbing capability is occurring.

The applicant also stated that the latest inspection of the SFP Boraflex panels was conducted in

August 2001. The results of the blackness test indicated that for the first time since the'

Boraflex panels have been inspected, gaps have been found in 27 panels ranging from 0.8 inch

to 3.4 inches. The gaps appear to be randomly distributed along the vertical length of the

Boraflex panels. A condition report was issued to monitor the condition of the Boraflex in the

SFP.

The applicant's discussion of operating experience included a review of NRC inspection reports,

QA audit, surveillance reports, and self-assessments since 1999, which revealed no issues or

findings other than those described above that could impact the effectiveness of the Boraflex

Monitoring Program.

The staff reviewed the operating experience provided in the LRA, interviewed the applicant's

technical staff, and verified that the plant-specific operating experience did not reveal any

degradation not bounded by industry experience. The staff found that the applicant's program

is consistent with industry expectations. On the basis of its review of the above industry and

plant-specific operating experience, the staff concluded that the Boraflex Monitoring Program

will adequately manage the aging effects that are identified in the LRA for which this AMP is

credited.

FSAR Supplement. In LRA Section Al 5.2.5, the applicant provided the FSAR supplement for

the Boraflex Monitoring Program. The staff reviewed these sections and determined that the

information in the FSAR supplement provides an adequate summary of the program activities.

The staff found these sections of the FSAR supplement meet the requirements of

10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant's program, the staff found that

those program elements for which the applicant claimed consistency with the GALL Report are

consistent with the GALL Report. The staff found that the applicant had demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3). The staff also reviewed the FSAR supplement for this AMP and found that

it provides an adequate summary description of the program, as required by 10 CFR 54.21 (d).

3.0.3.2.6 Boric Acid Corrosion Program

Summary of Technical Information in the Agplication. The applicant's Boric Acid Corrosion

Program is described in LRA Section B2.1.6 "Boric Acid Corrosion Program." In the LRA, the

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applicant stated that this is an existing program that is consistent, with enhancements, with

GALL AMP XI.M1 0, "Boric Acid Corrosion."

In LRA Section B2.1.6, the applicant stated that the Boric Acid Corrosion Program manages

aging effects for SSCs as a result of borated water leakage. The program requires periodic

visual inspection of systems that contain borated water for evidence of -leakage or accumulation

of dried boric acid. The program includes provisions for (a) determination of the principal

location or source of the leakage, (b) examination requirements and procedures for locating

small leaks, and (c) evaluations, and/or corrective actions to ensure that borated water leakage

does not lead to degradation of the leakage source as well as other SSCs exposed to the

leakage, including mechanical, structural, and electrical items. The applicant stated that this

program complies with PBNP's response to GL 88-05. This program credits the Systems

Monitoring Program for the visual inspection of other SSCs that do not contain borated water,

but which may be subject to the degrading effects of any borated water leakage.

Staff Evaluation. In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information

included in LRA Section B2.1.6, regarding the applicant's demonstration that the Boric Acid

Corrosion Program will ensure that the effects of aging, as discussed above, will be adequately

managed so that the intended functions will be maintained consistent with the CLB throughout

the period of extended operation.

The staff reviewed the Boric Acid Corrosion Program against the AMP elements found in the

GALL Report, SRP-LR Section A.1.2.3, and SRP-LR Table A.1-1 and focused on how the

program manages aging effects through the effective incorporation of 10 elements (ie.,

program scope, preventive actions, parameters monitored or inspected, detection of aging

effects, monitoring and trending, acceptance criteria, corrective actions, confirmation process,

administrative controls, and operating experience).

The applicant indicated that the corrective actions, confirmation process, and administrative

controls are part of the site-controlled quality assurance program. The staff's evaluation of the

quality assurance program is discussed in SER Section 3.0.4. The remaining

seven elements are discussed below.

LRA Section B2.1.6 states that the Boric Acid Corrosion Program is consistent with the GALL

Report, with enhancements. The applicant stated that procedures will be revised and/or

developed to identify susceptible components upon which borated water may have leaked and

ensure they are inspected for degradation. The staff considered this type of enhancement to

be an administrative enhancement that does not require staff review.

(1) Scope of the Program - The applicant stated that the Boric Acid Corrosion Program

includes any carbon steel, low-alloy steel, or cast iron structures or components, and

electrical components, on which borated water may leak. The program adheres to

GL 88-05. It includes (1) determination of the leakage source, (2) examination

requirements and procedures for locating small leaks, and (3) evaluations and/or

corrective actions.

NRC Bulletins 2002-01, 2003-02, and NRC Order EA-03-009 provide documentation of

reported industry experience concerning degradation of ASME Code Class 1 nickel-alloy

partial-penetration welds, including those used to join the upper vessel head penetration

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nozzles to the upper reactor vessel (RV) heads of pressurized water reactors (PWRs)

and those used to join the bottom-mounted instrumentation (BMI) nozzles to the lower

RV heads of PWRs. The staff requested clarification regarding the list of components

that are within the scope of the Boric Acid Corrosion Program and the process the

applicant uses to augment the list of components within the scope of the AMP based on

pertinent industry experience. The staff RAI is addressed under Operating Experience.

The staff confirmed that the "scope of the program" program element satisfies the

criterion defined in the GALL Report and SRP-LR Section A.1.2.3.1. The staff

concluded that this program attribute is acceptable.

(2) Preventive Actions - The applicant stated that the preventive actions are limited to

improving maintenance practices such as revising the valve packing program to improve

packing techniques, performance of pre-outage walkdowns to identify those

components that may require corrective maintenance, and monitoring of locations where

potential leakage could occur. Timely repair of detected leakage prevents or mitigates

boric acid corrosion.

The staff confirmed that the preventive actions" program element satisfies the criterion

defined in the GALL Report and SRP-LR Section A. 1.2.3.2. The staff concluded that

this program attribute is acceptable.

(3) Parameters Monitored or Inspected - The applicant stated that visual inspections are

conducted to monitor the effects of boric acid corrosion on the intended function(s) of an

affected structure or component. Borated water leakage results in deposits of white

boric acid crystals and the presence of moisture that can be observed by visual

inspections during system walkdowns.

The staff confirmed that the "parameters monitored or inspected" program element

satisfies the criterion defined in the GALL Report and SRP-LR Section A.1.2.3.3. Visual

inspections are expected to ensure that borated water leaks are properly managed. The

staff concluded that this program attribute is acceptable.

(4) Detection of Aging Effects - The applicant stated that degradation of components due to

boric acid corrosion cannot occur without borated water leakage. Visual inspections are

frequently conducted to identify necessary repairs and minimize the potential of a leak

not being discovered and developing into a larger leak. The applicant also stated that

evaluations are conducted when leaks are detected.

This program also credits the Systems Monitoring Program for the visual inspection of

other SSC that do not contain borated water, but which may be subject to the degrading

effects of any borated water leakage.

The staff confirmed that the detection of aging effects" program element satisfies the

criterion defined in the GALL Report and SRP-LR Section A.1.2.3.4. The staff

concluded that this program attribute is acceptable.

(5) Monitoring and Trending - The applicant stated that monitoring and trending relies on

visual inspections conducted during normal plant operation and when the plant is

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shutdown for refueling. The program follows the guidelines In GL 88-05 and provides

for timely detection of leakage by observance of boric acid-crystal deposits during plant

walkdowns and maintenance.

The staff confirmed that the "monitoring and trending" program element satisfies the

criteria defined in the GALL Report and SRP-LR Section A.1.2.3.5. Trending of

inspection results will be performed and will enhance the applicant's ability to detect

aging effects before there is a loss of intended function. The staff concluded that this

program attribute is acceptable.

(6) Acceptance Criteria - The applicant stated that plant procedures provide recording,

evaluation, and acceptance criteria if any leakage of borated water is noted.

The staff confirmed that the uacceptance criteria" program element satisfies the criteria

defined in the GALL Report and SRP-LR Section A.1.2.3.6. Any anomalous indications

that are signs of degradation will be evaluated by an engineer to determine material

degradation. If found unacceptable, corrective measures will be implemented. The staff

concluded that this program attribute is acceptable.

(10) Operating Experience - The applicant stated that industry operating experience clearly

indicates that borated water leaking from the reactor coolant system can cause

significant corrosion damage to carbon steel reactor coolant pressure boundary

components.

The applicant stated that a review of plant operating experience indicates that numerous

work orders, condition reports/action requests, and several applicant event reports have

been issued as a result of the Boric Acid Corrosion Program discovering borated water

leaks and corrosion of components due to borated water leakage. A large percentage

of the work orders and condition reports/action requests initiated described dried boric

acid crystal deposits either on the component from which it leaked or on the floor below

the leaking component. Occasionally, dried boric acid crystals were found on

components located below the leaking component. Many of the work orders initiated to

repair and/or investigate evidence of borated water leakage, or both, were a result of

performing system walkdowns during pressure testing.

Furthermore, the applicant stated that a review of NRC inspection reports, QA

audit/surveillance reports, and self-assessments since 1999 was performed. Several

enhancements were made to the PBNP GL 88-05 Boric Acid Control Program as a

result of an action request initiated by the nuclear oversight group. These

enhancements included consolidation of the program requirements into one document,

assignment of program ownership, and the addition of program references to various

implementing documents. Completion of these enhancements was tracked via the

corrective action program. No other issues or findings that could impact the

effectiveness of the Boric Acid Corrosion Program were identified. As additional

operating experience is obtained, lessons learned may be used to adjust this program.

NUREG/CR-5576, "Survey of Boric Acid Corrosion of Carbon Steel Compbnents in

Nuclear Plants," dated January 1990, summarizes borated water leakage :and boric acid

corrosion events that occurred in the industry prior to 1990.

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Recent industry operating experience shows how severe corrosion damage to the RV

head at Davis-Besse and cracking and leakage on the RV BMI penetrations at South

Texas resulted in industry attention to ensuring the implementation of an effective Boric

Acid Corrosion Program.

Industry experience has demonstrated that the bimetallic partial penetration welds

fabricated using Alloy 82/182 weld material in the upper RV head penetration nozzles

may be susceptible to PWSCC that could induce leakage of the borated reactor coolant

over time. In addition, the industry experience summarized in NRC Bulletin 2003-02 has

demonstrated that the BMI nozzles of PWR-designed light-water reactors may be

susceptible to PWSCC that could induce reactor coolant leakage.

The staff's review of LRA Section B2.1.6 identified an area in which additional

information was necessary to complete the review of the applicant's program elements.

The applicant responded to the staff's RAI as discussed below.

RAI B2.1.6-1. In RAI B2.1.6-1, dated November 17,2004, the staff requested the

applicant to submit a discussion on how the NMC responses to NRC's orders and

bulletins below have been used to update the component list locations and visual

inspections within the scope of the Boric Acid Corrosion Program:

* NRC Bulletin 2002-01, dated March 29 and May 16, 2002,

* NRC's RAls on Bulletin 2002-01, dated January 17,2003,

* NRC Bulletin 2003-02, dated September 19, 2003,

* NRC Order EA-03-009, dated March 3, April 11, and April 18, 2003, and

* NRC Bulletin 2004-01, dated May 28,2004

If the responses were used to supplement the scope of the Boric Acid Corrosion

Program or other AMPs, the staff requested the applicant to identify the component

locations that had been added to the scope of the program and to clarify the type of

visual examinations that will be implemented on those components within the current

scope of the program.

In its response, dated January 25, 2005, the applicant confirmed that (1) there are no

Alloy 82/182/600 materials in the Units 1 and 2 pressurizers; and (2) industry experience

from boric acid corrosion has been incorporated into the Boric Acid Corrosion AMP, in

the Reactor Coolant System Alloy 600 Inspection AMP, or both. In addition, the Units 1

and 2 RPV heads were scheduled to be replaced in 2005.

On the basis of its review and RAI response described above, the staff concluded that

the Boric Acid Corrosion Program will adequately manage the aging effects that have

been observed at the applicant's plant.

The staff confirmed that the "operating experience" program element satisfies the

criteria defined in the GALL Report and SRP-LR Section A.1.2.3.10. The staff

concluded that this program attribute is acceptable.

FSAR SupDlement. In LRA Section Al5.2.6, the applicant provided its FSAR supplement for

the Boric Acid Corrosion Program. The applicant summarizes that the program requires

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periodic visual inspection of systems that contain borated water for evidence of leakage or

accumulations of dried boric acid. It includes provisions for (1) determination of the principal

location or source of the leakage, (2) examination requirements and procedures for locating

small leaks, and (3) evaluations, corrective actions, or both, to ensure that borated water

leakage does not lead to degradation of the leakage source as well as other SSCs exposed to

the leakage, including mechanical, structural, and electrical items such as bolts, fasteners,

piping, cable, cable trays, and electrical connectors that could cause the loss of intended

function(s).

The staff reviewed the FSAR supplement and concluded that it provides an adequate summary

of the program activities, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its review, RAI response, and audit of the applicant's program, the

staff found that those program elements for which the applicant claimed consistency with the

GALL Report are consistent with the GALL Report. The staff found that the applicant had

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff also reviewed the FSAR supplement for this AMP

and found that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.0.3.2.7 Buried Services Monitoring Program

Summary of Technical Information in the ADDlication. The applicant's Buried Services

Monitoring Program is described in LRA Section B2.1.7, "Buried Services Monitoring Program."

In the LRA, the applicant stated that this is a new program that is consistent, with

enhancements, with GALL AMP XI.M34, "Buried Piping and Tank Inspection."

In LRA Section B2.1.7, the applicant stated that the Buried Services Monitoring Program

manages aging effects on the external surfaces of carbon steel, low-alloy steel, and cast iron

buried components. The applicant indicated that the Buried Services Monitoring Program is

consistent with GALL AMP XI.M34, "Buried Piping and Tank Inspection." This program

includes (1) preventive measures, and (2) visual inspections of external surfaces of buried

components for evidence of coating damage and substrate degradation to manage the effects

of aging. The program scope manages aging effects for components in the following systems

and structures: Emergency Power, Service Water, and Fire Protection.

The applicant indicated that enhancements to the program will include the creation of those

documents needed to implement the requirements of the program for SSCs within the program

scope. Enhancements are scheduled for completion prior to the period of extended operation.

Staff Evaluation. In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information

included in LRA Section B2.1.7, regarding the applicant's demonstration of the Buried Services

Monitoring Program to ensure that the effects of aging, as discussed above, will be adequately

managed so that the intended functions will be maintained consistent with the CLB throughout

the period of extended operation.

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In LRA Section B.2.1.7, the applicant described its AMP to manage loss of material due to

corrosion from external environments for buried piping and tanks in the scope of license

renewal. The LRA stated that this AMP is consistent with GALL AMP XL.M34, "Buried Piping

and Tanks Inspection," with enhancements necessary to ensure program documentation

reflects the GALL recommendations. The applicant indicated that the program includes

preventive measures to mitigate degradation (e.g., external coatings and wrappings) and visual

inspections of the external surfaces of buried carbon steel, cast iron, and low-alloy steel

components (e.g., piping, tanks) for evidence of coating damage and substrate degradation.

The applicant intends to perform inspections based on plant operating experience and

opportunities for inspection associated with plant maintenance. The applicant stated that

components are coated pursuant to industry practice prior to installation and that the coatings

and wrappings would be visually examined for signs of degradation which may be indicative of

a loss of material. The applicant's proposed program will rely on an inspection periodicity

based on operating experience and on inspections of opportunity. In addition, the applicant

indicated that inspection results would be evaluated and if necessary additional areas

warranting inspection would be identified based upon the inspection results.

The staff reviewed the Buried Services Monitoring Program against the AMP elements found in

the GALL Report, SRP-LR Section A.1 .2.3, and SRP-LR Table A.1 -1 and focused on how the

program manages aging effects through the effective incorporation of 10 elements (ie.,

program scope, preventive actions, parameters monitored or inspected, detection of aging

effects, monitoring and trending, acceptance criteria, corrective actions, confirmation process,

administrative controls, and operating experience).

The applicant indicated that the corrective actions, confirmation process, and administrative

controls are part of the site-controlled quality assurance program. The staff's evaluation of the

quality assurance program is discussed in SER Section 3.0.4. The remaining

seven elements are discussed below.

(1) Scope of the Program - The applicant stated that the Buried Services Monitoring

Program consists of PBNP activities that manage the aging effects for components in

the following systems and structures: emergency power, service water, and fire

protection. The program includes preventive measures to mitigate degradation and

visual inspections of the external surfaces of buried carbon steel, cast iron, and low-alloy

steel components for evidence of coating damage and substrate degradation.

Inspections will be performed based on plant operating experience and opportunities for

inspection such as scheduled maintenance. Enhancements to the program will result in

the creation of procedures to implement the program requirements.

The staff's review of LRA Appendix B2.1.7 identified an area in which additional

information was necessary to complete the review of the applicant's AMR program

elements. The applicant responded to the staff's RAI as discussed below.

RAI B2.1.7-1. The program indicates that buried components within the program scope

are coated prior to installation, pursuant to industry guidance. In RAI B2.1.7-1, dated

November 18, 2004, the staff requested the applicant to clarify which components within

the program scope are coated.

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In Its response, dated January 6, 2005, the applicant stated that piping specifications

used for the design and installation of service water and fuel oil piping systems specify

that coatings and wrappings were to be used for buried pipe. Further, the applicant

indicated that plant-specific operating experience during excavations confirmed the

presence of coatings and wrapping on buried portions of these two systems. The

applicant indicated that the combination of design documentation and operating

experience provides reasonable assurance that these systems utilize coatings and

wraps to mitigate loss of material. The staff agreed that design documents and

operating experience provide assurance that the components are coated or wrapped to

mitigate loss of material and that operating experience indicates that inspections of

opportunity can be used to monitor potential degradation.

The applicant also addressed the fire protection piping and indicated that fire protection

piping was installed pursuant to industry standard, which may have allowed installation

without a coating if the soil is not aggressive. The applicant supplied only one example

of operating experience related to an inspection of opportunity for post-indicating valves

(PIV) in the LRA. The applicant's response indicated that the inspection of the buried

fire piping was found to have a light bituminous asphaltic coating and no signs of

external degradation after 14 years. The applicant also identified its understanding that

the soil is not aggressive pursuant to the guidance outlined in NUREG-1 801 and

Indicated that an aggressive environment was defined as having pH of less than 5.5, or

greater than 500 parts-per-million chlorides, or greater than 1500 parts-per-million

sulfates.

During a telephone conference, dated December 15, 2004, the applicant indicated that

there are potentially thousands of feet of buried fire pipe at the plant and that any pipe

coating was not necessarily intended to prevent corrosion of the buried piping. The

applicant's RAI response included a brief summary of past excavations of fire pipe that

is intended to demonstrate that inspections of opportunity occur roughly every three to

four years, and past inspections have not documented any external pipe degradation.

The staff reviewed the applicant's information provided in the LRA, the RAI response

discussed above, and clarifying information provided during the telephone conference.

The staff believes that the information provided by the applicant on the aggressive

nature of the soil is pertinent to concrete and feels that correlation was not provided why

this classification for non-aggressive soil may be used regarding potential corrosion of

buried carbon steel, low-alloy steel or cast iron. The staff acknowledges the frequency

that fire protection piping has been excavated, but understands that documentation

does not exist regarding the condition of the piping. The staff believes that the lack of a

pipe coating or pipe wrap to prevent corrosion should be identified as an exception to

the GALL Report. In light of the limited documented operating experience, no specific

corrosion protection coating on the piping and no correlation of the aggressive nature of

the soil relative to ferrous piping, the staff requested further justification pertaining to

how aging of buried, potentially uncoated pipe could be adequately managed using only

inspection of opportunity. The staff indicated that inspection prior to the period of

extended operation would be necessary to establish an understanding of the current

condition of the piping unless additional documented operating experience establishing

the condition of the piping could be provided.

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During a meeting on February 15, 2005, the staff Indicated and the applicant agreed,

that these responses required further clarification.

In its response, a clarification letter dated March 15, 2005, the applicant committed to

enhance the Buried Services Monitoring Program with additional inspections. The

applicant will perform an inspection of a section of buried fire pipe prior to the period of

extended operation. A susceptible section of the fire protection piping will be chosen for

the inspection prior to the period of extended operation. The applicant also committed

to performing an inspection at least every ten years during the period of extended

operation. However, an inspection of opportunity on buried fire protection piping may be

substituted for these scheduled inspections. The applicant indicated that coated and

wrapped piping will be inspected to identify damage of the coating or wrapping. If

coating damage is identified or if the piping is uncoated the program will require that the

component be further inspected for signs of degradation. The applicant indicated that if

any loss of material is identified the results will be evaluated and additional locations will

be inspected, as required. Evidence of component degradation will be evaluated under

the applicant's corrective action program.

The staff concluded that the enhancements to the Buried Services Monitoring Program

to detect loss of material of buried fire pipe are acceptable. The material condition will

be evaluated prior to the period of extended operation and during extended operation

based upon visual inspection of the pipe or applied coating and if unacceptable loss of

material is identified the sample population will be expanded. Visual inspection of the

pipe coating is consistent with GALL Report Xl M.34 to detect aging of buried piping.

The staffs concern described in RAI B2.1.7-1 is resolved.

The staff confirmed that the "scope of the program" program element, with

enhancements, satisfies the criterion defined in the GALL Report and SRP-LR

Section A.1.2.3.1. The staff concluded that this program attribute is acceptable.

(2) Preventive Actions - The applicant stated that buried components, such as piping and

tanks, are coated pursuant to industry practice prior to installation in order to protect the

component outer surfaces from corrosion and selective leaching.

The staff confirmed that the "preventive actions" program element satisfies the criterion

defined in the GALL Report and SRP-LR Section A.1.2.3.2. The staff concluded that

this program attribute is acceptable.

(3) Parameters Monitored or Inspected - The applicant stated that the program monitors

parameters, such as coating and wrapping integrity, that are directly related to loss of

material due to corrosion and selective leaching on the external surfaces of buried

carbon steel, low-alloy steel, and cast iron components. The effects of corrosion are

detectable by visual inspections, while the effects of selective leaching are detectable by

visual inspections and/or hardness measurements. If there are any indications of

selective leaching, or if the condition is indeterminate, a hardness test will be performed.

The staff confirmed that the "parameters monitored or inspected" program element

satisfies the criterion defined in the GALL Report and SRP-LR Section A.1.2.3.2. The

staff concluded that this program attribute is acceptable.

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(4) Detection of Aging Effects - The applicant stated that inspections of buried components,

such as piping and tanks, at susceptible locations, are performed to confirm that

coatings and wrappings are intact and can ensure that age-related degradation of

external surfaces has not occurred and that the components' intended function(s) can

be maintained. The periodicity of these inspections will be based on plant operating

experience and opportunities for inspection such as scheduled maintenance work.

In its response to RAI B2.1.7-1, the applicant submitted a clarification letter, dated

March 15, 2005, in which the applicant committed to enhance the Buried Services

Monitoring Program with additional inspections. The applicant will perform an inspection

of a section of buried fire pipe prior to the period of extended operation. A susceptible

section of the fire protection piping will be chosen for the inspection prior to the period of

extended operation. The applicant also committed to performing an inspection at least

every ten years during the period of extended operation. However, an inspection of

opportunity on buried fire protection piping may be substituted for these scheduled

inspections. The applicant indicated that coated and wrapped piping will be inspected to

identify damage of the coating or wrapping. If coating damage is identified or if the

piping is uncoated the program will require that the component be further inspected for

signs of degradation. The applicant indicated that if any loss of material is identified the

results will be evaluated and additional locations will be inspected, as required.

Evidence of component degradation will be evaluated under the applicant's corrective

action program.

The staff confirmed that the "detection of aging effects" program element satisfies the

criterion defined in the GALL Report and SRP-LR Section A.1.2.3.4. Inspections of

susceptible locations are expected to ensure management of aging effects. The staff

concluded that this program attribute is acceptable.

(5) Monitoring and Trending - The applicant stated that the inspection results will be

evaluated and used to assess the condition of the external surfaces of buried

components and to identify susceptible locations that may warrant further inspections.

The staff confirmed that the "monitoring and trending" program element satisfies the

criteria defined in the GALL Report and SRP-LR Section A.1.2.3.5. The use of previous inspection results is an appropriate method to establish monitoring and trending of

susceptible locations. The staff concluded that this program attribute is acceptable.

(6) Acceptance Criteria -The applicant stated that evidence of coating and wrapping

degradations will be documented and evaluated under the Corrective Action Program.

The staff confirmed that the "acceptance criteria" program element satPsfjetithe critnria

defined in the GALL Report and SRP-LR Section A.1.243.6. !Documen tto and

evaluation of coating and wrapping degradation is expected td ensure implementati n of

corrective actions and management of aging effects. The staff concluded that this 1

program attribute is acceptable.

(10) Operating Experience - The applicant stated that industry experience has slown that

carbon steel, low-alloy steel, or cast iron buried components have experienced corrosion

and selective leaching degradation. The critical areas appear to be at the interface

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where the component transitions from above ground to below ground. This is also the

area where coating and wrappings will most likely be missing or damaged. Experience

shows that the combination of protective coatings and relatively non-aggressive soil

conditions at PBNP serve to lessen the probability of component degradation due to

corrosion. Based on this plant-specific operating experience, the implementation of the

program will adequately manage the aging effect of loss of material due to corrosion

and selective leaching for the period of extended operation. A review of NRC inspection

reports, QA Audit/Surveillance Reports, and Self-Assessments since 1999 revealed no

issues or findings that could impact the effectiveness of the program.

The staff's review of LRA Appendix B2.1.7 identified areas in which additional

information was necessary to complete the review of the applicant's AMR program

elements. The applicant responded to the staff's RAIs as discussed below.

RAI B2.1.7-2. Related operating experience shows that a post-indicating valve was

repaired in the fire protection system requiring excavation and exposing portions of the

associated piping. In RAI B2.1.7-2, dated November 18, 2004, the staff requested the

applicant to discuss the condition assessment of the piping. The staff also requested

the applicant to provide details about the piping coating and its corrosion (or lack of

corrosion).

Operating experience from a 1993 excavation where coating on 30-inch service water

line and one-inch diesel fuel oil line was damaged was provided. The applicant stated

that a condition report was written during the course of the excavation to repair

damaged coating. The condition report indicated that no corrosion of the piping existed

and that the coating was repaired.

Further, in its response dated January 6, 2005, the applicant also provided operating

experience from an inspection of opportunity during repair to a fire protection system

PIV. The visual inspection included piping areas that were coated, as well as areas

where the base metal of the piping was exposed. This PIV had been buried for 14 years

and showed no signs of corrosion.

The staff found this response acceptable, because the applicant provided adequate

supporting information. Therefore, the concern described in RAI B2.1.7-2 is resolved.

RAI B2.1.7-3. PBNP has limited operating experience regarding inspections of

opportunity validating the buried component degradation. The GALL Report indicates

that inspection periodically is to be evaluated on a plant-specific basis. In RAI B2.1.7-3,

dated November 18, 2004, the staff requested the applicant to justify why a one-time

inspection of various in-scope components is not warranted to establish a basis for

inspection frequency. The staff also requested the applicant to justify why inspections

of opportunity will adequately manage aging.

In its response, dated January 6, 2005, the applicant stated that although the Buried

Services Monitoring Program is a new program, PBNP has almost 34 years of operating

experience with buried components. During that time, there have been no failures of

buried components within the scope of license renewal in the service water, fuel oil, or

fire water systems due to external surface degradation. This is primarily due to

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preventive measures to mitigate degradation (e.g., external coatings and wrappings),

and non-aggressive soil/ground water and lake water environmental conditions. The

applicant stated that this is supported by the examples of plant-specific operating

experience discussed in LRA Section B2.1.7. In addition, the applicant pointed to LRA

Section 3.0.1.9, where it is stated that periodic chemical analyses of the soil/ground

water and lake water will be performed to ensure that the below-grade environment

remains chemically non-aggressive for the period of extended operation. The applicant

concluded that a one-time inspection of various components within the scope of license

renewal is not warranted prior to the period of operation. Inspections will be performed

based on plant operating experience and opportunities for inspection. As additional

operating experience is obtained, lessons learned may be used to adjust the basis of

this program.

The staff found this response unacceptable since the fire protection piping was

uncoated and previous excavations did not sufficiently document the condition of the fire

protection piping. In its response to RAI B2.1.7-1, the applicant submitted a clarification

letter, dated March 15, 2005, in which PBNP committed to schedule an inspection at a

susceptible location in the fire protection system once, prior to entering the period of

extended operation, and at least every 10 years during the period of extended operation;

however, an inspection of opportunity on buried fire protection piping may be substituted

for these scheduled inspections.

The staff found that the clarification response to RAI B2.1.7-1 addresses the staff's

concerns described in RAI B2.1.7-3. These scheduled inspections are expected to

ensure that buried components within the fire protection system are periodically

monitored and inspected. Therefore, RAI B2.7.1-3 is resolved.

The staff confirmed that the "operating experience" program element satisfies the

criteria defined in the GALL Report and SRP-LR Section A. 1.2.3.10. The staff

concluded that this program attribute is acceptable.

FSAR Supplement. In LRA Section Al 5.2.7, the applicant provided the FSAR supplement for

the Buried Services Monitoring Program. The staff reviewed these sections and determined

that the information in the FSAR supplement provides an adequate summary of the:program activities. The staff found these sections of the FSAR supplement meet the requirements of

10 CFR 54.21(d).

Conclusion. On the basis of its review, RAI responses, and audit of the applicant's program,

the staff found that those program elements for which the applicant claimed consistency with

the GALL Report are consistent with the GALL Report. The staff found that the applicant had

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff also reviewed the FSAR supplement for this AMP

and found that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

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3.0.3.2.8 Cable Condition Monitoring Program

Summary of Technical Information in the ApDlication. The applicant's Cable Condition

Monitoring Program is described in LRA Section B2.1.8, "Cable Condition Monitoring Program."

The applicant stated that this is a new program that is consistent, with enhancements, with

GALL AMP XL.E1, -Electrical Cables And Connections Not Subject to 10 CFR 50.49

Environmental Qualification Requirements." The applicant further stated that the Cable

Condition Monitoring Program is consistent, with exceptions and enhancements, with GALL

AMP XL.E2, "Electrical Cables Not Subject to 10 CFR 50.49 Environmental Qualification

Requirements Used in Instrumentation Circuits," and GALL AMP XL.E3, "Inaccessible

Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification

Requirements."

The applicant stated that the Cable Condition Monitoring Program manages aging of conductor

insulation materials on cables and connectors, and other electrical insulation materials that are

installed in adverse localized environments caused by heat, radiation, or moisture. The scope

of this program includes accessible non-environmental qualification (non-EQ) electrical cables

and connections, including control and instrumentation circuit cables, non-EQ electrical cables

used in nuclear instrumentation circuits, and inaccessible non-EQ medium-voltage cables within

the scope of license renewal.

The applicant also stated that the Cable Condition Monitoring Program provides reasonable

assurance that the intended functions of electrical cables and connections within the scope of

license renewal that are not subject to the environmental qualification requirements of

10 CFR 50.49 and are exposed to adverse localized environments caused by heat, radiation, or

moisture are maintained consistent with the CLB through the period of extended operation.

This program considers the technical information and guidance provided in NUREG/CR-5643,"

Insights Gained From Aging Research," IEEE Standard P1 205-2000, "IEEE Guide for

Assessing, Monitoring and Mitigating Aging Effects on Class 1 E Equipment Used in Nuclear

Power Generating Stations," SAND-96-0344, "Aging Management Guideline for Commercial

Nuclear Power Plants - Electrical Cable and Terminations," and EPRI TR-1 09619, "Guideline

for the Management of Adverse Localized Equipment Environments."

This program addresses cables and connections whose configuration is such that most cables

and connections installed in adverse localized environments are accessible. It is a sampling

program where selected cables and connections from accessible areas are inspected and

represent, with reasonable assurance, all cables and connections in adverse localized

environments.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. Details of the staff's audit evaluation are documented in the

staff's audit and review report. Furthermore, the staff reviewed the exceptions and associated

justifications to determine whether the AMP, with the exceptions, remains adequate to manage

the aging effects for which it is credited.

In LRA Section B2.1.8, the applicant stated that its Cable Condition Monitoring Program is

consistent with GALL AMP XL.E1. The applicant further stated that its Cable Condition

Monitoring Program is consistent, with exceptions, to GALL AMP XL.E2 and AMP XLE3.

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The Cable Condition Monitoring Program takes exception to the "scope of the program"

program element for GALL AMP XL.E2 in that only non-EQ electrical cables used in nuclear

instrumentation (NI) circuits that are within the scope of license renewal and are installed in

adverse localized environments will be tested. This means that not all non-EQ instrumentation

cable is tested for reduced insulation resistance (IR) value. GALL AMP XL.E2 states that this

program applies to electrical cables used in circuits with sensitive, low-level signal such as

radiation monitoring and nuclear instrumentation that are within the scope of license renewal.

The staff verified that all electrical cables associated with radiation monitoring and EQ nuclear

Instrumentation within the scope of license renewal are either environmentally qualified in

accordance with 10 CFR 50.49 or not installed in adverse localized environments. In either

circumstance, the deterioration of IR values are either maintained (by virtue of the EQ program)

or do not exist (benign environment). On the basis of its review, the staff found this exception

to be acceptable.

The Cable Condition Monitoring Program also takes exception to the "parameters monitored or

inspected," "detection of aging effects," and "acceptance criteria" program elements for GALL

AMP XL.E2 in that the surveillance tests required by the PBNP technical specifications do not

include the electrical cables for certain nuclear instrumentation circuits. Therefore, the

applicant stated that its Cable Condition Monitoring Program periodically tests nuclear

instrumentation circuits to provide an indication of the cable insulation condition.

For the "parameters monitored or inspected," "detection of aging effects," and 'acceptance

criteria" program elements associated with the exception taken by the applicant, the GALL

AMP XL.E2 states, first, the parameters monitored are determined from the plant technical

specifications and are specific to the instrumentation loop being calibrated, as documented in

the surveillance test procedure; second, calibration provides sufficient indication of the need for

corrective actions by monitoring key parameters and providing trending data based on

acceptance criteria related to instrumentation loop performance; and third, calibration readings

are to be within the loop-specific acceptance criteria, as set out in the plant technical

specifications surveillance test procedures. The first test for license renewal are to be

completed prior to entering the period of extended operation.

The staff reviewed the applicant's Cable Condition Monitoring Program and verified that the

plant program, as documented in the staff's audit and review-report, for the IR testing of

non-EQ nuclear Instrumentation is comprehensive and conservative In that it tests all non-EQ

nuclear instrumentation circuits for insulation condition with the frequency required in the GALL

Report. On the basis of its review, the staff found this exception acceptable.

The staff's review of LRA Section B2.1.8 Identified areas in which additional information was

necessary to complete the review of the applicant's program elements. The applicant

responded to the staff's RAls as discussed below.

RAI B2.1.8-1. The Cable Condition Monitoring Program takes exception to the "scope of the

program" program element for GALL AMP XL.E3 in that the Cable Condition Monitoring

Program is based on prolonged exposure to significant moisture, which is defined as exposures

to significant moisture that last more than a few years.

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GALL AMP XLE3 states that significant moisture" is defined as periodic exposures to moisture

that last more than a few days (e.g., cable in standing water)." In RAI B2.1.8-1, dated

December 21, 2004, the staff requested the applicant to clarify the basis for this exception. In

its response, a clarification letter dated March 15, 2005, the applicant deleted this specific

exception related to significant moisture and agreed to perform the cable testing, with remaining

exceptions, as described in the GALL AMP XL.E3. On the basis of its review and the RAI

response, the staff found this acceptable. The staff's concern described in RAI B2.1.8-1 is

resolved.

The Cable Condition Monitoring Program also takes exception to the "parameters monitored or

inspected" and "detection of aging effects" program elements for GALL AMP XI.E3 in that the

Cable Condition Monitoring Program requires periodic testing of a representative sample of

in-scope, inaccessible medium-voltage cables not designed for submergence subject to

prolonged exposure to significant moisture and significant voltage. Specifically, the testing is

performed on a representative sampling of cable rather than on all cables.

RAI 3.6.2.1-7. In RAI 3.6.2.1-7, dated November 18, 2004, the staff requested the applicant to

explain why testing of inaccessible medium-voltage cables for detecting deterioration of

insulation due to moisture and voltage fluctuation is not needed. The staff requested the

applicant to consider all inaccessible non-EQ electrical medium-voltage cables for testing.

In its response, dated January 25, 2005, the applicant stated:

PBNP has tested all in-scope inaccessible Non-EQ medium-voltage cables. This testing

was performed in 2003 and 2004 and no significant deterioration of the cables was

found. On a ten-year testing interval, the next test will occur just after the end of the

current license for Unit 1, but prior to the start of the period of the extended license for

PBNP Unit 2. This will yield one additional test period versus if PBNP had waited until

just prior to the end of the current licensed period for Unit 1 to perform the initial testing.

PBNP intends to perform additional testing prior to the next scheduled ten-year test, as

deemed prudent by our system engineering personnel, to ensure continued awareness

of the condition of the aged medium-voltage cables.

Since the program has not yet been developed, selection of the sample of

medium-voltage cables to be tested is yet to be determined, but the cable sample

selection for testing will be based on the severity of prolonged exposure to significant

moisture and significant voltage, and the age of the cable. For example, for cables of

the same size, construction, voltage and ampere loading, and age run in parallel conduit

in the same underground duct bank, the sample may consist of only those cables in the

lowest conduits, since they are more likely to be exposed to water.

GALL AMP XL.E3 states that in-scope, medium-voltage cables exposed to significant moisture

and significant voltage are tested to provide an indication of the condition of the conductor

insulation.

In response to RAI B2.1.8-1, the applicant also agreed to consider for testing all inaccessible

non-EQ medium-voltage cables within the scope of license renewal not designed for

submergence that are subject to significant moisture and significant voltage. A representative

sample of in-scope, inaccessible, non-EQ, medium-voltage cables not designed for

3-52
submergence subject to significant moisture and significant voltage will be tested prior to

entering the period of extended operation and once every ten years thereafter. This sample will

include those cables considered to be most susceptible and will represent all cable types and

manufacturers. The basis for this representative sample will be documented. In addition, the

applicant revised the definition of significant moisture to be consistent with that contained in the

GALL AMP XL.E3. On the basis of its review and the discussion above, the staff found this

acceptable. The staff's concern described in RAI 3.6.2.1-7 is resolved.

In LRA Section B2.1.8, the applicant stated that its Cable Condition Monitoring Program is

consistent with GALL AMPs XL.E1, XL.E2,and XL.E3 with enhancements. The applicant stated

that, for the 'scope of the program" program element, enhancements to the Cable Condition

Monitoring Program include establishing a new program that manages aging of conductor

insulation materials on cables and connections, and other electrical insulation materials that are

installed in adverse localized environments caused by heat, radiation, or moisture. The staff

considered this type of enhancement to be an administrative enhancement that does not

require staff review.

O2eratina Excerience. The staff reviewed the applicant's operating experience for the Cable

Condition Monitoring Program.

In the LRA, the applicant stated the following:

Industry operating experience has shown that adverse localized environments caused

by heat or radiation for electrical cables and connections may exist next to or above

(within three feet of) steam generators, pressurizers or hot process pipes, such as

feedwater lines. These adverse localized environments have been found to cause

degradation of the insulating materials on electrical cables and connections that is

visually observable, such as color changes or surface cracking. These visual indications

can be used as indicators of degradation.

Industry operating experience has also shown that visual inspections of non-EQ

instrumentation circuit cables within the scope of license renewal are adequate to

identify aging degradation, as documented in SAND-96-0344, 'Aging Management

Guideline for Commercial Nuclear Power Plants - Electrical Cable and Terminations."

Exposure of electrical cables to adverse localized environments caused by heat or

radiation can result in reduced insulation resistance. Reduced insulation resistance can

cause an increase in leakage currents between conductors and from individual

conductors to ground. A significant reduction of insulation resistance is a concern for

circuits with sensitive, high voltagejlow-level signals such as radiation monitoring and

nuclear instrumentation since it may contribute to inaccuracies in the instrument circuits.

... Plant-specific operating experience has shown that adverse localized environments

caused by heat and moisture exist at PBNP. For example, the 4K VAC feeds to the

Steam Generator Feed Pumps and from X04 have been exposed to adverse localized

environments caused by heat and moisture, respectively. Maintenance work orders

were generated to test and/or replace cables and connections that showed signs of

aging due to adverse localized environments, as required.

3-53
Electrical cables associated with radiation monitoring instrumentation within the scope of

license renewal at PBNP are either environmentally qualified in accordance with

10 CFR 50.49 or not installed in adverse localized environments (e.g., radiation

monitoring instrumentation associated with the control room). Non-EQ electrical cables

used in nuclear instrumentation circuits within the scope of license renewal are included

within the scope of the Cable Condition Monitoring Program. Operating experience has

shown that anomalies found during cable testing can be caused by the degradation of

the nuclear instrumentation circuit cable and are a possible indication of potential cable

degradation.

Plant-specific operating experience has shown that changes to nuclear instrumentation

cable are gradual and minimal over a long period of time. PBNP Unit 1 has operated for

33 years, and Unit 2 has operated for 31 years without any direct failure in the nuclear

instrumentation cabling. Rather, particular cables have exhibited varying degrees of

noise, decreased IR, and, in one case, a conductor-to-shield short. These conditions

have decreased the signal quality but not interrupted or impaired the accuracy of the!

indication. In some cases of noise and reduced IR, this condition has been tracked over

several years and little additional degradation has been observed. In the case of the

conductor-to shield short, the cable was abandoned and a spare cable connected to

reestablish the circuit.

... An NRC Inspection Report identified a finding regarding inadequate and untimely

corrective actions relating to flooding of manholes containing safety and

nonsafety-related cables. The inspectors reviewed corrective actions associated with

flooded manholes containing electrical cables. Since 1997, numerous corrective action

program documents have been written relating to flooded manholes, submerged cables

in manholes, ice formation due to flooded manholes, effects of water on cables, and

spurious alarms relating to manholes. Based on the number of corrective action

program documents and associated ineffective corrective actions, the inspectors

concluded that the applicant had not implemented effective corrective actions to address

the problem of cables flooded in manholes.

A condition evaluation was performed as a result of questions raised during the

inspection. In order to better understand the magnitude of the groundwater intrusion

problem into the electrical manholes, a new call-up to inspect and pump the flooded

manholes was initiated. The new call-up periodically inspects and pumps down the

electrical manholes, as necessary. As part of the new call-up, the approximate water

level in each manhole is recorded. The recording of the water level will provide the

basis for any future changes in frequency to the call-up and any deletions of manhole

inspections. Based on the corrective actions taken to evaluate pumping out the

manholes throughout the year and to evaluate the need to inspect other manholes for

similar conditions, the NRC finding was closed. A solution to prevent manhole and

cable vault flooding is currently being pursued.

An NRC Inspection Report also identified an Unresolved Item concerning the effects of

prolonged water submergence on 13.8K VAC, 4160 VAC, and 480 VAC electrical

cables. The NRC determined that this issue did not represent an immediate safety

concem. However, it was concerned that if the condition were left uncorrected it would

become a more significant safety concern in subsequent years if cable degradation

3-54
were to interrupt the continuity of offsite power to the safeguards electrical buses. In

response to these concerns, a number of these cables, including all of the 13.8K VAC

cables subject to submergence, were successfully tested in 2003 using the Energized

Partial Discharge Testing Methodology. These cables will also be tested in the future in

accordance with the test vendors recommendations using a proven testing

methodology. In addition, actions have been taken to prevent further cable

submergence. Based upon these actions, the NRC closed this URI during the third

quarter 2003.

As documented in the audit and review report, the above statements were reviewed during

discussions with the applicant regarding the manhole flooding program. The staff reviewed the

documentation for the applicant's electrical manhole inspection program. Records from the

Computerized History and Maintenance Planning System (CHAMPS) were reviewed, showing

the frequency of maintenance actions and conditions found in manholes. CHAMPS is a

computer-based program in which records of work performed on plant SSCs are initiated and

managed. For the data sets reviewed (previous 12 months), water level in the manholes did

not reach the cable junctions. New manhole inspection and pumpdown procedures require that

the as-found water level be recorded on the work request form. When entered into CHAMPS,

these data will be trended and used to modify the inspection frequency as required to keep the

water level below the cable connections.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical staff to verify that the plant-specific operating experience did not reveal

any degradation not bounded by industry experience.

On the basis of its review of the above industry and plant-specific operating experience, the

staff concluded that the Cable Condition Monitoring Program, with exceptions as discussed, will

adequately manage the aging effects that are identified in the LRA for which this AMP is

credited.

FSAR Supplement. In LRA Section Al 5.2.8, the applicant provided the FSAR supplement for

the Cable Condition Monitoring Program. The staff reviewed these sections and determined

that the information in the FSAR supplement provides an adequate summary of the program

activities. The staff found these sections of the FSAR supplement meet the requirements of

10 CFR 54.21 (d).

Conclusion. On the basis of its review, the RAI responses discussed above, and audit of the

applicant's program, the staff found that those program elements for which the applicant

claimed consistency with the GALL Report are consistent with the GALL Report. In addition,

the staff reviewed the exceptions and the associated justifications and determined that the

AMP, with the exceptions, is adequate to manage the aging effects for which it is credited. The

staff found that the applicant had demonstrated that the effects of aging will be adequately

managed so that the intended functions will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the

FSAR supplement for this AMP and found that it provides an adequate summary description of

the program, as required by 10 CFR 54.21(d).

3-55
3.0.3.2.9 Closed-Cycle Cooling Water System Surveillance Program

Summary of Technical Information in the Application. The applicant's Closed-Cycle Cooling

Water System Surveillance Program is described in LRA Section B2.1.9, 'Closed-Cycle Cooling

Water System Surveillance Program." The applicant stated that this is an existing program that

is consistent, with exceptions and enhancements, with GALL AMP XL.M21, "Closed-Cycle

Cooling Water System."

The applicant stated that the Closed-Cycle Cooling Water System Surveillance Program

manages aging effects in closed-cycle cooling water (CCCW) systems that are not subject to

significant sources of contamination, in which water chemistry is controlled and heat is not

directly rejected to the ultimate heat sink. The program includes (1) maintenance of system

corrosion inhibitor concentrations to minimize degradation and (2) periodic or one-time

surveillance testing and inspections to evaluate system and component performance.

Inspection methods may include visual testing, ultrasonic testing (UT), and eddy current testing

(ECT).

The program is applicable to the component cooling (CC) water system, the emergency diesel

generator (EDG) coolant subsystems, gas turbine, gas turbine-associated diesel cooling

subsystems, and the chilled water subsystems for the control room, computer room, and cable

spreading room.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. Details of the staff's audit evaluation are documented in the

staff's audit and review report. Furthermore, the staff reviewed the exceptions and associated

justifications to determine whether the AMP, with the exceptions, remains adequate to manage

the aging effects for which it is credited.

In LRA Section B2.1.9, the applicant stated that its Closed-Cycle Cooling Water System

Surveillance Program is consistent with GALL AMP XL.M21, with exceptions. The Closed-Cycle

Cooling Water System Surveillance Program takes exception to the "preventive actions" and

"acceptance criteria" program elements such that the EDG and gas turbine-related cooling

subsystems, and the ventilation chilled water subsystems corrosion inhibitor concentrations are

maintained in accordance with the manufacturers recommendation, not EPRI TR-1 07396,

"Closed-Cooling Water Chemistry Guidelines."

GALL Report AMP XLI.M21 states, for the "preventive actions" and "acceptance criteria" program

elements, that the program should rely on the use of appropriate materials, lining, or coating to

protect the underlying metal surfaces and maintenance of system corrosion inhibitor

concentrations within specified limits of EPRI TR-1 07396 to minimize corrosion. The program

includes monitoring and control of cooling water chemistry to minimize exposure to aggressive

environments and application of corrosion inhibitor in the component cooling water system to

mitigate general, crevice, and pitting corrosion.

The applicant stated that the EDG and gas turbine-related cooling subsystems, and the

ventilation chilled water subsystems corrosion inhibitor concentrations are maintained in

accordance with the manufacturers recommendation, not EPRI TR 107396. The staff reviewed

the EPRI guidance document and the PBNP operating experience. The staff observed that

PBNP relies on the use of appropriate materials and a water treatment program to inhibit

3-56
corrosion. In addition, potassium dichromate is used as the corrosion inhibitor in the CC

system, and the chromate concentration limits fall within the typical control range provided in

EPRI TR-107396 Table 4.2. The program includes the monitoring and control of CC system

chemistry in order to minimize exposure to aggressive environments and to mitigate corrosion.

The EDG, gas turbine, gas turbine-associated diesels cooling subsystems, and ventilation

chilled water subsystems use commercial corrosion inhibitors. EPRI TR-1 07396 discusses

these in general terms but does not provide specific concentration limits for the two products in

use. The applicant maintains the corrosion inhibitor concentrations within the product

manufacturers recommended limits. The operating history indicates a lack of component

degradation exposed to the CCCW system coolant.

On the basis of its review, the staff found that the support of the manufacturer's

recommendations for chemistry concentrations is expected to maintain appropriate system

operation. On this basis, the staff found this exception acceptable.

The Closed-Cycle Cooling Water System Surveillance Program also takes exception to the

"parameters monitored or inspected" program element in that (1) PBNP does not reference

EPRI TR-1 07396 in any of the CC system, EDG, gas turbine, or chilled water subsystem

procedures, and as such does not monitor the CC system for corrosion products, calcium and

magnesium, or refrigerant chemicals, (2) the parameters stated in GALL AMP XI.M21 are not

monitored for all heat exchangers, only for a selected few in the CC system, (3) not all of the

EPRI chemistry parameters are monitored for the EDG, gas turbine, gas turbine associated

diesels coolant subsystems, and the ventilation chilled water subsystems, and (4) pump suction

or discharge pressure and coolant flows are not monitored for the EDG, gas turbine and

ventilation related subsystems.

GALL AMP Xl.M21 states, for the "parameters monitored or inspected" program element, that

this program should monitor the effects of corrosion by surveillance testing and inspections in

accordance with standards in EPRI TR-1 07396 to evaluate system and component

performance. For pumps, the parameters monitored include flow and discharge and suction

pressures. For heat exchangers, the parameters monitored include flow, inlet and outlet

temperatures, and differential pressure.

For the first exception, the applicant stated that it did not reference EPRI TR-107396 in any of

the CC system, EDG, gas turbine, or chilled water subsystem procedures. The EPRI document

states that the system impurities that could be monitored are chlorides, fluorides, sulfates,

corrosion products, calcium, and magnesium, refrigerant chemicals and radionuclides. The

applicant stated that the Closed-Cycle Cooling Water System Surveillance Program periodically

monitors CC system chemistry to verify it is being maintained within specified limits (pH,

chloride, fluoride, chromate and sulfate concentrations, conductivity, and radioactivity).

The staff reviewed the information provided in the LRA. The staff found that It is not mandatory

that the EPRI document be referenced, but that the important feature is what is monitored (i.e.,

system chemistry). With these monitored parameters and operability tests performed on

various system components, the staff found that the applicant has demonstrated satisfactory

performance with the affected SSCs. On the basis of the consideration of the parameters

monitored, the successful system operating history and operability test performance, the staff

found the exception is acceptable.

3-57
For the second exception, the applicant stated that the parameters are not monitored for all

heat exchangers, only for a selected few in the CC system. The applicant stated that the CC

system flows are monitored, as are pump suction and discharge pressure. Selected heat

exchangers are monitored for flow. Selected heat exchangers also are heat balance tested.

The smaller heat exchangers, such as the seal water heat exchangers on the containment

spray pumps, residual heat removal pumps, and the safety injection pumps and the sample

system heat exchangers, do not have the capability of performing a heat balance test. Flows

through these heat exchangers are set within specified ranges so that they are capable of

performing their intended function. Periodic performance of system pressure testing of the

component cooling system verifies that the pressure boundary function of the components in

the component cooling system is maintained. This test is used to identify leaks and correct

them prior to a loss of system or component intended function.

The staff reviewed the information provided in the LRA. The staff found that flow monitoring

and pressure testing are sufficient to ensure that intended function is maintained. On the basis

of its review, the staff found this exception acceptable.

For the third exception, the applicant stated that not all of the EPRI chemistry parameters are

monitored for the coolant subsystems in the EDG, gas turbine, gas turbine associated diesels,

and the ventilation chilled water. The applicant stated that the EDG coolant subsystems are

periodically sampled and analyzed to maintain the corrosion inhibitor concentration within the

manufacturer's recommended range. The ventilation chilled water system performance is

periodically monitored by checking system pressures and temperatures. The coolant in diesel

generators G01 and G02 is also checked for pH, microbiological contamination, conductivity,

total suspended solids, iron, copper, calcium, and magnesium. Engine coolant temperatures

are recorded during the monthly surveillance tests.

The staff reviewed the information provided in the LRA. On the basis of its review, the staff

found that the sampling and surveillances of the coolant and controlled engine temperature

provides a reasonable basis for successful operation of the subsystems. On this basis, the

staff found this exception acceptable.

For the fourth exception, the applicant stated that it does not monitor pump suction or discharge

pressure and coolant flows for the EDG, gas turbine and ventilation related subsystems.

Operating experience confirmed acceptable performance of this equipment. The applicant

stated that system performance assessments will continue to provide an indicator that a

subsystem may be degraded and result in appropriate corrective actions.

The staff reviewed the information provided in the LRA. The staff found that the plant operating

experience and system flow assessment is expected to ensure pump performance. On the

basis of its review, and on the system limits, tests performed and the acceptable operating

experienced observed, the staff found this exception acceptable.

The staff reviewed the applicant's Closed-Cycle Cooling Water System Surveillance Program,

as documented in its audit and review report. The staff concluded that the applicant monitors

the water chemistry and operating characteristics of the CCCW system in such a way that it

enables the applicant to continue to confirm the effectiveness of the CCCW system.

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The Closed-Cycle Cooling Water System Surveillance Program also takes exception to the

"detection of aging effects" program element such that PBNP does not perform microbiological

testing on the CC system, ventilation chilled water subsystems, or the coolant subsystems for

the B train EDG, or the coolant systems associated with the gas turbine.

GALL AMP XI.M21 states that controlling water chemistry does not preclude corrosion at

locations of stagnant flow conditions or crevices. Degradation of a component due to corrosion

would result in degradation of system or component performance. The extent and schedule of

inspections and testing in accordance with EPRI TR-1 07396 ensures detection of corrosion

before the loss of intended function of the component. Performance and functional testing in

accordance with EPRI TR-1 07396 ensures acceptable functioning of the CCCW system or

components serviced by the system. For systems and components in continuous operation,

performance adequacy is determined by monitoring data trends for evaluation of heat transfer

fouling, pump wear characteristics, and branch flow changes. Components not in operation are

periodically tested to ensure operability.

The applicant stated that it monitors CC water flows only through critical heat exchangers and

monitors the overall system performance. EPRI TR-1 07396 also states that microbiological

testing is performed on the bulk water in the CC system (planktonic organisms). The test can

be performed to provide a good indication of trends in general microbiological control.

Microbiological testing is performed on the nitrate based coolant used in G01 and G02 because

this type of coolant Is susceptible to microbiological contamination. The applicant does not

perform this type of test on the CC system, ventilation chilled water subsystems, or the coolant

.subsystems for diesel generators G03 and G04, and the coolant systems associated with G05,

G-500, and G-501. As previously stated, the -chromates in the CC system are toxic to

microbiological organisms, and plant experience has shown no problems with microbiological

growth in the system. The glycol concentration in the ventilation chilled water subsystems,

G03, G04, G05, G-500, and G-501 is maintained at a level where biological growth is inhibited.

The applicant stated that these preventive actions preclude the need to perform microbiological

testing.

Furthermore, the applicant stated that its One-Time Inspection Program is credited with the

detection of corrosion in areas of stagnant flow conditions in the CC system. Periodic heat

transfer testing of the CC heat exchangers provides indication of fouling. Various CC system

operating parameters such as pressure, flow, and surge tank volume are monitored and will

provide indications of system degradation. The EDGs, gas turbine, and gas turbine-associated

diesels are not normally in operation but are periodically tested to ensure operability. Internal

inspections of portions of the engines coolant subsystem will be performed via the One-Time

Inspection Program. The ventilation chilled water subsystems are normally in operation, and

system performance is periodically checked.

As documented in the audit and review report, the staff reviewed the information provided in the

LRA and held technical discussions with the applicant. The staff concluded that the measures

the applicant takes to monitor system chemistry and operating performance enable the

applicant to continue to confirm the effectiveness of the CCCW system. The staff found that

the applicant's One-Time Inspection Program supports the performance of its Closed-Cycle

Cooling Water Surveillance Program, and will adequately sample those areas subject to low or

stagnant flow as recommended by GALL AMP XI.M21. On this basis, the staff found this

exception acceptable.

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The Closed-Cycle Cooling Water System Surveillance Program also takes exception to the

"monitoring and trending" program element in that (1) PBNP will perform tests as a result of CC

system performance evaluations by the responsible engineer and (2) PBNP does not routinely

perform heat removal capability tests on the EDG, gas turbine related coolant subsystems, and

the ventilation chilled water subsystems.

GALL AMP XL.M21 states that the frequency of sampling water chemistry varies and can occur

on a continuous, daily, weekly, or as-needed basis, as indicated by plant operating conditions.

Pursuant to EPRI TR-1 07396, performance and functional tests are performed at least every 18

months to demonstrate system operability, and tests to evaluate heat removal capability of the

system and degradation of system components are performed every five years. The testing

intervals may be adjusted on the basis of the results of the reliability analysis, type of service,

frequency of operation, or age of components and systems.

The applicant stated that the CC system water chemistry is sampled on a periodic basis and as

indicated by plant operating conditions. Functional performance of the CC system is monitored

with the in-place instrumentation. System pressure tests are performed per plant procedures.

Thermal balance testing of the component cooling/service water heat exchangers is performed

on a frequency in accordance with plant procedures. Plant procedures are used to set flows to

heat exchangers or a group of heat exchangers, except for pump seal coolers. The EDG and

gas turbine-related coolant subsystems are sampled on a periodic basis. The staff considers

the in-place monitoring equipment as an acceptable alternative for performing periodic

functional tests. Based on review of the associated EPRI documents, plant chemistry sampling,

monitoring, and surveillance procedures, system performance tests, plant operating

procedures, and operating history, and the applicant's response to questions, the staff found

the measures the applicant takes to monitor system chemistry and operating performance

enable the applicant to continue to confirm the effectiveness of the Closed-Cycle Cooling Water

System Surveillance Program. On this basis, the staff found this exception acceptable.

The applicant does not routinely perform heat removal capability tests on the EDG and gas

turbine-related coolant subsystems. However, operability testing is periodically conducted.

These tests provide an indication of the heat flow performance of the EDG and gas

turbine-related coolant subsystems. Based on the operability tests, and successful operation,

the staff found this exception acceptable.

The applicant also does not routinely perform heat removal capability tests on the

ventilation chilled water subsystems. These systems are normally in continuous operation,

and system operating parameters are periodically checked to assess system performance. The

continuous operation is an indication that the ventilation chilled water subsystems heat

exchangers are performing appropriately. Based on the continuous operation and past

successful operation, the staff found this exception acceptable.

In LRA Section B2.1.9, the applicant stated that its Closed-Cycle Cooling Water System

Surveillance Program is consistent with GALL AMP XL.M21, with enhancements. The applicant

stated that, for the "detection of aging effects" program element, enhancements to plant

documents include revisions to ensure consideration of the applicable aging effects and to

establish sampling periodicity and criteria for the coolant associated with the gas turbine and

related diesel engines, and applicable ventilation chilled water subsystems. This is being done

to ensure the appropriate concentration of corrosion inhibitor is being maintained in the coolant.-

3-60
Enhancements also Include (1) a review of the acceptable chloride and fluoride levels in the CC

system, (2) the creation of procedural requirements for operating the system within the

established acceptance ranges for the applicable chemical parameters, and (3) the completion

of a strategy for a long-term condition assessment of the CC heat exchangers because of

suspected galvanic corrosion of the tube support plates. The staff considered these types of

enhancements to be administrative enhancements that do not require staff review.

Ooerating Experience. The staff reviewed the applicant's operating experience for the

Closed-Cycle Cooling Water System Surveillance Program.

In the LRA, the applicant stated the following:

Plant-specific operating experience indicates that CC system performance has been

very good. The applicant has not experienced degradation of its CC system due to

corrosion product build up or cracking. The chromate water treatment in the CC system

has performed satisfactorily in mitigating loss of material and loss of heat transfer.

Routine checks performed on the CC system by operators, such as monitoring flows

through heat exchangers, monitoring system pressures at various locations, monitoring

pump suction and discharge pressure, and monitoring temperatures of both the CC

system and the components that the CC water is cooling, ensure early detection of CC

system problems that will lead to corrective actions. The performance of a system

pressure test is used to detect and eliminate unacceptable leaks.

Tube vibration in the CC heat exchangers has been documented in the corrective action

program. The vibration has been attributed to increased clearances in the tube-to-tube

support plate interface. The CC heat exchangers were re-tubed with SeaCure tube

material, which creates the potential for galvanic corrosion of the carbon steel tube

support plates. Galvanic corrosion of the tube support plates is believed to be the

reason for the increased clearances and subsequent tube vibration at high CC flows. A

long-term condition assessment strategy for the CC heat exchangers is being developed

regarding this issue.

Trending of nitrite and microbiological levels in the engine coolant of G01 and G02

EDGs has revealed slight in-leakage of service water into the engine coolant. This

resulted in the heat exchangers being inspected and repaired or replaced. Periodic

nitrate depletion In G02 is an open issue that is being addressed via the corrective

action process. There have been no significant degradation problems with the coolant

subsystems of EDG G03 and G04, the gas turbine and associated equipment, and the

ventilation chilled water subsystems. The Closed-Cycle Cooling Water System

Surveillance Program provides reasonable assurance that these subsystems and

components will continue to perform their intended functions.

A review of NRC Inspection Reports, QA Audit/Surveillance Reports, and

Self-Assessments since 1999 revealed no issues or findings that could impact the

effectiveness of the Closed-Cycle Cooling Water System Surveillance Program.

As additional operating experience is obtained, lessons learned may be used to adjust

this program.

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The staff reviewed plant operating experience provided in the LRA and the plant method for

data collection, as documented in the audit and review, and held discussion with the applicant's

technical staff. On the basis of its review, the staff concluded that the Closed-Cycle Cooling

Water System Surveillance Program, with identified exceptions, will adequately manage the

aging effects that are identified in the LRA for which this AMP is credited.

FSAR Supplement. In LRA Section Al 5.2.9, the applicant provided the FSAR supplement for

the Closed-Cycle Cooling Water System Surveillance Program. The staff reviewed these

sections and determined that the information in the FSAR supplement provides an adequate

summary of the program activities. The staff found these sections of the FSAR supplement

meet the requirements of 10 CFR 54.21 (d).

Conclusion. On the basis of its review and audit of the applicant's program, the staff found that

those program elements for which the applicant claimed consistency with the GALL Report are

consistent with the GALL Report. In addition, the staff reviewed the exceptions and the

associated justifications and determined that the AMP, with the exceptions previously

discussed, is adequate to manage the aging effects for which it is credited. The staff found that

the applicant had demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the FSAR supplement

for this AMP and found that it provides an adequate summary description of the program, as

required by 10 CFR 54.21 (d).

3.0.3.2.10 Fire Protection Program

Summary of Technical Information in the Application. The applicant's Fire Protection Program

is described in LRA Section B2.1.10, "Fire Protection Program." The applicant stated that this

is an existing program that is consistent, with exceptions and enhancements, with GALL AMP

XI.M26, "Fire Protection," and GALL AMP XI.M27, "Fire Water System," as clarified by Interim

Staff Guidance (ISG)-04, "Aging Management of Fire Protection Systems for License Renewal."

The applicant stated that the Fire Protection Program consists of fire barrier inspections,

electric and diesel-driven fire pump tests, halon fire suppression system inspections and tests,

and water-based fire protection system inspections and tests. The fire barrier inspection

requires periodic visual inspection of fire barrier penetration seals, fire dampers, fire barrier

walls, ceilings and floors, and periodic visual inspections and functional tests of fire-rated doors

to ensure that their functionality and operability are maintained. The electric and diesel-driven

fire pumps are tested to ensure that an adequate flow of firewater is supplied and that there is

no degradation of diesel fuel supply lines. The water-based fire protection systems are

inspected and tested to provide reasonable assurance that fire water systems are capable of

performing their intended function. Also, the applicant stated that its fire protection system

credits the Buried -Services Monitoring Program for the management of aging effects on the

external surfaces of buried fire water system piping.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. Details of the staff's audit evaluation are documented in the

staff's audit and review report. Furthermore, the staff reviewed the exceptions and associated

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justifications to determine whether the AMP, with the exceptions, remains adequate to manage

the aging effects for which it is credited.

The Fire Protection Program takes exception to the "preventive actions" program element for

GALL AMP XL.M26 in that the fire protection evaluation report does not manage or prevent

aging effects of components associated with fire prevention, fire detection, fire suppression, fire

containment or alternative shutdown capability. Therefore, the fire protection evaluation report

is not addressed in the fire protection AMP. GALL AMP XL.M26, as modified by ISG-04, states

that a fire hazard analysis is to assess the fire potential and fire hazard in all plant areas, and to

specify measures for fire prevention, fire detection, fire suppression, and fire containment and

alternative shutdown capability for each fire area containing SSCs important to safety.

The staff verified that the fire protection evaluation report assessed the fire potential and fire

hazard in all plant areas, and specified measures for fire prevention, detection, suppression,

and containment, as well as alternative shutdown capability for each fire area containing SSCs

important to safety, as the fire hazard analysis, named in the GALL Report, specifies.

Therefore, the staff determined that the generic GALL Report term "fire hazard analysis"

equates to the PBNP-specific term 'fire protection evaluation report," because each performs

the same actions and specifies the same measures. With regard to the exception, noted

above, the staff did not expect to find requirements to manage or to prevent aging effects in the

requirements in the fire protection evaluation report. The purpose of this fire protection

evaluation report is not to manage or to prevent aging effects, but to demonstrate that the plant

will maintain the ability to perform safe shutdown functions and to minimize radioactive material

releases to the environment in the event of a fire. The staff did find requirements to manage

and to prevent aging in this fire protection AMP. It is this AMP, with its specific program

elements, that actually manages or prevents aging effects on the specified components

associated with the above systems. The staff learned that the applicant had identified this as

an exception on the basis that the program element contained requirements that did not

manage or prevent aging effects. The applicant had complied with the GALL Report

specification but wanted to call attention to the fact that the requirements did not actually

manage or prevent aging effects. On the basis of its review, and for the reasons discussed

herein, the staff found this exception acceptable.

The Fire Protection Program takes exception to the parameters monitored and inspected, the

detection of aging effects, and the "monitoring and trending program" elements for GALL

AMP XL.M26 in that the visual inspection of fire barrier penetration seals is performed on a

4.5-year inspection frequency, with approximately one-third of these seals being inspected

every 18-months. The applicant stated that the inspection frequency of the visual inspections

of the fire barrier penetration seals, during which approximately 33 percent of the total seal

population are inspected, meets and exceeds that inspection frequency that is recommended

by the GALL Report, as modified by ISG-04. GALL AMP XL.M26, as modified by ISG-04, states

that visual inspection of 10 percent of each type of penetration seal is to be performed at least

once during every refueling outage.

The staff verified that the inspection frequency of the visual inspections of the fire barrier

penetration seals, at approximately 33 percent versus 10 percent, exceeds the inspection

frequency-that is recommended by the GALL Report, as modified by ISG-04. As such, the staff

found this exception acceptable.

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The Fire Protection Program takes exception to the "detection of aging effects" program

element for GALL AMP XL.M26 in that PBNP inspection personnel are not qualified to perform

VT-1 or VT-3 visual inspections. GALL AMP XL.M26, as modified by ISG-04, states that VT-1

or equivalent and VT-3 or equivalent visual inspections are to be performed and, therefore,

allows alternative inspections to be performed.

The staff reviewed the information provided by the applicant, as documented in the audit and

review report. The staff verified that, although the inspection personnel were qualified to

perform these inspections in accordance with PBNP procedures, they were not qualified in

accordance with VT-1 or VT-3. The staff determined that the applicable inspection procedures

contained procedure requirements and acceptance criteria that were of sufficient detail and

conservatism that they were the equivalent to those recommended for VT-1 and VT-3 visual

inspection. The staff noted the practical matter that those personnel who install the fire barrier

components, (ie., those who were the most familiar with them), were the principal inspectors

who performed the required visual inspections. The staff also noted the further conservative

measure that these inspectors reported any discrepancy discovered during the inspection to the

fire protection system engineer or the fire protection engineer for his evaluation and disposition

under the applicant's corrective action program. Therefore, the staff concluded that the detail

and conservatism provided in the inspection procedures were sufficient to assure that an

inspection equivalent to VT-1 or VT-3 will be performed. On the basis of its review and the

above discussion, the staff found this exception acceptable.

The Fire Protection Program takes exception to the "detection of aging effects" program

element for GALL AMP XL.M27 in that PBNP performs monthly yard fire hydrant inspections

and annual yard fire hydrant flushing, which is not in accordance with NFPA 25. The Fire

Protection Program also takes exception to the "detection of aging effects" program element for

GALL AMP XL.M27 in that PBNP checks the flow capacity of the main fire loop annually, but

does not measure individual fire hydrant flow. GALL AMP XI.M27, as modified by ISG-04,

states that visual inspection of yard fire hydrants is to be performed annually, in accordance

with NFPA 25, and that fire hydrant hose hydrostatic tests, gasket inspections, and fire hydrant

flow tests are to be performed annually.

The staff noted that NFPA 25 recommends a fire hydrant visual inspection to be performed

annually and after each operation, and determined that PBNP, in performing monthly fire

hydrant visual inspections, exceeds this NFPA 25 recommendation. The staff noted that PBNP

treats fire hydrant hoses and gaskets as consurnables, and that these components are within

the scope of license renewal. The staff further noted that hoses and gaskets are visually

inspected monthly and the hoses are hydrostatically tested on a frequency of 18 or 36 months,

depending on the hose location. In the event that the hose or gasket does not pass the visual

inspection, or the hose does not pass the hydrostatic test, it is replaced. Therefore, the staff

concluded that this practice precludes any aging concern for these components. The staff

verified that main fire loop flow capacity test that PBNP performs annually, has a flow capacity

that meets and exceeds that of any single fire hydrant. On the basis of its review and for the

reasons discussed above, the staff found this exception acceptable.

The Fire Protection Program takes exception to the "monitoring and trending" program element

for GALL AMP XL.M27 in that inspection and testing is performed in accordance with the

nuclear insurance carrier's fire protection system testing requirements and generally follows the

guidance of the applicable NFPA codes and standards. GALL AMP XL.M27, as modifiedby

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ISG-04, states that system performance testing results are monitored and trended as specified

by the NFPA codes and standards.

The staff reviewed the information provided by the applicant, as documented in its audit and

review report. The staff found significant deviations between PBNP fire protection system

testing requirements and NFPA codes and standards testing requirements. The staff

determined that the applicable NFPA standard in effect at PBNP is NFPA 13, "Standard for the

Installation of Sprinkler Systems." The applicant performed a code compliance review of

NFPA 13 and developed a justification to demonstrate that the PBNP fire protection system

testing requirements are changed such that an equivalent level of protection is achieved. The

staff compared the monitoring and trending recommendations of NFPA 13 to those of the

nuclear insurance carriers fire protection system testing and determined that the PBNP

monitoring and trending requirements exceed those of NFPA 13. On the basis of its review and

for the reasons discussed above, the staff found this exception acceptable.

The Fire Protection Program takes exception to the "acceptance criteria" program element for

GALL AMP XL.M27 in that PBNP does not specifically inspect for biofouling in its sprinkler

systems. GALL AMP XL.M27, as modified by ISG-04, states that no biofouling that could cause

corrosion in the sprinkler systems is to exist.

The staff determined that the applicant takes actions to minimize biofouling in fire system

components. These actions include flushing, performance testing, inspections, and chlorination

when circulation water temperature exceeds 45 "F. The staff verified that PBNP plans to

inspect or replace sprinkler heads prior to exceeding their 50-year service life in accordance

with NFPA 25. If the sprinkler head is not replaced, the required testing will be repeated at

10-year intervals. The inspection of the sprinkler heads will identify any corrosion, which will

then be addressed in accordance with the PBNP corrective action program and, therefore,

accomplish the goal that no biofouling that could cause corrosion will exist. Periodically, the

sprinkler lines are partially flushed, and prior to replacement they will be drained, at which time,

any loose corrosion products will be evident. The disposition of any corrosion products that are

detected will be in accordance with the applicant's corrective action program. On the basis of

its review and for the reasons discussed above, the staff found this exception acceptable.

In LRA Section B2.1.10, the applicant stated that its Fire Protection Program is consistent with

GALL AMP XI.M26 and GALL AMP XL.M27, with enhancements. The applicant stated that, for

the "scope of the program" and 'detection of aging effects" program elements, enhancements

include revisions to various existing implementing documents to add specific inspections,

monitoring and trending requirements, and/or frequency adjustments based on operating

experience. Additionally, new implementing documents will be created to cause inspections of

selected components and portions of the fire suppression piping. An evaluation will be

performed to determine which non-Appendix R safe shutdown fire dampers may need to be

added to the program. The staff considered these types of enhancements to be administrative

enhancements that do not require staff review.

QOerating Experience. The staff reviewed the applicant's operating experience for the Fire

Protection Program.

The applicant stated that plant-specific operating experience has shown that after thirty plus

years of operation the fire protection system performed well. There have been some cases of

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small pipe threaded connection leaks, small pipe external corrosion leaks, spray nozzles for the

transformer deluge system plugged due to rust scale build-up, and cracked piping and fittings.

Pinhole leaks have also been found on the 10-inch fire water supply header and sprinkler heads

have been found to leak. These discrepancies were discovered in the last 13 years and were

repaired using maintenance work orders.

The applicant also stated that its Fire Protection Program has been an ongoing program at

PBNP. The program has evolved over the years of plant operation and has been enhanced by

the implementation of 10 CFR Part 50, Appendix R and 10 CFR 50.48. The overall

effectiveness of the program is demonstrated by the operating experience of SSCs that are

subject to the Fire Protection Program.

Furthermore, the applicant performed a review of NRC inspection reports, QA audit/surveillance

reports, and self-assessments since 1999 performed to determine the overall effectiveness of

the program. The results of this review indicated that the overall effectiveness of the Fire

Protection Program was good.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical staff to verify that the plant-specific operating experience did not reveal

any degradation not bounded by industry experience. The staff found that the operating

experience is consistent with industry practice. On the basis of its review of the above industry

and plant-specific operating experience, the staff concluded that the Fire Protection Program,

with the identified exceptions, will adequately manage the aging effects that are identified in the

LRA for which this AMP is credited.

FSAR Supplement. In LRA Section Al 5.2.10, the applicant provided the FSAR supplement for

the Fire Protection Program. The staff reviewed these sections and determined that the

information in the FSAR supplement provides an adequate summary of the program activities.

The staff found these sections of the FSAR supplement meet the requirements of

10 CFR 54.21 (d).

Conclusion. On the basis of its review and audit of the applicant's program, the staff found that

those program elements for which the applicant claimed consistency with the GALL Report are

consistent with the GALL Report. In addition, the staff reviewed the exceptions and the

associated justifications and determined that the AMP, with the exceptions, is adequate to

manage the aging effects for which it is credited. The staff found that the applicant had

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff also reviewed the FSAR supplement for this AMP

and found that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

3.0.3.2.11 Flow-Accelerated Corrosion Program

Summarv of Technical Information in the Application. The applicant's flow-accelerated

corrosion program is described in LRA Section B2.1.1 1, "Flow-Accelerated Corrosion Program."

The applicant stated that this is an existing program. As modified by letters dated April 8 and

June 9, 2005, the applicant stated that this program is consistent, with exceptions and

enhancements, with GALL AMP XI.M17, "Flow-Accelerated Corrosion."

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The applicant stated that the Flow-Accelerated Corrosion Program manages aging effects due

to flow-accelerated corrosion (FAC) on the internal surfaces of carbon or low-alloy steel piping,

elbows, reducers, expanders, and valve bodies that contain high energy fluids (both

single-phase and two-phase). The applicant also stated that the program implements the EPRI

guidelines in NSAC-202L-R2, "Recommendations for an Effective Flow-Accelerated Corrosion

Program," for an effective Flow-Accelerated Corrosion Program and includes (a) an analysis

using a predictive code such as CHECWORKS to determine critical locations, (b) baseline

inspections to determine the extent of thinning at these locations, (c) follow-up inspections to

confirm the predictions, and (d) repairing or replacing components, as necessary.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. Details of the staff's audit evaluation are documented in the

staff's audit and review report.

In LRA Section B2.1.11, the applicant stated that its Flow-Accelerated Corrosion Program is

consistent with GALL AMP XI.1 7, with enhancements. The applicant stated that, for the "scope

of the program" program element, it will enhance the Flow-Accelerated Corrosion Program to

add SG feedwater nozzles and attached reducers to the scope of the Flow-Accelerated

Corrosion Program.

GALL AMP Xi.17 states that, for "scope of the program" program element, the

Flow-Accelerated Corrosion Program, described by the EPRI guidelines in NSAC-202L-R2,

includes procedures or administrative controls to assure that the structural integrity of all carbon

steel lines containing high-energy fluids (two phase as well as single phase) is maintained.

The applicant stated that its SG AMR identified the need to include the SG feedwater nozzles

and attached reducers to the Flow-Accelerated Corrosion Program.

As documented in the audit and review report, the staff reviewed the information provided by

the applicant and held discussions with the applicant's technical staff. The staff concluded that

this enhancement to the Flow-Accelerated Corrosion Program scope is acceptable and will

ensure that wall thinning in Units 1 and 2 SG feedwater nozzles will be managed according to

the guidelines In NSAC-202L-R2 and that appropriate administrative controls will be in place to

ensure that the structural integrity is maintained in carbon steel, high-energy locations. On this

basis, the staff found this enhancement acceptable.

The staff's review of LRA Section B2.1.11 identified an area in which additional information was

necessary to complete the review of the applicant's program elements. The applicant

responded to the staff's RAI as discussed below.

RAI B2.1.11-1.' During the audit, the staff noted that for the "acceptance criteria" program

element, it is unclear how the applicant calculates the minimum permitted wall thickness and

uses in its analysis for FAC. In RAI B2.1.11-1, dated March 30, 2005, the staff requested the

applicant to clarify its wall thickness calculation and its uses.

The staff's concern was referred to the Region IlIl staff, which performed its'AMR/AMP onsite

inspection during the weeks of March 7 and 21, 2005. The applicant clarified its methodology.

The applicant stated that the minimum wall calculations are performed using the design

pressure, which is greater than the operating pressure and demonstrates that the actual

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measured wall thickness is greater than the minimum thickness required by the maximum hoop

stress. If degradation is detected such that the wall thickness is less than or equal to 87.5

percent of nominal wall thickness for safety-related piping or 60 percent for nonsafety-related

piping, additional examinations will be performed in adjacent areas to bound the thinning. The

applicant will provide its justification to confirm that the minimum wall thickness will be

maintained for the period of extended operation. This was identified as confirmatory item

(Cl) B2. 1.1 1-1.

In its response to Cl B2.1.1-11, by letter dated June 9, 2005, the applicant stated that during

the Region IlIl AMR/AMP onsite inspection, a detailed review of the Flow-Accelerated Corrosion

Program was completed. As a result of that review and discussions between the Region Ill

staff, the License Renewal Branch, and Division of Engineering personnel, PBNP provided a

clarification to LRA Section B2.1.1.1 1, 'Flow-Accelerated Corrosion Program," by letter dated

April 8, 2005. Based upon discussions with the NRC staff on May 3, 2005, a revision to the

April 8, 2005, letter was identified as being needed to clarify the intent of the sample expansion

criterion. By letter dated June 9, 2005, the applicant provided a modified text to clarify its

program. The revised text replaced the discussion under the program element Monitoring and

Trendingm in LRA Section B2.1.1 1, as follows:

If degradation is detected such that the wall thickness is less than or equal to 87.5% of

nominal wall thickness for safety-related piping, additional examinations will be

performed in adjacent areas to bound the thinning. For both safety-related and

non-safety related piping, additional examinations will be performed in adjacent areas to

bound the thinning if the remaining service life, based on the code minimum allowable

wall thickness, is less than one operating cvcle. The sample size will also be expanded

for non-safety related piping i degradation is detected such that the wall thickness is

less than or equal to 60% of nominal wall thickness. This covers situations where the

code minimum allowable wall thickness may be less than 60% of nominal wall thickness

for non-safety related piping. The expansion of the sample size should include a

minimum of the next two most susceptible components in that CHECWORKS line, any

component within two pipe diameters downstream (upstream if expander), or like

components in parallel trains. If the initial expansion finds additional components with

significant loss of material due to FAC, the examination scope is expanded further.

This element includes exceptions to the corresponding NUREG-1801 aging

management program element. NUREG-1 801 states: "If degradation is detected such

that the wall thickness is less than the minimum predicted thickness, additional

examinations are performed in adjacent areas to bound the thinning.' Literal

interpretation of this sample expansion criteria is not practical in many cases. If very

little degradation is predicted, measured wall thickness may be less than the predicted

thickness even though the calculated life of the affected component may exceed the

operating life of the plant. In this case, sample expansion would not be warranted.

The FAC program at PBNP implements the EPRI guidelines in NSAC-202L-R2, which

recommends increasing the sample size when inspections of the sample detect

significant FAC wear. In the PBNP FAC program, significant FAC wear is defined as

FAC resulting in a wall thickness of less than or equal to 87.5% of nominal wall

thickness for safety related piping. For both safety related and non-safety related

piping, additional examinations will be performed in adjacent areas to bound the thinning

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if the remaining service life, based on the code minimum allowable wall thickness, is

less than one operating cycle. The sample size will also be expanded for non-safety

related piping if degradation is detected such that the wall thickness is less than or equal

to 60% of nominal wall thickness. This covers situations where the code minimum

allowable wall thickness may be less than 60% of nominal wall thickness for non-safety

related piping. This criterion for sample expansion is acceptable because it specifies a

wall thickness criterion and requires projection of inspection results to the next

inspection opportunity consistent with industry guidance. Therefore, PBNP meets the

intent of this NUREG-1 801 aging management program element.

The staff reviewed the applicant's responses to RAI B2.1.1-11, its exception to the GALL

Report, and the final text to be included in the AMP, and concluded that the applicant

appropriately defined the program and demonstrated that the program, as defined, provides

reasonable assurance that structural integrity will be maintained. The staff's concern is

resolved; therefore, Cl B2.1.1-11 is closed.

The applicant also stated that for the udetection of aging effects" and "acceptance criteria"

program elements, enhancements include revising procedures to ensure congruence with the

guidelines of NSAC-202L-R2 and provide better references to the input data sets.

Enhancements also include (1) clarification of the program requirements for SG nozzles and

reducers and more stringent controls placed on program basis documentation and software,

and (2) revise procedures to require a local thinning evaluation if the measured wall thickness is

less than t-min. The staff considered these types of enhancements to be administrative

enhancements that do not require staff review.

Oerating Experience. The staff reviewed the applicant's operating experience for the

Flow-Accelerated Corrosion Program.

The applicant stated that it performed a comprehensive review of industry issues and service

and its relevance to PBNP, including wall-thinning problems in single-phase systems In

feedwater and condensate systems, two-phase piping in extraction steam lines, and moisture

separation reheater and feedwater heater drains. The applicant's plant-specific operating

experience review refers to a single event involving a feedwater heater steam leak at Unit 1 in

1999 due to steam impingement and FAC. Subsequent to the failure, inspections were

performed and repairs were made due to wall thinning. Unit 2 heater materials were

FAC-resistant, and no wall thinning was noted.

The staff noted that, based on its review of the LRA discussion of this plant-specific event, it

was not clear to the staff that the Flow-Accelerated Corrosion Program was effective in

detecting wall thinning in the Unit 1 feedwater heater prior to failure. In addition, it appears that

wall thinning in the other heaters was discovered and examined only after the first heater failed.

The applicant explained, during discussions between the staff and the applicant's technical

staff, that the Flow-Accelerated Corrosion Program did not detect this condition, as feedwater

heaters were not included within the scope of the program at the time. Immediately prior to this

event, PBNP was evaluating industry operating experience (OE) on feedwater heater

degradation. The timing of the industry OE did not allow for OE evaluation before the

occurrence of the event. The Flow-Accelerated Corrosion Program was revised to include

feedwater heaters within the scope of the program.

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The applicant stated that the Flow-Accelerated Corrosion Program identified component

thinning conditions that resulted in corrective actions being pursued prior to component failure.

The applicant described two examples where thinning in the main feedwater pumps and heater

drain tank pumps' mini recirculation lines was discovered, the inspection scope was expanded,

and sections of the lines were replaced with more corrosion-resistant materials. The applicant

stated that the most common enhancements to the program are associated with scope

additions and program process improvements resulting from Flow-Accelerated Corrosion

Program findings, industry operating experience, and internal assessment recommendations.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical staff to verify that the plant-specific operating experience did not reveal

any degradation not bounded by industry experience. On the basis of its review of the above

industry and plant-specific operating experience, the staff concluded that the Flow-Accelerated

Corrosion Program, with the identified enhancements, will adequately manage the aging effects

that are identified in the LRA for which this AMP is credited.

FSAR SuDplement. In LRA Section Al 5.2.11, the applicant provided the FSAR supplement for

the Flow-Accelerated Corrosion Program. The staff reviewed these sections and determined

that the information in the FSAR supplement provides an adequate summary of the program

activities. The staff found these sections of the FSAR supplement meet the requirements

10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant's program, the staff found that

those program elements for which the applicant claimed consistency with the GALL Report are

consistent with the GALL Report. In addition, the staff reviewed the exceptions and the

associated justifications and determined that the AMP, with exceptions, is adequate to manage

the aging effects for which it is credited. The staff found that the applicant had demonstrated

that the effects of aging will be adequately managed so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3). The staff also reviewed the FSAR supplement for this AMP and found that

it provides an adequate summary description of the program, as required by 10 CFR 54.21 (d).

3.0.3.2.12 Fuel Oil Chemistry Control Program

Summary of Technical Information in the Application. The applicant's Fuel Oil Chemistry

Control Program is described in LRA Section B2.1.12, "Fuel Oil Chemistry Control Program."

The applicant stated that this is an existing program that is consistent, with exceptions and

enhancement, with GALL AMP XI.M30, "Fuel Oil Chemistry Control Program."

The applicant stated that the Fuel Oil Chemistry Control Program mitigates and manages aging

effects on the internal surfaces of fuel oil storage tanks and associated components in systems

that contain fuel oil. The program includes (1) surveillance and monitoring procedures for

maintaining fuel oil quality by controlling contaminants in accordance with applicable ASTM

standards, (2) periodic draining of water from fuel oil tanks, (3) periodic or conditional visual

inspection of internal surfaces or wall thickness measurements from external surfaces of fuel oil

tanks, and (d) one-time inspections of a representative sample of components in systems that

contain fuel oil.

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Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. Details of the staff's audit evaluation are documented in the

staff's audit and review report. Furthermore, the staff reviewed the exceptions and associated

justifications to determine whether the AMP, with the exceptions, remains adequate to manage

the aging effects for which it is credited.

In LRA Section B2.1.12, the applicant stated that its Fuel Oil Chemistry Control Program is

consistent with GALL AMP XI.M30, with exceptions. The Fuel Oil Chemistry Control Program

takes exception to the "preventive actions" program element for GALL AMP XI.M30 in that

PBNP does not routinely add corrosion inhibitors, stabilizers, or biocides to the fuel oil.

However, fuel oil additives would be considered if sample results indicate the

presence of these degradation mechanisms.

GALL AMP XI.M30 states that the quality of fuel oil is maintained by additions of biocides to

minimize biological activity, stabilizers to prevent biological breakdown of the diesel fuel, and

corrosion inhibitors to mitigate corrosion. Periodic cleaning of a tank allows removal of

sediments, and periodic draining of water collected at the bottom of a tank minimizes the

amount of water and the length of contact time. Accordingly, these measures are effective in

mitigating corrosion inside diesel fuel oil tanks. Coatings, if used, prevent or mitigate corrosion

by protecting the internal surfaces of the tank from contact with water and microbiological

organisms.

The applicant stated that its Fuel Oil Chemistry Control Program is geared to the discovery and

correction of conditions that could lead to degradation of fuel oil system components.

Accumulated water is periodically removed from the tanks. Draining of accumulated water will

also remove sediments from the tanks. The quality of new fuel oil is verified and the quality of

stored fuel oil is periodically checked. These actions will mitigate loss of material in the fuel oil

tanks and other components.

As documented in the audit and review report, the applicant stated that if tank wall and bottom

thickness are determined via UT measurements from outside the tank, there is no need to

remove the tank (and associated equipment) from service and drain, clean, and inspect the

inside of the tank. Periodic removal of free water and sediment via tank drain valves or via use

of a bottom sample thief are expected to minimize conditions and environment conducive to

tank corrosion.,

Additionally, the applicant stated that the EDG below-ground tanks and underground tank are

drained and inspected only if deemed necessary based on the results of the fuel oil sample

analysis or as recommended by the system engineer. The staff found this to be acceptable

based on the inspection results of above-ground tanks, which are considered to be in a more

severe environment and have shown no appreciable material loss in more than 30 years of

service. Additionally, wall thickness measurements of the underground tank indicate that no

appreciable material loss has occurred in more than 30 years of service. Significant

degradation of the inside surfaces of the EDG below-ground tanks and underground tank, or

conditions expected to cause such degradation, would be evidenced by the quarterly particulate

and stability oil sample analysis results and/or identified by routine inspections or tests

performed on supported equipment, which is monitored by the system engineer. There are no

expected aging effects for the outside surface of the EDG below-ground tanks because they

are encased in concrete.

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In addition, the applicant indicated that operating experience validates that there is no need for

chemical addition to the fuel oil system; the applicant continues to monitor operations for

indications of aging conditions to warrant chemical addition and will do so if deemed necessary.

Therefore, the applicant stated that no chemical addition is the preferred method at this time.

As documented in the audit and review report, the staff reviewed the information provided by

the applicant and held discussions with the applicant's technical staff. On the basis of its review

and on plant-specific operating history, the test results and the results of contaminant

monitoring which shows no indication of aging in the various tanks, the staff found this

exception acceptable.

The applicant's Fuel Oil Chemistry Control Program also takes exception to the "parameters

monitored or inspected" and "acceptance criteria" program elements for GALL AMP XL.M30 in

that the applicant (1) uses only D 2709 to determine the amount of contamination due to water

and sediment in diesel fuel, (2) uses D 6217 in lieu of D 2276 for particulate determination, (3)

uses a filter with a pore size no larger than 0.8 micron, and (4) uses ASTM D 2274 for stability

analysis.

GALL AMP XL.M30 states that the AMP should monitor fuel oil quality and the levels of water

and microbiological organisms in the fuel oil, which cause the loss of material of the tank

internal surfaces and are the principal parameters relevant to maintaining tank structural

integrity. ASTM Standard D4057 is used for guidance on oil sampling. ASTM Standards

D1796 and D2709 are used for determination of water and sediment contamination in diesel

fuel. For determination of particulates, modified ASTM Standard D2276, Method A, is used.

The staff reviewed and compared the referenced ASTM Standards Dl 796, D2709, D6217,

D2276, and D4057; and the information provided by the applicant, as documented in the audit

and review report. On the basis of its review, the staff found that ASTM D2709 is a test method

that addresses the determination of volume of free water and sediment in middle distillate fuels.

This standard has been revised since the issuance of the GALL Report. It is no longer a

"pass/fail" test but actually quantifies the amount of water and sediment measurable to 0.01 mL.

The staff reviewed the results of the last quarterly inspection report and found that the test as

run is sensitive enough to verify that the water/sediment content is less than the applicant's limit

of 0.05 percent. DI 796 provides another quantified method of analysis and is applicable to

higher viscosities of oil. Interviews with plant staff indicate that corrective actions are taken if

any water or particulate are found in the oil above the 0.05 percent limit. Because ASTM

D2709 meets the inspection criteria, the staff found this approach acceptable.

The applicant stated that ASTM D2276 as recommended in GALL AMP XL.M30 is applicable to

aviation fuel, whereas ASTM D6217 is applicable to middle distillate fuel used in diesel engines.

Therefore, with regard to the use of ASTM D2276 versus D6217, the staff agreed and found the

applicant's approach and basis for using Standard D6217 to be acceptable.

The applicant stated that it also uses a filter with a pore size no larger than 0.8 micron versus

GALL AMP XL.M30 recommendation of 3.0 micron, therefore, PBNP is more conservative. On

the basis that the applicant uses a more conservative filter, the staff found this acceptable.

The applicant also stated that it uses ASTM D 2274 for stability analysis. The level of

microbiological organisms in the fuel oil is not directly measured but can be inferred from the

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particulate and stability parameters. Since the applicant does not routinely add biocides, it

performs stability analysis to assess if biocides should be added. The staff reviewed the use of

the ASTM standard and agreed that applicant use of ASTM standard for stability analysis is

acceptable. On this basis, the staff found this exception acceptable.

The applicant's Fuel Oil Chemistry Control Program also takes exception to the "detection of

aging effects" program element for GALL AMP XI.M30 in that PBNP does not periodically

perform an internal inspection of all of the fuel oil tanks.

GALL AMP XI.M30 states that degradation of the diesel fuel oil tank cannot occur without

exposure of the tank internal surfaces to contaminants in the fuel oil, such as water and

microbiological organisms. Compliance with diesel fuel oil standards in the "parameters

monitored or inspected" program element and periodic multilevel sampling provides assurance

that fuel oil contaminants are below acceptable levels. Internal surfaces of tanks that are

drained for cleaning are visually inspected to detect potential degradation. However, corrosion

may occur at locations in which contaminants may accumulate, such as a tank bottom, and an

ultrasonic thickness measurement of the tank bottom surface ensures that significant

degradation is not occurring.

The applicant stated that day tanks for the diesel-driven fire pump and emergency diesel

generators are examined externally via UT wall thickness measurements, which the GALL AMP

XL.M30 program description describes as an acceptable verification program. Furthermore, the

applicant stated that the emergency diesel generator below-ground storage tanks and the

underground emergency fuel tank are drained and inspected only if deemed necessary based

on the trends indicated by the results of the fuel oil analysis, or as recommended by the system

engineer based on equipment operating experience. This is considered acceptable based on

the inspection results of the underground emergency fuel tank and the above-ground storage

tanks, which were inspected in 2000 and showed no appreciable material loss in over thirty

years of operation. The emergency diesel generator below-ground storage tanks are relatively

new tanks, which were installed in the 1994 time frame and are in a less severe environment

than the above-ground storage tanks.

The staff reviewed the information provided by the applicant, as documented in the audit and

report, and held technical discussion with the applicant's staff. On the basis of its review, the

staff determined that the applicant's Fuel Oil Chemistry Control Program does not require

periodic visual examinations and UT of all tanks. The program requires different measures for

different tanks, and no tanks require both periodic visual inspection and UT as recommended

by the GALL AMP XL.M30. On this basis, the staff found this exception acceptable.

In LRA Section B2.1.12, the applicant stated that its Fuel Oil Chemistry Control Program is

consistent with GALL AMP XL.M30, with enhancements., The applicant stated that, for the

"detection of aging effects" program element, enhancements include revision of existing

implementing documents and/or creation of new implementing documents to (1) periodically

drain water from the gas turbine starting and auxiliary diesel fuel tanks, (2) periodically drain

and inspect the gas turbine starting and auxiliary diesel fuel tanks and the two above-ground

storage tanks, and (3) periodically take UT thickness measurements of the EDG and

diesel-driven fire pump day tanks. The staff considered these types of enhancements to be

administrative enhancements that do not require staff review.

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Operating Experience. The staff reviewed the applicant's operating experience for the Fuel Oil

Chemistry Control Program.

The applicant stated that (1) the operating experience of some plants included identification of

water in the fuel, particulate contamination, and biological fouling, (2) a search of plant-specific

operating experience revealed past problems with sampling methods, which were corrected

with a revision to the sampling procedure, (3) problems were noted also with the particulate

levels of delivered fuel oil and were attributed to the fuel oil cloud point and cold weather, (4)

QA audits of the laboratory that performs the analysis of the fuel oil samples indicate that the

laboratory is performing satisfactorily, (5) the internals of the above-ground fuel oil tanks and

the underground emergency fuel tank were inspected in August 2000 and no significant rust

deposits, corrosion, or other obvious defects were found, (6) thickness measurements of the

underground emergency fuel tank and the bottom of the above-ground fuel oil tanks were

performed and indicated no significant loss of material, (7) there have been no identified

instances of component failure due to loss of material resulting from fuel oil contamination, and

(8) a review of NRC inspection reports, QA audit/surveillance reports, and self-assessments

since 1999 revealed no issues-or findings that could impact the effectiveness of the Fuel Oil

Chemistry Control Program.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical staff to verify that the plant-specific operating experience did not reveal

any degradation not bounded by industry experience. The staff found that the operating

experience is consistent with industry practice. On the basis of its review of the above industry

and plant-specific operating experience, the staff concluded that the Fuel Oil Chemistry Control

Program, with the exceptions identified above, will adequately manage the aging effects that

are identified in the LRA for which this AMP is credited.

FSAR Supolement. In LRA Section Al 5.2.12, the applicant provided the FSAR supplement for

the Fuel Oil Chemistry Control Program. The staff reviewed these sections and determined

that the information in the FSAR supplement provides an adequate summary of the program

activities. The staff found these sections of the FSAR supplement meet the requirements of

10 CFR 54.21 (d).

Conclusion. On the basis of its review and audit of the applicant's program, the staff found that

those program elements for which the applicant claimed consistency with the GALL Report are

consistent with the GALL Report. In addition, the staff reviewed the exceptions and the

associated justifications and determined that the AMP, with the exceptions, is adequate to

manage the aging effects for which it is credited. The staff found that the applicant had

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21(a)(3). The staff also reviewed the FSAR supplement for this AMP

and found that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

3.0.3.2.13 One-Time Inspection Program

Summary of Technical Information in the Application. The applicant's One-Time Inspection

Program is described in LRA Section B2.1.13, "One-Time Inspection Program." The applicant

stated that this is a new program that is consistent, with exceptions and enhancements, with

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GALL AMP XL.M32, "One-Time Inspection Program," and GALL AMP XI.M33, "Selective

Leaching of Materials."

The applicant stated that the One-Time Inspection Program addresses potentially long

incubation periods for certain aging effects and provides a means of verifying that an aging

effect is either not occurring or progressing so slowly as to have negligible effect on the

intended function of the structure or component. Hence, the One-Time Inspection Program

provides measures for verifying an AMP is not needed, verifying the effectiveness of an existing

program, or determining that degradation is occurring that will require evaluation and corrective

action.

The applicant further stated that the program elements include (1) determination of appropriate

inspection sample size, (2) identification of inspection locations, (3) selection of examination

technique, with acceptance criteria, and (4) evaluation of results to determine the need for

additional inspections or other corrective actions. The inspection sample includes locations

where the most severe aging effect(s) would be expected to occur. Inspection methods may

include visual (or remote visual), surface or volumetric examinations, or other established NDE

techniques.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. Details of the staff's audit evaluation are documented in the

staff's audit and review report. Furthermore, the staff reviewed the exceptions and associated

justifications to determine whether the AMP, with the exceptions, remains adequate to manage

the aging effects for which it is credited.

In LRA Section B2.1.13, the applicant stated the following with respect to the methods used to

monitor or inspect degradation of components under the One-Time Inspection Program:

For verification of the effectiveness of the Water Chemistry Control Program and the

Closed-Cycle Cooling Water System Surveillance Program for stagnant or low flow

areas and for verification of the effectiveness of the Fuel Oil Chemistry Control

Program, a visual examination or other appropriate NDE methodology will be used to

verify that degradation due to the applicable aging effects is not occurring.

The staff found that the applicant did not describe parameters directly related to the

degradation of a component as required by the GALL Report. The GALL Report states

that a link should be established between the degradation of the particular structure or

component intended function(s) and the parameter(s) being monitored.

During the audit, the staff requested the applicant to provide a description that clearly identifies

the link(s) between the parameters monitored or inspected and the aging effect for the

particular structure or component. The inspection method selected for the parameter to be

monitored shall be capable of measuring the parameter. The method is to be able to provide

data that are adequate to conclude that the aging effect is managed consistent with the CLB.

In its response, dated July 12, 2004, the applicant provided a table, included below, which will

be added to the LRA during its annual update, which links the aging effects/mechanisms

managed by the One-Time Inspection Program with the parameters monitored/inspected and

the measurement methodology. The inspection method identified is capable of measuring the

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parameter monitored and providing data that are adequate to conclude the aging effect is

managed consistent with the CLB. If an inspection method different from that listed in the table

below is used, the basis for the revised inspection method will be documented. The One-Time

Inspection Program manages these aging effects/mechanisms on the internal surfaces of

components. Visual inspections are performed only when the components are drained/opened

and the component surface of interest is accessible. If degradation is identified through a visual

inspection, additional NDE may be performed to characterize the degradation and determine

the extent of the condition.

Table 3.0.3.2-1 Relationship of Parameters Monitored or Inspected and Aging Effect

Aging Effect Aging Mechanism Parameter Measurement Method

Monitored

Loss of Material Crevice Corrosion Wall Thickness Visual (VT-1I) and/or Volumetric

(RT or UT)

Loss of Material Galvanic Corrosion Wall Thickness Visual (VT-3) and/or Volumetric

(RT or UT)

Loss of Material General Corrosion Wall Thickness Visual (VT-3) and/or Volumetric

__ (RT or UT)

Loss of Material MIC Wall Thickness Visual (VT-3) and/or Volumetric

(RT or UT)

Loss of Material Pitting Corrosion Wall Thickness Visual (VT-1) and/or Volumetric

(RT or UT)

Loss of Material Selective Leaching Wall Thickness Hardness test (per response to

RAI B2.1.13-1), Visual (VT-3)

and/or Volumetric (RT or UT)

Loss of Material Erosion Wall Thickness Visual (VT-3) and/or Volumetric

(RT or UT)

Loss of Heat Transfer Fouling Tube Fouling General or Remote Visual

Cracking SCC Cracks Volumetric (RT or UT)

Loss of Preload Stress Relaxation Dimension Changes Visual (VT-3)

In addition, the staff, based upon a review of the "parameters monitored element" for the

One-Time Inspection Program, was unable to find a statement that indicated that the NDE

inspections performed as part of this AMP would be conducted in accordance with the

requirements of the ASME Code and 10 CFR Part 50, Appendix B. The staff requested the

applicant to provide verification that the NDE inspections performed as part of the One-Time

Inspection Program will be conducted in accordance with the requirements of the ASME Code

and 10 CFR Part 50, Appendix B, or state that PBNP is taking an exception to the GALL Report

and provide its technical justification.

In its response, dated July 12, 2004, the applicant stated that the NDE exams performed as a

part of the One-Time Inspection Program will be conducted in accordance with the

requirements of ASME Code Section Xi and 10 CFR Part 50, Appendix B, except for the

general or remote visual examinations. The general or remote visual examinations for loss of

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heat transfer due to fouling will be performed in accordance with the requirements of ASME

Code Section V and 10 CFR Part 50, Appendix B.

In LRA Section B2.1.13, the applicant stated that Its One-Time Inspection Program is consistent

with GALL AMP XI.M32, with exceptions. The One-Time Inspection Program takes exception

to the "scope of the program" and "detection of aging effects" program elements for GALL AMP

XL.M32 in that examination of nonexempt small-bore ASME Code Class 1 and 2 piping will be

addressed within the applicant's ASME Code Section Xi, Subsections IWB, IWC, and IWD

Inservice Inspection Program, which includes volumetric examinations performed in accordance

with RI-ISI requirements.

GALL AMP XL.M32 states the program includes measures to verify that unacceptable

degradation is not occurring, thereby validating the effectiveness of existing AMPs or confirming

that there is no need to manage aging-related degradation for the period of extended operation.

The structures and components for which one-time inspection is intended to verify the

effectiveness of the AMPs have been identified in the GALL Report. Examples include small

bore piping in the reactor coolant system or the feedwater system components in boiling water

reactors (BWRs) and PWRs. The GALL Report includes piping less than 4 inches in diameter

as small bore piping.

The staff reviewed the SER documented in a letter from NRC to PBNP, NPoint Beach Nuclear

Power Plant, Units 1 & 2 - Evaluation of Risk Informed Inservice Inspection Program

(ML030210167)," dated July 2, 2003. The staff determined that the plant's augmented

programs for FAC and high-energy break exclusion piping are not subsumed into the RI-ISI

program and remain unaffected. The degradation mechanisms identified in the RI-ISI submittal

included thermal fatigue, thermal transients, IGSCC, PWSCC, and FAC. These aging effects

were compared with the aging effects identified in one of the RI-ISI programs (EPRI

TR-1 06706). All aging effects addressed by the One-Time Inspection Program were found to

be included in the scope of aging effects managed by the RI-ISI program. The applicant also

clarified that the RI-ISI program addresses only the Class 1 and 2 piping welds.

In LRA Section B2.1.13, the applicant stated that its One-Time Inspection Program is consistent

with GALL AMP XL.M33, with exceptions. The One-Time Inspection Program takes exception

to the "scope of the program," "parameters monitored or inspected," and "detection of aging effects" program elements such that hardness measurements may be performed in accessible

locations to confirm the absence of selective leaching and determine material properties, which

can be used in component functionality assessments. The internal surfaces of susceptible

components may not be accessible for hardness measurements due to the size of the

component. Therefore, only visual inspections are required by the program.

GALL AMP XI.M33 states, for the "scope of the program" program element, this AMP

determines the acceptability of the components that may be susceptible to selective leaching

and assess their ability to perform the intended function during the period of extended

operation. The GALL Report includes a one-time hardness measurement of a selected set of

components to determine whether loss of material due to selective leaching is not occurring for

the period of extended operation. GALL AMP XL.M33 states, for the "parameters monitored or

inspected" program element that the one-time visual inspection and hardness measurement

include close examination of a select set of components to determine whether selective

leaching occurred and whether the resulting loss of strength and/or material will affect the

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intended functions of these components during the period of extended operation. Selective

leaching generally does not cause changes in dimensions and is difficult to detect. However, in

certain brasses it causes plug-type de-zincification, which can be detected by visual inspection.

One acceptable procedure is to visually inspect the susceptible components closely and

conduct Brinell hardness testing on the inside surfaces of the selected set of components to

determine if selective leaching occurred. If it is occurring, an engineering evaluation is initiated

to determine acceptability of the affected components for further service. Further evaluation for

the "detection of aging effects" program element is documented in RAI B2.1.13-1, below.

The staff's review of LRA Section B2.1.13 identified an area in which additional information was

necessary to complete the review of the applicant's program elements. The applicant

responded to the staff's RAI as discussed below.

During the audit, the staff conducted discussions concerning this exception with PBNP technical

staff. The staff further evaluated this exception and was unable to reconcile how leaching of

the subject components would be effectively managed using only visual inspection; that is,

without performance of hardness testing on the inside surfaces of the selected set of

components. The inability to reconcile this exception is predicated on GALL AMP XL.M33,

which indicates that visual inspections are generally unable to detect leaching. However, the

staff acknowledges that components with limited accessibility may be one factor in choosing the

"selected set of components" upon which the hardness tests are to be performed. The PBNP

exception indicates that "hardness measurements may be performed," which therefore, makes

hardness testing optional.

RAI B2.1.13-1. In RAI B2.1.13-1, dated September 16, 2004, the staff requested the applicant

to demonstrate that visual inspection alone will guarantee detection of leaching in cast iron and

brass materials. Otherwise, the staff requested the applicant to indicate whether or not it will

p&rform a one-time visual inspection and hardness measurement on a selected set of

components, of each material type, to determine whether selective leaching occurred and

whether the resulting loss of strength and/or material will affect the intended functions of these

components during the period of extended operation.

In its response, dated October 15, 2004, the applicant stated that a one-time visual inspection

and hardness measurement will be performed on accessible locations of a select set of

components of each material type (e.g., cast iron and brass) to determine whether selective

leaching occurred and whether the resulting loss of strength and/or material will affect the

intended functions of these components during the period of extended operation. The internal

surfaces of susceptible components may not be accessible for hardness measurements due to

the size of the component. Therefore, one of the factors used in choosing the selected set of

components to be inspected for selective leaching will be the accessibility of the internal surface

of the component for hardness testing. Hardness measurements will be performed in

accessible locations to confirm the absence of selective leaching and determine material

properties that can be used in component functionality assessments.

Furthermore, the applicant stated that during the AMR process it was not always possible to

determine whether the cast iron components in question were constructed of gray or ductile

cast iron. In many cases the material specification only stated cast iron. In these cases, PBNP

conservatively assumed that the material was gray cast iron and susceptible to selective

leaching. Should further material evaluation determine that the material is ductile cast iron and,

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therefore, not susceptible to selective leaching, these components would be removed from the

selected set of components to be inspected for selective leaching.

The staff reviewed the information provided by the applicant and the RAI response discussed

above, as documented in the audit and review report. On the basis of its review, the staff found

this exception acceptable. The staff's concerns described in RAI B2.1.13-1 are resolved.

In LRA Section B2.1.13, the applicant stated that its One-Time Inspection Program is consistent

with GALL AMP XL.M32 and GALL AMP XL.M33, with enhancements. The applicant stated that,

for the ascope of the program" program element, enhancements include the creation of new

implementing documents required to provide those inspections necessary to manage aging of

components within the scope of license renewal. The staff considered this type of

enhancement to be an administrative enhancement that does not require staff review.

Operatina Experience. The staff reviewed the applicant's operating experience for the

One-Time Inspection Program.

The applicant stated that the One-Time Inspection Program is a new program to be

implemented before the current operating license expires. The NDE inspection methods that

will be used, such as visual (or remote visual), surface or volumetric, or other established

techniques, are consistent with industry practice.

The staff reviewed the information provided by the applicant, as documented in the audit and

review report. The staff found that the applicant uses a database to track plant operating

experience as well as industry operating experience.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical staff to verify that the plant-specific operating experience did not reveal

any degradation not bounded by industry experience. The staff concluded that the operating

experience is consistent with industry practice. On the basis of its review of the above industry

and plant-specific operating experience, the staff concluded that the One-Time Inspection

Program will adequately manage the aging effects that are identified in the LRA for which this

AMP is credited.

FSAR SuoDlement. In LRA Section Al 5.2.13, the applicant provided the FSAR supplement for

the One-TimelInspection Program. The staff reviewed these sections and the applicant's letter

dated October 15, 2004 and determined that the information in the FSAR supplement provides

an adequate summary of the program activities. The staff found these sections of the FSAR

supplement meet the requirements of 10 CFR 54.21 (d).

Conclusion. On the basis of its review, RAI response, and audit of the applicant's program, the

staff found that those program elements for which the applicant claimed consistency with the

GALL Report are consistent with the GALL Report. In addition, the staff reviewed the

exceptions and the associated justifications and determined that the AMP, with the exceptions,

is adequate to manage the aging effects for which it is credited. The staff found that the

applicant had demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the FSAR supplement

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for this AMP and found that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.0.3.2.14 Open-Cycle Cooling (Service) Water System Surveillance Program

Summarv of Technical Information in the APolication. The applicant's Open-Cycle Cooling

(Service) Water System Surveillance Program is described in LRA Section B2.1.14,

"Open-Cycle Cooling (Service) Water System Surveillance Program." The applicant stated that

this is an existing program that is consistent, with exceptions and enhancements, with GALL

AMP XI.M20, "Open-Cycle Cooling Water System."

The applicant stated that the Open-Cycle Cooling (Service) Water System Surveillance

Program relies on implementation of the recommendations of GL 89-13, "Service Water

System Problems Affecting Safety-Related Equipment," to ensure that the aging effects such

as loss of material due to general, pitting, and crevice corrosion, microbiologically induced

corrosion (MIC), and loss of heat transfer due to biologicalcorrosion product fouling (e.g.,

sedimentation, silting) caused by exposure of internal surfaces of metallic components in

cooling water systems to raw, untreated water will be managed for the period of extended

operation. The aging effects are managed through (1) surveillance and control of biofouling, (2)

verification of heat transfer by testing, and (3) routine inspection and maintenance program

activities to ensure that aging effects do not impair component intended function. The applicant

states that this program complies with PBNP responses to GL 89-13.

During the audit, the applicant stated that there is no lined/coated piping in the open-cycle

cooling (service) water system.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. Details of the staff's audit evaluation are documented in the

staff's audit and review report. Furthermore, the staff reviewed the exceptions and associated

justifications to determine whether the AMP, with the exceptions, remains adequate to manage

the aging effects for which it is credited.

In LRA Section B2.1.14, the applicant stated that its Open-Cycle Cooling (Service) Water

System Surveillance Program is consistent with GALL AMP XI.M20, with exceptions. The

Open-Cycle Cooling (Service) Water System Surveillance Program takes exception to the

"scope of the program" program element for GALL AMP XL.M20 in that not all of the

safety-related heat exchangers are tested to verify heat transfer capability by performing a heat

balance test.

GALL AMP XI.M20 states that, consistent with the guidelines of GL 89-13, the open-cycle

cooling water system program implements a periodic testing program for degraded heat

exchanger performance in order to verify heat transfer capabilities for heat exchangers relied

on to transfer heat from safety-related SSCs to the ultimate heat sink.

The applicant identified the following as in-scope components that will not receive routine heat

transfer capability testing: primary auxiliary building battery room vent coolers, turbine driven

auxiliary feed water pump turbine oil coolers, containment fan motor coolers, and emergency

diesel generators G01/G02 coolant heat exchangers. The applicant stated that, as an

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alternative, these small heat exchangers are periodically flushed or cleaned, and inspected as

part of regular maintenance.

The staff reviewed the regular maintenance activities that were proposed as an alternative to

periodic heat transfer verification testing for each of the heat exchangers identified in the

exception, as documented in the audit and review report. The applicant stated that the primary

auxiliary building battery room vent coolers and emergency diesel generators GO1/G02 coolant

heat exchangers are inspected and, if necessary, cleaned annually, and that the turbine-driven

auxiliary feed water pump turbine oil coolers and containment fan motor coolers are inspected

and, if necessary, cleaned every refueling outage. In addition, selected parameters are

monitored during periodic performance testing of the turbine-driven auxiliary feed water pumps

and emergency diesel generators. The turbine-driven auxiliary feed water pumps bearing oil

temperatures are recorded and compared against acceptance criteria and the emergency

diesel generators service water outlet temperature, coolant/service water differential pressure,-

lube oil temperature, and coolant temperature are recorded and trended. Inspection and

cleaning frequencies are adjusted if coolant temperatures trend upward.

On the basis of Its review, the staff concluded that these alternatives are consistent with

PBNP's responses to GL 89-13 and the applicant's proposed periodic maintenance, monitoring,

and trending is an acceptable alternative to periodic testing for degraded heat exchanger

performance. In addition, the staff determined that the proposed periodic inspection and

cleaning/flushing activities, and component functional testing will effectively manage fouling and

scaling aging effects and ensure that heat transfer capabilities are maintained. On this basis,

the staff found the exception acceptable.

In LRA Section B2.1.14, the applicant stated that its Open-Cycle Cooling (Service) Water

System Surveillance Program is consistent with GALL AMP XL.M20, with enhancements. The

applicant stated that, for the "detection of aging effects" program element, enhancements

include (1) verification that the implementing documents for activities contain a reference or

other link, (2) clarification of GL 89-13 commitments regarding the emergency diesel generator

G01/G02 coolant heat exchangers, and (3) revisions to existing call-ups to ensure evaluations

take place for the management of aging effects. The staff considered these types of

enhancements to be administrative enhancements that do not require staff review.

Operating Exnerience. The staff reviewed the applicant's operating experience for the

Open-Cycle Cooling (Service) Water System Surveillance Program.

The applicant stated that heat exchangers have experienced erosion/corrosion of end bells,

biofouling build-up, and silt accumulation. Erosion/corrosion has also been experienced at or

near throttled valves. Zebra mussels have been found and are controlled by the chlorination

system, copper ion generator treatment, and periodic cleaning of the heat exchanger tubes.

Piping systems have experienced corrosion, pitting, MIC, and sedimentation build-up especially

in low flow areas and stagnant dead legs off the main flow stream. These are controlled by

flushing, the chlorination system, and inspections. Cavitation/erosion of components is

monitored by using established NDE methods and components have been repaired and/or

replaced, as necessary.

The applicant also stated that plant-specific operating experience was reviewed and revealed

that condition reports and work orders were initiated to repair system leaks and/or to investigate

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component wall thinning due to corrosion. Deficiencies found in service water system

components were addressed via the corrective action program such that these deficiencies are

corrected so that they will not impede the component's intended function.

Furthermore, the applicant stated that a review of NRC inspection reports, QA

audit/surveillance reports, and self-assessments since 1999 revealed no other issues or

findings that could impact the effectiveness of the Open-Cycle Cooling (Service) Water System

Surveillance Program. As additional operating experience is obtained, lessons learned may be

used to adjust this program.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical staff to verify that the plant-specific operating experience did not reveal

any degradation not bounded by industry experience. The staff concluded that the operating

experience is consistent with industry practice. On the basis of its review of the above industry

and plant-specific operating experience, the staff concluded that the Open-Cycle Cooling

(Service) Water System Surveillance Program will adequately manage the aging effects that

are identified in the LRA for which this AMP is credited.

FSAR Supplement. In LRA Section Al 5.2.14, the applicant provided the FSAR supplement for

the Open-Cycle Cooling (Service) Water System Surveillance Program. The staff reviewed

these sections and determined that the information in the FSAR supplement provides an

adequate summary of the program activities. The staff found these sections of the FSAR

supplement meet the requirements of 10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant's program, the staff found that

those program elements for which the applicant claimed consistency with the GALL Report are

consistent with the GALL Report. In addition, the staff reviewed the exceptions and the

associated justifications and determined that the AMP, with the exceptions, is adequate to

manage the aging effects for which it is credited. The staff found that the applicant had

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff also reviewed the FSAR supplement for this AMP

and found that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

3.0.3.2.15 Reactor Coolant System Alloy 600 Inspection System Program

Summarv of Technical Information in the Application. The applicant's Reactor Coolant Alloy

600 Inspection System Program is described in LRA Section B2.1.16, "Reactor Coolant System

Alloy 600 Inspection System." In the LRA, the applicant stated that this is a new program that is

consistent, with exceptions and enhancements, with GALL AMP XI.Ml 1, "Nickel Alloy

Penetrations."

Staff Evaluation. In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information

included in LRA Section B2.1.16, regarding the applicant's demonstration of the Reactor

Coolant Alloy 600 Inspection System to ensure that the effects of aging, as discussed above,

will be adequately managed so that the intended functions will be maintained consistent with

the CLB throughout the period of extended operation.

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The staff's original basis for inspecting Alloy 600 reactor vessel head (RVH) penetration nozzles

in U.S. PWR is provided in GL 97-01, "Degradation of Control Rod Drive Mechanism Nozzle

and Other Vessel Head Penetrations," dated, April 1, 1997. Between November 2000 and

April 2001, subsequent to the issuance of GL 97-01, reactor coolant pressure boundary (RCPB)

leakage was identified from the RVH penetration nozzles of four U.S. PWR-design light water

reactor facilities. Supplemental examinations of the degraded nozzles indicated the presence

of circumferential cracks in four of the CRDM nozzles. These cracks initiated from the outer

surface of the nozzle, either in the associated J-groove weld or heat-affected-zone, and not

from the inside surface of the nozzle, as was assumed in the industry responses to GL 97-01.

These cracks penetrated through the nozzles and were the first identified instances of

circumferential cracking in U.S. RVH penetration nozzles. In NRC Bulletin 2001-01,

"Circumferential Cracking of Reactor Pressure Vessel Head (RVH) Penetration Nozzles,"

issued on August 3,2001, the staff discussed the generic safety significance and impact of

these cracks on RVH penetration nozzles and recommended that enhanced visual examination

or volumetric examination methods be used for the inspection of RVH penetration nozzles.

In March 2002, during a refueling outage at the Davis-Besse Nuclear Power Station, the

licensee reported the occurrence of reactor coolant leakage from an RVH penetration that

resulted in significant boric-acid-related wastage of the RVH. The wastage affected the entire

thickness of a localized area of the RVH around a penetration nozzle with the exception of the

RVH cladding. On March 18, 2002, the NRC issued Bulletin 2002-01, "Reactor Pressure

Vessel Head Degradation and Reactor Coolant Pressure Boundary Integrity," to owners of

PWR designs, requesting that the licensees address the impact of the Davis-Besse event on

the structural integrity of their RVHs and associated penetration nozzles. On August 9, 2002,

the staff issued Bulletin 2002-02, OReactor Pressure Vessel Head and Vessel Head Penetration

Nozzle Inspection Programs," to address additional technical issues resulting from the

Davis-Besse event. In Bulletin 2002-02, the staff specifically suggested that further augmented

inspections, more comprehensive than those suggested in Bulletin 2001-01, be performed on

RVH penetration nozzles. On February 11, 2003, the staff issued Order EA-03-009, "Issuance

of Order Establishing Interim Inspection Requirements for Reactor Pressure Vessel Heads at

Pressurized Water Reactors," to further define thefrequency and extent of examination of - nickel-based alloys and welds in the RPV heads due to PWSCC. On August 21, 2003, the staff

issued Bulletin 2003-02, "Leakage from Reactor Pressure Vessel Lower Head Penetrations and

Reactor Coolant Pressure Boundary Integrity," to advise licensees that RPV lower head

inspections may need to be supplemented with additional measures to assure that reactor

coolant pressure boundary (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. I *

During V.C. Summer refueling outage 12, in 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 Information Notices (IN) 2000-17 and 2000-17, Supplement 1, Udatod

October 18, 2000, and November 16, 2000, respectively, provide details of the V.0. Summer

RV hot-leg nozzle weld cracking event. Since the V.C. Summer main coolant loop weld

cracking event involves 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

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technology. An interim industry report, "PWR Materials Reliability Project Interim Alloy 600

Safety Assessment for US PWR Plants (MRP-44), Appendix 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 an SE dated June 14, 2001. The final industry report, "Alloy 82/182 Pipe Butt

Weld Safety Assessment for U.S. PWR Plant Designs (MRP-1 13)," was issued in July 2004.

Pending the staff's review of this report and additional UT inspection data from piping involving

Alloy 821182 weld material from the industry, the staff is pursuing resolution of this current

operating issue pursuant to 10 CFR Part 50.

The aging of RVH penetration nozzles and other Class 1 components made from nickel-based

alloys due to PWSCC is an emerging issue that is currently being evaluated and resolved by

the NRC and external stakeholders. The staff assessed whether the applicant's AMP

accounted for the effects of the Davis-Besse event and other applicable operating experience.

The staff reviewed the Reactor Coolant System Alloy 600 Inspection System Program against

the AMP elements found in the GALL Report, SRP-LR Section A.1.2.3, and SRP-LR

Table A.1-1 and focused on how the program manages aging effects through the effective

incorporation of 10 elements (i.e., program scope, preventive actions, parameters monitored or

inspected, detection of aging effects, monitoring and trending, acceptance criteria, corrective

actions, confirmation process, administrative controls, and operating experience). The Reactor

Coolant System Alloy 600 Inspection System Program takes exceptions to the following

program elements: (1) scope of the program, (4) detection of aging effects, (5) monitoring and

trending, and (7) operating experience.

The applicant indicated that the corrective actions, confirmation process, and administrative

controls are part of the site-controlled quality assurance program. The staff's evaluation of the

quality assurance program is discussed in SER Section 3.0.4. The remaining seven elements

are discussed below.

LRA Section B2.1.16 states that the Reactor Coolant System Alloy 600 Inspection Program is

consistent with the GALL Report, with enhancements. The applicant stated that enhancements

will include development of new implementing documents to meet the commitments made in

response to NRC Bulletins 2002-02,2003-02 and the requirements of NRC Order EA-03-009.

The staff considered this type of enhancement to be an administrative enhancement that does

not require staff review.

(1) Scope of the Program - The applicant stated that the Reactor Coolant System Alloy 600

Inspection Program scope included the control rod drive mechanism (CRDM) adapter

tubes, reactor vessel bottom head instrumentation penetrations and associated Inconel

attachment welds to the reactor vessel closure head or bottom head, Inconel 82/182

butt welds of the Alloy 600 CRDM adapter tube and bottom-mounted instrumentation

nozzles to stainless steel safe ends, Unit 2 SG vent nozzles and the associated Inconel

152 welds, and the Unit 2 Inconel 82/152 SG primary nozzle-to-safe end welds.

The staff noted that the applicant made commitments specific to degradation involved

with the Alloy 600 material and degradation in the RPV head J-groove welds. PBNP

committed to performing bare metal visual examinations of the reactor pressure vessel

head and nozzles of Units 1 and 2 in response to NRC Bulletins 2001-01 and 2002-02

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and indicated compliance with Order EA-03-009. Based on the discussion above, the

staff has concerns regarding the applicant's involvementwand developing issues

surrounding the 82/182 alloy welds and other Alloy 600 successors. Secondly, the

applicant stated that enhancements are scheduled for completion consistent with the

commitments made in the response to NRC Bulletins 2002-02 and 2003-02 and the

requirements of NRC Order EA-03-009, or prior to the period of extended operation, as

applicable.

The staff's review of LRA Section B2.1.16 identified an area in which additional

information was necessary to complete the review of the applicant's program elements.

The applicant responded to the staff's RAI as discussed below.

RAI 2.1.16-1. In RAI 2.1.16-1, dated November 17, 2004, the staff requested the

applicant to provide a commitment to assure that interim report UPWR Materials

Reliability Project Interim Alloy 600 Safety Assessment for US PWR Plants (MRP-44),

Appendix 1: Alloy 82/182 Pipe Butt Welds," and its final version will be used as part of

the basis for the Reactor Coolant System Alloy 600 Inspection Program. The

commitment should state that the Reactor Coolant System Alloy 600 Inspection

Program will be submitted 24 to 36 months prior to the period of extended operation for

staff review and approval to determine if the program demonstrates the ability to

manage the effects of aging pursuant to 10 CFR 54.21 (a)(3).

In its response, dated January 25, 2005, the applicant committed to use the interim

report "PWR Materials Reliability Project Interim Alloy 600 Safety Assessment for US

PWR Plant (MRP-44), Appendix 1: Alloy 82/182 Pipe Butt Welds," and its final version

as part of the basis for the Reactor Coolant System Alloy 600 Inspection Program. The

applicant further committed to submit the Reactor Coolant System Alloy 600 Inspection

Program to the NRC for staff review and approval 24 to 36 months prior to the period of

extended operation.-

On the basis of its review and the RAI response discussed above, the staff found this

acceptable. The applicant committed to submit the subject program 24 to 36 months

prior to the period of extended operation. The staff's concern in RAI 2.1.16-1 is

resolved.

The staff confirmed that the uscope of the program" program element satisfies the

criterion defined in the GALL Report and SRP-LR Section A.1.2.3.1. The staff

concluded that this program attribute is acceptable.

(2) Preventive Actions - The applicant stated that the program credited the Water Chemistry

Control Program for monitoring and control of reactor coolant water chemistry to

mitigate PWSCC. This element is consistent with the corresponding NUREG-1 801 AMP

element that recommends the use of the Water Chemistry Control Program to mitigate

cracking.

The staff confirmed that the "Preventive actions" program element satisfies the criterion

defined in the GALL Report and SRP-LR Section A.1.2.3.2. The staff concluded that

this program attribute is acceptable.

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(3) Parameters Monitored or Inspected - The applicant stated that the Reactor Coolant

System Alloy 600 Inspection Program incorporates routine inspections performed under

the ISI program and augmented inspections capable of detecting and sizing

non-through-wall cracks. For vessel head penetration (VHP), augmented visual

inspections for leakage and volumetric and/or surface exams are performed in

accordance with regulatory requirements and commitments. This element is consistent

with the corresponding NUREG-1801 AMP element that recommends the use of the ISI

Program to monitor for cracking. In addition, the applicant stated that testing will be in

accordance with regulatory requirements. The staff notes that the current regulatory

requirements under First Revised Order EA-03-009 exceed the ASME Code

requirements.

The staff confirmed that the "parameters monitored or inspected" program element

satisfies the criterion defined in the GALL Report and SRP-LR Section A.1.2.3.3. The

staff concluded that this program attribute is acceptable.

(4) Detection of Aging Effects - The applicant stated that it differed from the guidance in the

GALL Report in that it was using the methodology prescribed by NRC Order EA-03-009

rather than the model referenced in the GL 97-01 response. In addition, the

enhancements to the program include the development of new implementing documents

to meet the commitments made in response to NRC Bulletins 2002-02 and 2003-02.

Since these regulatory documents pertain primarily to nickel-based alloys in RPV heads,

the applicant indicated that performance of susceptibility assessments and development

of corrective action plans and/or inspections will be done for nickel-based components

and welds not addressed under the evaluations for the RPV head.

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. Since the V.C. Summer main coolant loop weld cracking event

involves 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), Appendix 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 SE dated

June 14, 2001. The final industry report, "Alloy 82/182 Pipe Butt Weld Safety

Assessment for U.S. PWR Plant Designs (MRP-1 13)," was issued in July 2004.

Pending the staff's review of this report and additional UT inspection data from piping

involving Alloy 82/182 weld material from the industry, the staff is pursuing resolution of

this current operating issue pursuant to 10 CFR Part 50. Based on its response to

RAI 2.1.16-1, dated January 25, 2005, and its associated commitment discussed under

the scope of the program, the staff concluded that this element is acceptable. The

staff's concern described in RAI 2.1.16-1 is resolved.

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The staff confirmed that the "detection of aging effects" program element satisfies the

criterion defined in the GALL Report and SRP-LR Section A.1.2.3.4. The staff

concluded that this program attribute is acceptable.

(5) Monitoring and Trending - The applicant stated that periodic RPV head inspections are

performed as required to meet commitments made in response to NRC Bulletin 2002-02

and the requirements of NRC Order EA-03-009. Periodic inspection of the lower RPV

dome will be conducted as described in PBNP's response to NRC Bulletin 2003-02.

Inspections of other components are based on the results of the susceptibility

assessment and corrective action plan. This element provides a more recent and

up-to-date methodology than that suggested by the GALL Report that discusses

GL 97-01.

The staff confirmed that the "monitoring and trending" program element satisfies the

criteria defined in the GALL Report and SRP-LR Section A.1.2.3.5. The staff concluded

that this program attribute is acceptable.

(6) Acceptance Criteria - The applicant stated that indications detected will be evaluated in

accordance with ASME Code Section Xl requirements. Additionally, if non-through-wall

cracks are detected by a volumetric inspection, the evaluation of the component's

acceptability for continued service will consider the most current crack growth rate

information. This is consistent with the GALL Report, which recommends evaluation in

accordance with ASME Code Section Xl. Also, NUREG-1801 recommends that if there

have been significant changes since the applicant's response to GL 97-01, the applicant

provide references to appropriate industry model revisions or provides updated

information on crack initiation and crack growth data and models.

The staff confirmed that the "acceptance criteria" program element satisfies the criteria

defined in the GALL Report and SRP-LR Section A.1.2.3.6. The staff concluded that

this program attribute is acceptable.

(10) Operating Experience - The applicant stated that extensive industry operating

experience had been reviewed in developing the Reactor Coolant System Alloy 600

Inspection Program. The applicant referred to PWSCC cracking in 82/182 alloy piping

butt weld (V.C. Summer), severe degradation in an RPV head (Davis Besse) and axial

cracking in reactor vessel bottom-mounted instrumentation (BMI) penetrations (South

Texas). The applicant also performed a justification for continued operation, and

revised existing guidance documents to provide more direction for responding to

increasing RCS leakage, and inspection of the Units 1 and 2 reactor vessel heads.

The staff's review of LRA Section B2.1.16 identified an area in which additional

information was necessary to complete the review of this program element. The

applicant responded to the staff's RAI as discussed below.

RAI 2.1.16-2. In RAI 2.1.16-2, dated November 17, 2004, the staff requested the

applicant to discuss its review of industry/plant operating experience and how it will

equate to the continued operation of the existing Units 1 and 2 RPV heads. If the heads

are to be replaced, please discuss your plans for the monitoring of the heads in

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accordance with current industry events, Owner's Groups activities and existing NRC

regulations or orders.

In its response, dated January 25, 2005, the applicant stated that the RPV heads would

be replaced during each unit's upcoming refueling outage in 2005. Furthermore, the

applicant stated that the replaced RPV heads would be inspected in accordance with the

requirements of NRC Order EA-03-009, uOrder Establishing Interim Inspection

Requirements for Reactor Pressure Vessel Heads at Pressurized Water Reactors,"

revised February 20, 2004. Finally, the applicant stated that NMC is actively

participating with the industry through the EPRI MRP efforts to develop long-term

inspection procedures for reactor vessel closure heads and their penetrations for U.S.

pressurized water reactor plants. The staff concluded that the replacement of the RPV

heads along with the commitment to monitor the new heads in accordance with the most

recent MRP guidelines and Order EA-03-009 provided the most conservative and

up-to-date methodology for inspecting due to PWSCC in CRDM penetrations.

Therefore, the staff considers the applicant's response to RAI 2.1.16-2 acceptable. The

staff's concern described in RAI 2.1.16-2 is resolved.

The staff confirmed that the "operating experience" program element satisfies the

criteria defined in the GALL Report and SRP-LR Section A.1.2.3.10. The staff

concluded that this program attribute is acceptable.

FSAR Supplement. In LRA Section Al 5.2.1.16, the applicant provided the FSAR supplement

for the Reactor Coolant System Alloy 600 Inspection Program. The staff reviewed these

sections and determined that the information in the FSAR supplement provides an adequate

summary of the program activities. The staff found these sections of the FSAR supplement

meet the requirements of 10 CFR 54.21 (d).

Conclusion. On the basis of its review, the RAI responses discussed above, and its audit of the

applicant's program, the staff found that the applicant had demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The

staff concluded that the applicant's commitment to submit the Reactor Coolant System Alloy

600 Inspection Program 24 to 36 months prior to the period of extended operation is

acceptable. This program will demonstrate that the effects of aging, associated with the Alloy

600 Class 1 components, will be adequately managed. The staff also reviewed the FSAR

supplement for this AMP and found that it provides an adequate summary description of the

program, as required by 10 CFR 54.21(d).

3.0.3.2.16 Reactor Vessel Internals Program

Summary of Technical Information in the Application. The applicant's Reactor Vessel Internals

Program is described in LRA Section B2.1.17, "Reactor Vessel Internals Program." In the LRA,

the applicant stated that this is an existing program that is consistent, with exceptions and

enhancements, with GALL AMP XL.M13, "Thermal Aging and Neutron Irradiation Embrittlement

of Cast Austenitic Stainless Steel (CASS)," and GALL AMP XI.M1 6, "PWR Vessel Internals."

The applicant stated that the Reactor Vessel Internals Program manages the aging effects for

both non-bolted and bolted reactor vessel internal (RVI) components. The program provides

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for: (1) inservice Inspection (ISI) in accordance with ASME Code Section Xl requirements

including supplemental examinations on the leading locations of hon-CASS components with

respect to irradiation-assisted stress corrosion cracking (IASCC) and irradiation embrittlement

and the leading locations of CASS components with respect to fluence and thermal aging

embrittlement screening criteria; (2) evaluations that will identify leading locations with respect

to IASCC and irradiation embrittlement and thermal aging embrittlement; (3) the development

and implementation of appropriate nondestructive examination (NDE) techniques and

examination schedule for these locations; (4) baffle-former and barrel-former bolt evaluations

that will determine the acceptability of the current arrangement or if ultrasonic examination

and/or replacement of these bolts is necessary; and (5) monitoring and control of reactor

coolant water chemistry in accordance with the Water Chemistry Control Program to mitigate

SCC or IASCC.

The applicant stated that this program is credited by the Bolting Integrity Program for the

inspection of bolting internal to the RV. In addition to the requirements of ASME Code

Section Xl, Subsection IWB, this program monitors for loss of preload caused by stress

relaxation of bolted joints and specifically addresses cracking in baffle/barrel former bolts. This

program also credits the One-Time Inspection Program for the management of stress

relaxation of the lower internals hold-down spring.

Furthermore, the applicant stated that it will actively participate in industry groups such as the

EPRI MRP RI-ITG and the Westinghouse Owners' Group, who are studying RVI materials

degradation issues. The applicant also will implement NRC-approved industry activities

resulting from the MRP efforts, as appropriate, to manage any applicable aging effects

identified through the MRP effort. The applicant will continue to monitor industry research on

the significance of void swelling and augmented examinations for void swelling based on the

results and recommendations of the industry research.

In the LRA and in NMC clarification letter, dated July 12, 2004, the applicant stated its Reactor

Vessel Internals Program is based on the following industry initiatives and attributes:

* NMC will continue to participate in the industry's initiatives intended to clarify the nature

and extent of aging mechanisms potentially affecting RVIs.

* NMC will incorporate the results of these initiatives (to the extent that they are applicable

to the PBNP RVIs) into the scope, inspection requirements (including inspection

locations, methods, qualifications, and frequencies), acceptance criteria, and corrective

actions for the Reactor Vessel Internals Program.

* NMC will submit an inspection plan for the PBNP Reactor Vessel Internals Program for

NRC review and approval at least two years prior to entering the period of extended

operation.

Staff Evaluation. In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information

included in LRA Section B2.1.17 regarding the applicant's demonstration that the Reactor

Vessel Intemals Program will ensure that the effects of aging, as discussed above, will be

adequately managed so that the intended functions will be maintained consistent with the CLB

throughout the period of extended operation.

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The staff reviewed the Reactor Vessel Internals Program against the AMP elements found in

the GALL Report, SRP-LR Section A.1.2.3 and SRP-LR Table A.1 -1 and focused on how the

program manages aging effects through the effective incorporation of the 10 elements (i.e.,

program scope, preventive actions, parameters monitored or inspected, detection of aging

effects, monitoring and trending, acceptance criteria, corrective actions, confirmation process,

administrative controls, and operating experience). The PBNP Reactor Vessel Internals

Program takes exceptions to the following program elements: (1) scope of the program, (4)

detection of aging effects, (5) monitoring and trending, and (6) acceptance criteria.

The applicant indicated that the corrective actions, confirmation process, and administrative

controls are part of the site-controlled quality assurance program. The staff's evaluation of the

quality assurance program is discussed in SER Section 3.0.4. The remaining seven elements

are discussed below.

(1) Scope of the Program - The applicant stated that the Reactor Vessel Internals Program

is an existing program credited with the management of the following aging effects (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 identified reactor vessel internals (RVIs) major components as upper

internals and lower intemals. The following RVI components are within the scope of the

Reactor Vessel Internals Program.

Lower internals major components:

* baffle and former plates * diffuser plate

* baffle-former and * lower core plate

barrel-former bolts * lower support forging

* bottom-mounted * lower support plate column

instrumentation columns * secondary core support

* core barrel flange * thermal shield

* core barrel outlet nozzles * upper and lower core barrel

Upper internals major components:

* control rod guide tubes * upper support columns

* upper core plate * upper support plate

* upper instrumentation columns

and supports

Virtually all these components are fabricated from various types of wrought austenitic

stainless steel; however, a few components are fabricated from CASS. Unit 1 guide

tube split pins are fabricated from nickel-based alloy X-750. Unit 2 split pins were

replaced during the 2005 refueling outage. The new split pins are fabricated from

cold-worked 316 stainless steel.

3-90
The applicant's program relies on the ASME Code Section Xl examinations of the RVIs

to detect the applicable aging effects. This program credits the ASME Code Section Xl,

Subsection IWB, IWC, and IWD Inservice Inspection Program (ISI) for the ISI

examinations of the RVIs. The applicant recognizes that for some components the VT-3

examination required by ASME Code Section Xl may not be adequate to detect the

effects before the component's intended function is compromised. The applicant stated

that the need for augmented examinations will be determined by evaluations of the

susceptibility of each RVI component to the applicable aging effects that require aging

management. The applicant also stated that in addition to industry and plant-specific

experience, fluence, temperature, and stress analyses may be used as inputs to the

susceptibility evaluations.

For CASS components that are part of the RVIs, PBNP will use 1 x 1017 n/cm2

(E > 1.0 MeV) as its threshold value for initiation of neutron irradiation embrittlement.

This criterion is in line with the GALL's recommendation. The applicant stated that if the

fluence remains below 1 x 10"7 n/cm2 (E > 1.0 MeV), the significance of thermal aging

will be determined by comparison with the screening criteria, based on delta ferrite

content, molybdenum content, and casting method, as described in NUREG-1 801,

Section XI.M13.

The Reactor Vessel Intemals Program takes exception to this program element. The

GALL Report references ASME Code Section Xl, Subsection IWB, 95A96 for the

inservice inspections of RVIs. PBNP currently uses ASME Code Section Xl,

Subsections IWB, IWC, and IWD Inservice Inspection Program, 98A00.

Section 50.55a(g)(4)(iv) of 10 CFR requires that inservice examination of components

may meet the requirements set forth in subsequent editions and addenda that are

incorporated by reference in 10 CFR 50.55a(b) subject to the limitations and

modifications listed in 10 CFR 50.55a(b) and subject to NRC approval. The staff

accepts the applicant's use of the later version of the ASME Code considering: (1) use

of the later version of the ASME Code as permitted by 10 CFR 50.55a, and (2) the

applicant's commitment of participating in industry initiatives and submittal of inspection

program for NRC approval 24 months prior to entering the period of extended operation.

The staff confirmed that the "scope of the program" program element satisfies the

criterion defined in the GALL Report and SRP-LR Section A.1.2.3.1. As discussed

above, the staff concluded that this program attribute, including its associated

exceptions, is acceptable.

(2) Preventive Actions - The applicant stated that the Water Chemistry Control Program is

credited for monitoring and control of reactor coolant water chemistry to prevent or.

mitigate the effects of SCC and IASCC. Additionally, the guide tube split pins in Unit 1

have all been replaced with pins made from the same alloy with a more SCC-resistant

heat treatment. In Unit 2,-the pins on two guide tubes were replaced and the remaining

pins were verified to have been solution heat treated above 1800 'F, although it is

assumed that they are still susceptible to SCC because the initial installation torque was

substantially higher than that used in the replacements. The Unit 2 split pins were

replaced during the 2005 refueling outage. The new split pins are fabricated from

cold-worked 316 stainless steel. A portion of the Unit 2 baffle former bolts have been

replaced with a more crack-resistant material. For RVI CASS components, the program

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consists of evaluations and inspections. There are no preventive actions to mitigate

thermal aging, neutron irradiation embrittlement, or void swelling.

The staff confirmed that the "preventive actions" program element satisfies the criterion

defined in the GALL Report and SRP-LR Section A.1.2.3.2. The staff concluded that

this program attribute is acceptable.

(3) Parameters Monitored or Inspected - The applicant stated that the program monitors for

cracking, loss of fracture toughness, loss of bolted joint preload, wear, and change of

dimensions through ASME Code Section Xl examinations and augmented NDEs.

The program monitors the effects of loss of fracture toughness of components by

identifying the CASS materials that either have a neutron fluence of greater than

1017 n/cm2 or are determined to be susceptible to thermal aging embrittlement. For

these components, PBNP will evaluate the need for, and the characteristics of, an

augmented examination. As an alternative to an augmented examination, a mechanical

loading assessment may be conducted. This element is consistent with the

corresponding GALL Report program element.

The staff confirmed that the "parameters monitored or inspected" program element

satisfies the criterion defined in the GALL Report and SRP-LR Section A.1.2.3.3. The

staff concluded that this program attribute is acceptable.

(4) Detection of Aging Effects - The applicant stated that exception to this NUREG-1 801

AMP element was taken. NUREG-1 801 provides a specific example of an acceptable

supplemental or enhanced examination as VT-1 examination with .0005 inch resolution.

The applicant's program does not specify resolution requirements for enhanced VT-1

examination, but rather requires examination methods sufficient to detect a crack of

such size that crack growth during the interval until the next examination will not result in

a crack of critical size or larger.

The applicant stated that visual examinations to detect cracking, loss of preload, and

wear are used. The type of visual examination utilized will be, as a minimum, the VT-3

examination specified by ASME Code Section Xl, Subsection IWB, Category IWB,

Category B-N-3. Augmented examinations for cracking may consist of VT-1, enhanced

VT-1 examinations, or a volumetric examination when warranted by the size and

location of the crack that must be detected to preserve intended functions. For

baffle-former bolts and other bolts that are largely inaccessible for visual examination,

ultrasonic testing or other appropriate NDE technique will be used to detect cracking.

The applicant confirmed in the LRA "for baffle-former and other bolts that are largely

inaccessible for visual examination, ultrasonic testing (UT) or other appropriate NDE

technique will be used to detect cracking." PBNP also confirmed that it will evaluate the

need for an augmented examination covering portions of the susceptible components

determined to be limiting from the standpoint of thermal aging susceptibility, neutron

fluence, and cracking.

The applicant committed to: (1) examination methods sufficient to detect a crack of

such size that crack growth during the interval will not result in a crack of critical size or

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larger, and (2) participate in industry initiatives and submittal of inspection program for

NRC approval 24 months prior to entering the period of extended operation. Therefore,

the staff concluded that this exception is acceptable.

The staff confirmed that the "detection of aging effects" program element satisfies the

criterion defined in the GALL Report and SRP-LR Section A.1.2.3.4. The staff

concluded that this program attribute is acceptable.

(5) Monitoring and Trending - The applicant stated that exception to this corresponding

NUREG-1801 AMP element was taken. The GALL Report specifies examination

schedules in accordance with ASME Code Section Xl IWB-2400, which requires core

support structures to be inspected once during each 1 0-year interval. The applicant

stated, "while this applies to the VT-3 examination, some augmented examinations may

be performed at a different frequency or only one-time based on the susceptibility

evaluations and examinations result."

The applicant currently uses the VT-3 examination pursuant to ASME Code Section Xl,

Subsection IWB, Category B-N-3 once per 1 0-year interval on each accessible part of

the RVIs. The applicant also planned to schedule either periodic or one-time

augmented examinations for cracking in components susceptible to cracking or loss of

fracture toughness, and ultrasonic examinations of baffle-former bolts for cracking. The

scheduling of future augmented examinations will depend on the results of the initial

examination.

PBNP's inspection frequency is based on susceptibility evaluations and examination

results and, in essence, meets the intent of NUREG-1 801 AMP elements. In addition,

the applicant committed to participate in industry initiatives and submittal of inspection

program for NRC approval 24 months prior to entering the period of extended operation.

Therefore, the staff concluded that this exception is acceptable.

The staff confirmed that the 'monitoring and trending" program element satisfies the

criteria defined in the GALL Report and SRP-LR Section A.1.2.3.5. The staff concluded

that this program attribute is acceptable.

(6) Acceptance Criteria - The applicant stated that the relevant conditions of degradation

detected will be evaluated in accordance with ASME Code Section Xl IWB-31 00, which

refers to acceptance standards contained in ASME Code Section Xl IWB-3400 and

IWB-3500. The criteria of IWB-3500 will be used for CASS components with flaw

tolerance evaluations in accordance with the ASME Code Section Xl IWB-3640

procedure for submerged arc welds, with the modification for delta ferrite content as

required by IWB-3641. However, any of the acceptance methods of ASME Code

Section Xl IWB-3132 may be used (i.e., volumetric or surface examination,

repair/replacement, analytical evaluation).

The applicant took exception to this NUREG-1 801 AMP element. GALL AMP XI.M1 6

refers to the ASME Code Section Xl, 95A96. PBNP uses ASME Code Section Xl,

98A00.

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The staff accepts the applicant's use of the later version of the ASME Code considering:

(1) use of the later version of the ASME Code as permitted by 10 CFR 50.55a, and (2)

the applicant's commitment to participate in industry initiatives, and (3) submittal of its

inspection program for NRC approval 24 months prior to entering the period of extended

operation.

Since it has been adopted in the GALL Report, use of industry research studies and

activities on age-related degradation of RVI components may be used as an alternative

basis for determining which age-related degradation mechanisms are applicable to RVIs

and what types of examinations are necessary to manage these mechanisms. This is a

process-oriented approach to aging management that will ensure that the inspections

proposed for RVIs are those that the industry research studies have demonstrated are

necessary to maintain the structural integrity or functionality of the components. -NRC's

review of the recommended activities is an integral part of the industry initiative process.

The staff used this alternative in evaluating the exceptions identified in program

attributes.

However, any proposal to use the industry's research studies and activities on RVIs 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 inspection plan for the RVIs to the NRC for review and

approval prior to the period of extended operation.

The LRA and the clarification letter, dated July 12, 2004, confirmed that:

* NMC will continue to participate in the industry's initiatives intended to clarify the

nature and extent of aging mechanisms potentially affecting RVIs.

* NMC will incorporate the results of these initiatives (to the extent that they are

applicable to the PBNP RVIs) into the scope, inspection requirements (including

inspection locations, methods, qualifications, and frequencies), acceptance

criteria, and corrective actions for the Reactor Vessel Internals Program.

* NMC will submit an inspection plan for the PBNP Reactor Vessel Internals

Program for NRC review and approval at least two years prior to entering the

period of extended operation.

Therefore, the staff concluded that the applicant's LRA commitment is acceptable.

PBNP will: (1) apply acceptable industry guidelines that will ensure that only those

inspections will be used that are capable of detecting degradation prior to a loss of

component intended function; (2) allow the staff to review the applicant's inspection

plans for the RVI as based on the industry recommendations, and (3) provide the staff

an opportunity to resolve with the applicant any issues that may arise with the inspection

plan.

The staff confirmed that the "acceptance criteria" program element satisfies the criteria

defined in the GALL Report and SRP-LR Section A.1.2.3.6. As discussed above, the

staff found that the use of a later version of the ASME Code is acceptable. The staff

concluded, therefore, that this program attribute is acceptable.

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(10) Operating Experience - The applicant stated that Industry operating experience has

been reviewed during the development of the Reactor Vessel Internals Program. The

experience reviewed includes IN 98-11, "Cracking Of Reactor Vessel Internal Baffle

Former Bolts In Foreign Plants," and IN 84-18, "Stress Corrosion Cracking in PWR

Systems." Most of the industry operating experience reviewed involved cracking of

austenitic stainless steel baffle-former bolts, or SCC of high-strength internals bolting.

SCC of guide tube split pins has also been reported.

A review of plant-specific operating experience with RVIs reveals that PBNP responded

to industry operating experience regarding RVI degradation. Two examples that

demonstrate PBNP's response to industry operating experience with RVIs are

augmented examination and -replacement of guide tube split pins and augmented

examination and replacement of baffle-former bolts. Guide tube split pins were replaced

in their entirety in Unit 1 and partially in Unit 2 in response to SCC failures of these pins

in other Westinghouse units. A more SCC-resistant heat treatment was applied to the

replacement pins. An augmented examination via UT was conducted on the

baffle-former bolts of Unit 2. The UT examination identified a number of bolts with

indications indicative of crack-like flaws. A number of bolts sufficient to guarantee the

structural margins of the baffle-former joints were replaced, including all bolts with UT

indications. The replacement bolts are fabricated from a more IASCC-resistant

material; however, during the 2005 refueling outage, PBNP replaced all Unit 2 split pins

with split pins fabricated from cold-worked 316 stainless steel. PBNP will participate in

the EPRI RI-ITG, which is engaged in ongoing research into aging effects of RVIs and

provides guidance to utilities on corrective actions for these aging effects. PBNP also

participates in Westinghouse Owners Group activities related to RVIs.

A review of NRC inspection reports, QA audit/surveillance reports, and

self-assessments since 1999 revealed no issues or findings that could impact the

effectiveness of the Reactor Vessel Intemals Program. As additional operating

experience is obtained, lessons learned may be used to adjust this program. This

element is consistent with the corresponding NUREG-1 801 AMP elements.

The staff confirmed that the "operating experience" program element satisfies the

criteria defined in the GALL Report and SRP-LR Appendix A.1.2.3.10. The staff

concluded that this program attribute is acceptable.

FSAR Supolement. In LRA Section Al5.2.17, the applicant provided the FSAR supplement for

the Reactor Vessel Internals Program. The staff reviewed these sections and determined that

the information in the FSAR supplement provides an adequate summary of the program

activities. The staff found that the commitment to the Reactor Vessel Internals Program

acceptable, as required by 10 CFR 54.21 (d).

Conclusion. On the basis of its review and audit of the applicant's program, the staff found that

those program elements for which the applicant claimed consistency with the GALL Report are

consistent with the GALL Report. In addition, the staff reviewed the exceptions and the

associated justifications and determined that the AMP, with the exceptions, is adequate to

manage the aging effects for which it is credited. The staff found that the applicant had

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

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required by 10 CFR 54.21 (a)(3). The staff also reviewed the FSAR supplement for this AMP

and found that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.0.3.2.17 Reactor Vessel Surveillance Program

Summary of Technical Information in the AP1lication. The applicant's Reactor Vessel

Surveillance Program is described in LRA Section B2.1.18, "Reactor Vessel Surveillance

Program." In the LRA, the applicant stated that this is an existing program that is consistent,

with exceptions and enhancements, with GALL AMP XI.M31, 'Reactor Vessel Surveillance."

The applicant stated that its Reactor Vessel Surveillance Program, as modified by its

supplemental letters dated September 10 and October 25, 2004, manages the aging effect of

reduction of fracture toughness due to neutron embrittlement of the low-alloy steel reactor

vessels. This program includes: (1) capsule insertion, withdrawal and materials

testing/evaluation, (including upper shelf energy and increase in transition temperature, RTNDT

determinations), (2) fluence and uncertainty calculations, (3) monitoring of effective full power

years (EFPY), and (4) determination of impact on pressure-temperature limitations and on low

temperature overpressure set points (LTOP). The applicant stated that the AMP applies the

methodology of Regulatory Guide (RG) 1.190 for fluence calculations and determinations. This

RG provides the NRC-recommended methodology for performing 'best estimate fluence

calculations.

Staff Evaluation. In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information

included in LRA Section B2.1.18, regarding the applicant's demonstration of the Reactor Vessel

Surveillance Program to ensure that the effects of aging, as discussed above, will be

adequately managed so that the intended functions will be maintained consistent with the CLB

throughout the period of extended operation.

The staff's evaluation of the Reactor Vessel Surveillance Program is based on its review of the

program description in LRA Section B2.1.18. The staff's criteria for accepting the Reactor

Vessel Surveillance Program are based on both conformance with GALL AMP XL.M31 and

compliance with the applicable requirements of 10 CFR Part 50, Appendix H.

The program discussion in GALL AMP XL.M31 is not currently based on the staff's

recommendations of the 10 program attributes that should be included in Reactor Vessel

Surveillance Program, but rather on general recommendations of how these surveillance

programs are expected to comply with the requirements of 10 CFR Part 50, Appendix H, and

should be modified, as applicable, to address the increases in neutron fluences projected for

the period of extended operation. Because the applicant considered the Reactor Vessel

Surveillance Program to be an existing plant-specific program for Units 1 and 2, it included a

description of the 10 program elements in LRA Section B2.1.18.

The staff reviewed the Reactor Vessel Surveillance Program against the AMP elements found

in the GALL Report, SRP-LR Section A.1.2.3 and SRP-LR Table A.1-1 and focused on how the

program manages aging effects through the effective incorporation of 10 elements (i.e.,

program scope, preventive actions, parameters monitored or inspected, detection of aging

effects, monitoring and trending, acceptance criteria, corrective actions, confirmation process,

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administrative controls, and operating experience). The PBNP Reactor Vessel Surveillance

Program takes exceptions to the following program element: (6) acceptance criteria.

The applicant indicated that the corrective actions, confirmation process, and administrative

controls are part of the site-controlled quality assurance program. The staff's evaluation of the

quality assurance program is discussed in SER Section 3.0.4. The remaining seven elements

are discussed below.

LRA Section B2.1.18, as modified by a supplemental letter dated October 25, 2004, states that

the Reactor Vessel Surveillance Program is consistent with GALL, with enhancements. The

applicant stated that enhancements include revisions to plant procedures to clarify

organizational responsibilities, describe the plan/schedule for removal, testing and evaluation of

surveillance capsules, and to evaluate fracture toughness margin through the period of

extended operation. The staff considered this type of enhancement as an administrative

enhancement which does not require staff review.

(1) Scope of the Program - The applicant stated that the Reactor Vessel Surveillance

Program consists of activities that manage the aging effects for components in the

reactor vessel. The Reactor Vessel Surveillance Program only applies to the Units 1

and 2 reactor pressure vessels. Reactor Vessel Surveillance Programs, which are

designed and implemented in accordance with 10 CFR Part 50, Appendix H, use testing

of RV surveillance capsule test specimens as the basis for monitoring for neutron

irradiation-induced embrittlement in base metals (plate or forgings) and welds that are

located in the beltline region of low-alloy steel or carbon steel RVs. The original PBNP

surveillance program consisted of six surveillance capsules in each unit attached to the

outside of the RVIs thermal shield. Each capsule contained mechanical test specimens,

Charpy V-Notch specimens, dosimetry, and thermal monitors. The mechanical test

specimens were fabricated from material representative of the PBNP RVs. To date,

four surveillance capsules have been removed and tested from each unit's RV. One of

the standby capsules has also been removed from each unit's RV and is being stored at

PBNP.

The applicant stated that the original surveillance capsules did not contain the most

limiting material with respect to embrittlement. A replacement surveillance capsule

containing materials closely matching the limiting materials for both Units 1 and 2 was

installed in the Unit 2 RV during the 2002 refueling outage. The newly installed capsule

will be withdrawn during an outage at which it accumulates a fluence equivalent to the

60 calendar-year vessel fluence. Data from an integrated surveillance program that

includes all PWRs with RVs fabricated by B&W will also be used to predict

embrittlement of the RV limiting beltline material. However, the applicant also stated

that since the spare capsules remaining In both Units 1 and 2 RVs do not contain the

most limiting materials, there are no plans to withdraw these capsules. By keeping the

capsules in the vessel, the capsules will experience much higher exposure and would

not provide meaningful data. The program discussion in GALL AMP XL.M31 suggests to

withdraw one capsule at an outage in which the capsule receives neutron fluence

exposure equivalent to the 60-year fluence and test the capsule in accordance with the

requirements of ASTM E 185. The GALL Report also suggests that other standby

capsules be removed and placed in storage. These standby capsules would be

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available for reinsertion into the reactor if needed. The applicant stated that it has no

plan to withdraw the last capsules from the PBNP vessels.

The staff's review of LRA Section B2.1.18 identified an area in which additional

information was necessary to complete the review of the applicant's- program elements.

The applicant responded to the staff's RAI as discussed below.

RAI B2.1.18-1. In RAI B2.1.18-1, dated November 17, 2004, the staff requested the

applicant to justify its decision of not removing the capsules from the vessels.

In its response, dated January 25, 2005, the applicant stated that there are no current

plans to remove the standby capsules from the reactor vessels. The standby capsules

may be removed at some time in the future to support industry needs. Also, the lead

factor for these remaining capsules is low enough to allow extended neutron exposure.

Removal of these capsules will not directly support demonstration of adequate upper

shelf energy (USE) and pressurized thermal shock (PTS) evaluations for the

Units 1 and 2 RVs, and consequently removal was not required in the AMP. The

Reactor Vessel Surveillance AMP requires all withdrawn surveillance capsules, not

discarded as of August 31, 2000, to be placed in storage for purposes of future use, if

necessary. The staff agreed with the applicant's approach; removal of these capsules is

not necessary at this point.

The staff confirmed that the "scope of the program" program element satisfies the

criterion defined in the GALL Report and SRP-LR Section A.1.2.3.1. The staff

concluded that this program attribute is acceptable.

(2) Preventive Actions - The applicant stated that the surveillance program determines

neutron embrittlement of RV materials that will be used in evaluating for USE and its

impact on pressure-temperature limits for 60 years. However, there are no preventive

or mitigative actions associated with the RV surveillance removal and evaluation

program, nor did the staff identify a need for such actions.

The staff confirmed that the "preventive actions" program element satisfies the criterion

defined in the GALL Report and SRP-LR Section A.1.2.3.2. The staff concluded that

this program attribute is acceptable.

(3) Parameters Monitored or Inspected - The applicant stated that the program monitors the

effects of neutron irradiation on the Units 1 and 2 RV beltline materials. Fracture

toughness of beltline materials is indirectly monitored through measurement of the

impact energy of Charpy V-notch specimens, made from representative materials from

the PBNP RV beltline regions. The surveillance capsules also contain neutron

dosimetry that monitors the amount of neutron fluence received by the test specimens.

Fracture toughness of PBNP RV beltline materials were monitored using the Charpy

V-notch specimens and neutron fluence was monitored using the neutron dosimeters.

Therefore, the staff concluded that the applicant satisfied the monitoring criteria as

recommended in the GALL Report.

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The staff confirmed that the "parameters monitored or inspected" program element

satisfies the criterion defined in the GALL Report and SRP-LR Section A.1.2.3.3. The

staff concluded that this program attribute Is acceptable.

(4) Detection of Aging Effects - The applicant stated that aging effects are detected through

testing of surveillance materials. Charpy V-notch tests are performed to determine the

decrease in USE and increase in transition temperature RTNDT, for materials that closely

match RV beltline materials. Aging effects of vessel beltline materials were detected

using Charpy V-notch tests and, therefore, the staff concluded the applicant satisfied the

criteria for the detection of aging effects as recommended in the GALL Report.

The staff confirmed that the "detection of aging effects" program -element satisfies the

criterion defined in the GALL Report and SRP-LR Section A.1.2.3.4. The staff

concluded that this program attribute is acceptable.

(5) Monitoring and Trending - The applicant stated that monitoring of RV bettline fracture

toughness is accomplished through testing of surveillance specimens from surveillance

capsules that are periodically withdrawn from the vessels. Trending is accomplished

through RG 1.99, Revision 2 methods for projection of RTNDT and USE. Projection of

the increase in RTNDT and the decrease in USE provides early indication of the fracture

toughness properties of the PBNP RV beltline materials. To date, four surveillance

capsules have been removed and tested from each Unit's RV. One of the standby

capsules has also been removed from each Unit's RV and is being stored at PBNP.

Since the original surveillance capsules did not contain the most limiting material with

respect to embrittlement, an additional surveillance capsule was installed in 2002 that

contains the most limiting material. Withdrawals of this additional capsule will provide

meaningful data for 60 years of operation. In addition, the supplemental capsules are

available for testing and alternate dosimetry is not required in conformance with

provision seven of GALL AMP XL.M31. Based on this discussion, the staff concluded

that the applicant satisfied the criteria for the monitoring and trending as recommended

in the GALL Report.

The staff confirmed that the "monitoring and trending" program element satisfies the

criteria defined in the GALL Report and SRP-LR Section A.1.2.3.5. The staff concluded

that this program attribute is acceptable.

(6) Acceptance Criteria - The applicant, in its clarification letter, dated September 4, 2004,

stated that the USE acceptance criteria require that the RV beltline materials must have

USE values above 50 ft-lbs until the EOL extension, using the methods of RG 1.99,

Revision 2, with the PBNP-specific and integrated surveillance program data as inputs

or an equivalent margin analysis must be performed. The RTP,, of the most limiting

material in the RV beltline must not exceed the PTS screening criteria specified by

10 CFR 50.61, unless it can be demonstrated by alternate means, as allowed by

10 CFR 50.61, that the probability of brittle fracture of the RV in a PTS event is

acceptably low.

The acceptance criterion for P-T curves is that the flaw stability criteria of ASME Code

Section Xl, Appendix G are met for all normal operating conditions as required by

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10 CFR Part 50, Appendix G. The acceptance criteria of the ASME Code, Section Xl,

Appendix G may be modified through application of ASME Code Case N-641, which

allows the use of the K1c curve, an alternate fracture toughness curve to the Kic curve.

Additionally, the applicant stated that, if no reasonably practical flux reduction program

can be shown to prevent RTp, values from exceeding the PTS screening criteria prior to

EOL, other options allowed by 10 CFR 50.61(b) will be evaluated and implemented.

The staff confirmed that the "acceptance criteria" program element satisfies the criteria

defined in the GALL Report and SRP-LR Section A.1.2.3.6. The staff found acceptable

the use of fracture toughness curves pursuant to the guidance provided in ASME Code

Case N-641. The staff concluded that this program attribute is acceptable.

(10) Operating Experience - The applicant stated that the Units 1 and 2 P-T limits have been

developed as required. The applicant also stated that the actuation of low temperature

overpressure protection (LTOP) system relief valves at Unit 1 on October 23, 1997

avoided an overpressurization event.

The applicant stated that Unit 1 will continue to satisfy the requirements of

10 CFR Part 50, Appendix G and 1O CFR 50.61 through the end of the period of

operation. However, RTpis for the intermediate-to-lower shell girth weld in the Unit 2

vessel is predicted to exceed the PTS screening criteria prior to the end of license

extension. The applicant addressed the issue of RTp. by discussing several options

including flux reduction, advanced analysis and other options. This is further discussed

in SER Section 4.2.1.

The applicant modified its surveillance capsule program to incorporate data from the

B&W integrated surveillance program. A replacement surveillance capsule containing

materials closely matching the limiting materials for both Units 1 and 2 has been

installed in the Unit 2 RV during the 2002 refueling outage. The newly installed capsule

will be withdrawn during an outage at which it accumulates a fluence equivalent to the

60 calendar year vessel fluence. Data from an integrated surveillance program that

includes all PWRs with RVs fabricated by B&W will also be used to predict

embrittlement of the RV limiting beltline material.

The staff confirmed in its review of the TLAAs on neutron irradiation embrittlement that

the applicant applied all relevant copper and nickel alloy chemistry data to the

assessments. These assessments are included in LRA Section 4.2 and are evaluated

in SER Section 4.2. The staff concluded that the operating experience program

attribute is acceptable since the applicant referred to all of the surveillance data that are

applicable to the Reactor Vessel Surveillance Program and the TLAAs on neutron

irradiation embrittlement.

The staff confirmed that the "operating experience" program element satisfies the

criteria defined in the GALL Report and SRP-LR Section A. 1.2.3.10. The staff

concluded that this program attribute is acceptable.

FSAR Sunplement. In LRA Section Al 5.2.18, the applicant provided the FSAR supplement for

the Reactor Vessel Surveillance Program. The staff reviewed these sections and determined

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that the information in the FSAR supplement provides an adequate summary of the program

activities. The staff found these sections of the FSAR supplement meet the requirements of

10 CFR 54.21 (d).

Conclusion. On the basis of its review, RAI response, and audit of the applicant's program, the

staff found that those program elements for which the applicant claimed consistency with the

GALL Report are consistent with the GALL Report. In addition, the staff reviewed the

exceptions and the associated justifications and determined that the AMP, with the exceptions,

is adequate to manage the aging effects for which it is credited. The staff found that the

applicant had demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the FSAR supplement

for this AMP and found that it provides an adequate summary description of the program, as

required by 10 CFR 54.21 (d).

3.0.3.2.18 Steam Generator Integrity Program

Summary of Technical Information in the Application. The applicant's Steam Generator

Integrity Program is described in LRA Section B2.1.19, "Steam Generator Integrity Program."

In the LRA, the applicant stated that this is an existing program that is consistent, with

enhancements, with GALL AMP XI.M1 9, "Steam Generator Tube Integrity."

The Unit 1 SGs were replaced in 1984 and use thermally treated Alloy 600 SG tubing, stainless

steel tube supports and chrome plated Alloy 600 anti-vibration bars. The Unit 2 SGs were

replaced in 1997 and use Alloy 690 tubing, stainless steel tube supports and anti-vibration bars.

The Steam Generator Integrity Program incorporates the guidance of NEI 97-06 "Steam

Generator Program Guidelines," and maintains the integrity of the SG, including tubes, tube

plugs or other tube repairs, and various secondary-side internal components. The program

manages aging effects through a balance of prevention, inspection, evaluation, repair, and

leakage monitoring measures. Component degradation is mitigated by controlling primary and

secondary water chemistry. Eddy current testing is used to detect SG tube degradation and

flaws. Visual inspections are performed to identify degradation of various secondary-side SG

internal components. A tube integrity assessment is done following each SG tube inspection.

The purpose of the assessment is to ensure that the performance criteria have been met for the

previous operating period and will continue to be met for the next period. NRC reporting

requirements are in accordance with plant technical specifications and NEI 97-06.

Periodic visual inspections of accessible areas are performed to verify the integrity of

secondary-side components and to assess tube fouling. The inspections include the upper

tube bundle, tube support plates, swirl vane, moisture separator, and feed ring areas.

The Steam Generator Integrity Program is an existing program that is consistent with

the GALL Report, Section XI.M1 9, "Steam Generator Tube Integrity," with regard to managing

the aging effects of SG tubes, and tube plugs or other tube repairs. The Steam Generator

Integrity Program is also considered an existing plant-specific program that consists of the

appropriate 10 elements described in Branch Technical Position RLSB-1, "Aging Management

Review-Generic," which is included in Appendix A of NUREG-1800, "Standard Review Plan for

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Review of License Renewal Applications for Nuclear Power Plants," for managing the aging

effects of various SG secondary-side internal components.

Staff Evaluation. In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information

included in LRA Section B2.1.19, regarding the applicant's demonstration of the Steam

Generator Integrity Program to ensure that the effects of aging, as discussed above, will be

adequately managed so that the intended functions will be maintained consistent with the CLB

throughout the period of extended operation.

Steam generator aging management incorporates provisions of NEI 97-06. The industry

guidelines include an assessment of degradation mechanisms considering the operating

experience from similar SGs to identify all potential degradation mechanisms that should be

considered during inspection. For each identified mechanism, the industry guidelines define the

inspection techniques, measurement uncertainty and the sampling strategies. The industry

guidelines provide criteria for the qualification of personnel, specific techniques and the

associated acquisition and analysis of data, including procedures, probe selection, analyses

protocols and reporting data. Performance criteria are specified and pertain to structural

integrity, accident induced leakage and operational leakage. The Steam Generator Integrity

Program includes guidance on assessment of degradation mechanisms, inspection, tube

integrity, maintenance, repair, leakage monitoring as well as control of water chemistry. Water

chemistry control of both primary and secondary water is an integral component outlined in

NEI 97-06 and as a method to limit age-related degradation. NEI 97-06 identifies the provision

for monitoring secondary-side SG components to ensure that failure of a secondary-side

component will not impact the ability of the SG to fulfill its safety-related function.

The staff reviewed the Steam Generator Integrity Program against the AMP elements found in

the GALL Report, SRP-LR Section A.1.2.3, and SRP-LR Table A.1 -1 and focused on how the

program manages aging effects through the effective incorporation of 10 elements (i.e.,

program scope, preventive actions, parameters monitored or inspected, detection of aging

effects, monitoring and trending, acceptance criteria, corrective actions, confirmation process,

administrative controls, and operating experience).

The applicant indicated that the corrective actions, confirmation process, and administrative

controls are part of the site-controlled quality assurance program. The staff's evaluation of the

quality assurance program is discussed in SER Section 3.0.4. The remaining seven elements

are discussed below.

LRA Section B2.1.19 states that the Steam Generator Integrity Program is consistent with the

GALL Report, with enhancements. The applicant stated that enhancements include plant

procedure revisions to specify the inspections of additional secondary-side components,

provide acceptance criteria, and improve the inspection documentation. The staff considered

this type of enhancement to be an administrative enhancement that does not require staff

review.

(1) Scope of the Program - The applicant stated that the scope of the program was

structured to meet NEI 97-06 and applicable plant technical specifications. The

applicant's discussion of the program scope indicated that the various secondary-side

components were included, but did not clearly elaborate on which secondary-side

components were included in the program scope. As discussed in SER Section 3.1, the

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staff requested the applicant to identify all the components within the secondary-side

inspection scope. In a letter, dated January 6, 2005, the applicant stated that aging of

the following components would be managed by this portion of the Steam Generator

Integrity Program: anti-vibration bars, blowdown piping nozzles and secondary-side

shell penetrations, feedwater nozzle, secondary closures, steam outlet nozzle, transition

cone girth weld, tube bundle wrapper and wrapper support system, tube support plates,

tubesheet and the upper and lower shell, elliptical head and transition cone. The

applicant also indicated that portions of the upper tube bundle, tube support plates, swirl

vane, moisture separators and feed ring are inspected. The scope adequately

addresses those components identified as potentially susceptible to aging degradation.

Therefore, the staff found this acceptable.

The staff confirmed that the "scope of the program" program element satisfies the

criterion defined in the GALL Report and SRP-LR Section A.1.2.3.1. The staff

concluded that this program attribute is acceptable.

(2) Preventive Actions - The applicant stated that the Water Chemistry Control is in place to

mitigate the potential corrosion related degradation of primary and secondary

components. The Water Chemistry Control Program is evaluated in SER

Section 3.0.3.2.20. In addition, the applicant Indicated that the guidelines of NEI 97-06

include foreign material exclusion requirements to limit fretting and wear-related

degradation and that sludge lancing is used to minimize the potential for pitting

associated with sludge piles. The staff found that the preventive actions identified are

acceptable and will assist in managing aging of the components within the program

scope.

The staff confirmed that the "preventive actions" program element satisfies the criterion

defined in the GALL Report and SRP-LR Section A.1.2.3.2. The staff concluded that

this program attribute is acceptable.

(3) Parameters Monitored or Inspected - The applicant stated that the SG tube inspections

are performed in accordance with plant technical specifications and NEI 97-06. Primary

to secondary leakage is monitored to verify tube integrity during plant operations and

tube integrity is assessed against the NEI 97-06 performance criteria. Secondary-side visual inspections are performed to assess the condition of components within the

program scope. The program requires periodic visual Inspection of the upper tube

bundle, tube support plates, swirl vane, moisture separators and feed ring. A number of

the components identified by the applicant as within the program scope have limited

visual accessibility. As discussed in SER Section 3.1, the staff requested the applicant

to identify how these components will be inspected as part of the secondary-side SG

visual inspections (i.e., anti-vibration bars). The applicant stated that for those

components with limited visual accessibility, similar materiaVenvironment combinations

will be relied on to provide indication of the potential for age-related degradation. The

staff concluded that the parameters monitored or inspected are acceptable. Inspections

are performed in accordance with plant technical specifications; NEI 97-06 criteria and

performance of SG secondary inspections would provide meaningful information

regarding aging of SG components.

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The staff confirmed that the "parameters monitored or inspected" program element

satisfies the criterion defined in the GALL Report and SRP-LR Section A.1.2.3.3. The

staff concluded that this program attribute is acceptable.

(4) Detection of Aging Effects - The applicant stated that its program complies with the plant

technical specifications and with NEI 97-06 criteria by using the program extent and

schedule for inspections to ensure that flaws do not exceed established performance

criteria. The applicant indicated that tube integrity assessments account for

uncertainties associated with detectability and sizing of certain types of flaws. In

addition, the applicant indicated that periodic visual secondary-side SG inspections

would provide reasonable assurance that degradation would be detected before a loss

of intended function or the integrity of the tubes was challenged. As discussed in SER

Section 3.1, the staff requested the applicant to discuss how aging effects would be

detected in components with limited access for visual inspection.

In a letter, dated January 6, 2005, the applicant stated that the secondary-side

inspections were intended to augment the Water Chemistry Control Program and

committed to perform secondary-side visual inspections of accessible areas to verify the

integrity of SG secondary-side components at least every six years, with one SG being

inspected every three years on an alternating basis. The applicant stated that the Water

Chemistry Control Program was intended to mitigate corrosion related degradation in

the SG. The secondary-side visual inspections are intended to augment water

chemistry and verify its effectiveness by conducting a general condition assessment.

The applicant indicated that where the component is inaccessible to visual inspection,

the applicant intends to inspect components with a similar material/environment

combination to provide insight into the potential for age-related degradation. The

applicant's response included a new commitment regarding the frequency of

secondary-side visual inspection stating that any indications of degradation or

unacceptable conditions will be evaluated through the corrective action program,

including extent of condition. The staff concluded that aging effects should be

adequately detected by the program. The applicant will use both a mitigating strategy

and inspections of accessible components.

The staff confirmed that the "detection of aging effects" program element satisfies the

criterion defined in the GALL Report and SRP-LR Section A.1.2.3.4. The staff

concluded that this program attribute is acceptable.

(5) Monitoring and Trending - The applicant stated that inspection intervals based upon the

technical specifications and NEI 97-06 are expected to provide timely detection of tube

degradation. Primary to secondary leakage is monitored and will identify degradation of

SG tubing. In addition the applicant indicated that operational assessments are

performed to verify that structural and leakage integrity will be maintained during the

operating interval until the next required inspection. The applicant indicated that the

results of the secondary-side inspections are documented, evaluated and compared to

the results of previous secondary-side inspections in order to monitor on-going

degradation. The staff found that the applicant's monitoring and trending is acceptable.

Condition monitoring and operational assessments will address potential degradation

modes and provide assurance that SG integrity will be met during future operating

cycles.

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The staff confirmed that the "Monitoring and trending" program element satisfies the

criteria defined in the GALL Report and SRP-LR Section A.1.2.3.5. The staff concluded

that this program attribute is acceptable.

(6) Acceptance Criteria - The applicant stated that the acceptance criteria are in

accordance with the plant technical specifications and NEI 97-06. The applicant

indicated that any loose part or foreign material that is identified is removed from the SG

unless it is shown by evaluation that these items will not cause unacceptable tube

damage. The applicant indicated that tube inspections are followed by assessments of

tube integrity relative to performance criteria in the areas of structural integrity and

operational and accident leakage integrity. The applicant also indicated that when SG

tubes do not meet the acceptance criteria, the tubes are repaired or removed from

service by plugging. The applicant utilizes primary-to-secondary leakage criteria in

accordance with NEI 97-06, which is more restrictive than the technical specification

limits.

The staff confirmed that the "acceptance criteria" program element satisfies the criteria

defined in the GALL Report and SRP-LR Section A.1.2.3.6. The staff concluded that

this program attribute is acceptable.

(10) Operating Experience - The applicant stated that the Steam Generator Integrity

Program has been effective in ensuring timely detection and correction of the aging

effects for SGs. The applicant's program incorporates the plant technical specification

requirements and the information contained in NEI 97-06. The applicant has replaced

the SGs. In Unit 1, the SGs were replaced in 1984 with SGs utilizing thermally treated

Alloy 600 tubes. In Unit 2, the SGs were replaced in 1997 with SGs utilizing Alloy 690

tubes. Both units' replacement SGs employ design changes to enhance material

performance.

The applicant indicated that the most recent Unit 1 SG inspection results indicated that

the SGs are in very good condition with only 10 of 6428 tubes having been plugged

(each SG has 3214 tubes). The applicant indicated that four tubes were preventively

plugged prior to operation, four tubes were plugged resulting from AVB wear and two

tubes were plugged resulting from damage incurred during maintenance activities. The

applicant also indicated that no tubes have been plugged as a result of corrosion-related

degradation. As discussed in SER Section 3.1, the staff requested the applicant to

provide a discussion regarding activities to address outside diameter stress corrosion

cracking (ODSCC) identified at the Seabrook plant in thermally treated Alloy 600 tubing

as outlined in INs 2002-21 and 2002-21 Supplement 1. The applicant stated that, as a

result of industry operating experience, ODSCC was considered as a potential :

degradation mechanism in the Unit 1 SG degradation assessment. The applicant also

included ODSCC as a potential degradation mechanism for the tubing in the Unit 2 SG,

but considers the Alloy 690 tubing to be more resistant to this type of degradation.

The applicant indicated that a special analysis was performed on the 2001 inspection

results by Westinghouse to look for the potential susceptibility foe ObSCC, which may

be indicated by drift in the eddy current signal. This analysis was performed on low row

tubes (row 8 and below). The applicant indicated that this analysis indicated that there

are 98 tubes that are potentially susceptible to ODSCC. Further, the applicant indicated

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that during the Spring 2004 SG inspection, these 98 tubes were inspected and analyzed

with a heightened sensitivity to ODSCC by the analysts. No indications were identified.

The applicant indicated that the most recent Unit 2 inspection results also indicated the

SGs are in very good condition with only four of 6998 tubes having been plugged (each

SG has 3499 tubes). All four of these tubes have been plugged as a precautionary

measure, two tubes were plugged as a result of small volumetric indications at the top of

the tubesheet and two tubes were plugged as a result of excessive eddy current noise.

The applicant indicated that no tubes have been plugged as a result of corrosion-related

degradation.

The applicant indicated that the SG secondary-side inspections to date have revealed

no degradation of the swirl vane, moisture separators, feed ring areas, J-tubes, or tube

support plates. The staff concluded that the operating experience supports the

applicant's conclusion that the Steam Generator Integrity Program provides reasonable

assurance that applicable aging effects will be managed during the license renewal

period.

The staff confirmed that the "operating experience" program element satisfies the

criteria defined in the GALL Report and SRP-LR Section A.1.2.3.10. The staff

concluded that this program attribute is acceptable.

FSAR Supplement. In LRA Section Al 5.2.19, the applicant provided the FSAR supplement for

the Steam Generator Integrity Program. The staff reviewed these sections and determined that

the information in the FSAR supplement provides an adequate summary of the program

activities. The staff found these sections of the FSAR supplement meet the requirements of

10 CFR 54.21 (d).

Conclusion. On the basis of is review and audit of the applicant's program, the staff found that

those program elements for which the applicant claimed consistency with the GALL Report are

consistent with the GALL Report. In addition, the staff reviewed the ten program elements and

determined that the AMP is adequate to manage the aging effects for which it is credited. The

staff found that the applicant had demonstrated that the effects of aging will be adequately

managed so that the intended functions will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the

FSAR supplement for this AMP and found that i provides an adequate summary description of

the program, as required by 10 CFR 54.21 (d).

3.0.3.2.19 Structures Monitoring Program

Summary of Technical Information in the ADolication. The applicant's Structures Monitoring

Program is described in LRA Section B2.1.20, "Structures Monitoring Program." The applicant

stated that this is an existing program that is consistent, with enhancements, with GALL AMP

XI.S5, "Masonry Wall Program," and GALL AMP XI.S6, "Structures Monitoring Program." The

applicant further stated that the Structures Monitoring Program is consistent, with exceptions

and enhancements, with GALL AMP XI.S7, "RG 1.127, Inspection of Water-Control Structures

Associated with Nuclear Power Plants," and GALL AMP XL.M23, "Inspection of Overhead

Heavy Load and Light Load (Related to Refueling) Handling Systems."

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The applicant stated that the Structures Monitoring Program manages the aging effects

associated with steel (including fasteners), concrete (including masonry block and grout),

earthen berms, and elastomers. The environments include below-grade and fluid-exposed

material, outdoor weather, and indoor air. The program includes all safety-related buildings,

structures within the containment, other buildings within the scope of license renewal, crane

bridge and trolley structures, and component supports (including high-energy line break [HELB]

structures and panels) within the scope of license renewal. The program provides for periodic

visual inspections and examination of accessible surfaces of the structures and components

and identifies the aging effects that impact the materials of construction.

The applicant also stated that of the various mechanisms for concrete degradation, only

cavitation and abrasion of concrete exposed to flowing water are considered to be of sufficient

significance to require aging management. However, this program also provides for

comprehensive management of other various potential degradation mechanisms for the

concrete structures within the scope of this program.

The Bolting Integrity Program credits this program for the inspection of all structural and

component support bolting within the scope of license renewal that is not within the scope of the

ASME Code Section Xl, Subsection IWF Inservice Inspection Program or Systems Monitoring

Program. Bolting associated with the supports for electrical cabinets, conduits, and cable trays

also is included within the scope of this program. Visual inspections of bolting are performed

concurrent with the structure inspection. The visual inspections check for corrosion, cracking,

missing or loose fasteners, and coating degradation.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. Details of the staff's audit evaluation are documented in the

staff's audit and review report. Furthermore, the staff reviewed the exceptions and associated

justifications to determine whether the AMP, with the exceptions, remains adequate to manage

the aging effects for which it is credited.

During the audit, the staff noted that, for the "scope of the program" program element for

Structures Monitoring Program, the applicant incorrectly describes the overhead crane locations

for cranes. In a letter dated July 12, 2004, the applicant committed to revise, as part of its LRA

annual update, the "scope of the program" program element for the Structures Monitoring Program to add more detail specifically describing overhead crane locations. On this basis, the

staff found that the scope of the applicant's program is consistent with the GALL AMP XI.M23.

The staff also noted that, for the "scope of the program" program element for the Structures

Monitoring Program, the applicant did not include steel edge supports and bracing for masonry

walls, as required by GALL AMP XI.S5. The applicant was requested to provide clarification

during the audit. In a letter dated July 12, 2004, the applicant committed to revise, as part of its

LRA annual update, the "scope of the program" program element for the Structures Monitoring

Program to add a description of the steel edge supports and bracing for masonry walls. On this

basis, the staff found that the scope of the applicant's program is consistent with the GALL

AMP XL.S5. i

In LRA Section B2.1.20, the applicant stated that its Structures Monitoring Program is

consistent with GALL AMP XI.S7, with exceptions. The Structures Monitoring Program takes

exception to the "scope of the program" program element for GALL AMP XI.S7 in that the

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applicant has not committed to RG 1.127, Revision 1 and does not include the intake crib,

intake pipes, or discharge flume within the scope of license renewal.

GALL AMP XL.S7 states that RG 1.127 applies to water-control structures associated with

emergency cooling water systems or flood protection of nuclear power plants. The water

control structures included in the RG 1.127 program are concrete structures, embankment

structures, spillway structures and outlet works, reservoirs, cooling water channels and canals,

intake and discharge structures, and safety and performance instrumentation.

As documented in the audit and review report, the applicant stated that its CIB takes an

exception to RG 1.127 in that PBNP does not include inspection of the intake crib, intake pipes,

or discharge flume as part of its CLB. This exception to the scope is addressed in SER

Section 2.4. The staff reviewed the inspection methods applied by the applicant and

determined that the inspections performed on the circulating water pumphouse are consistent

with RG 1.127.

On the basis of its review of the inspection methods, as documented in audit and review report,

the staff concluded that the inspection methods used by the applicant are consistent with

RG 1.127 and, therefore, meet the inspection criteria of GALL AMP XI.S7. On this basis, the

staff found the exception acceptable.

The Structures Monitoring Program also takes exception to the parameters monitored or

inspected" program element for GALL AMP XL.M23 in that the applicant does not keep records

of the number and magnitude of crane lifts that have been made.

GALL AMP XL.M23 states that, for the "parameters monitored or inspected" program element,

the program evaluates the effectiveness of the maintenance monitoring program and the

effects of past and future usage on the structural reliability of cranes. The number and

magnitude of lifts made by the crane are also reviewed.

The applicant stated that, although the records of the number and magnitude of lifts that have

been made are not kept, the applicant uses the cranes for the functions they were designed to

perform, and the cranes are inspected periodically. Crane usage is well within the design

capacity and service duty of the cranes. Any lifts in excess of rated crane capacity would be

evaluated and documented pursuant to ANSI B30.2.

As documented in the audit and review report, the applicant informed the staff that the crane's

service duty would not be exceeded during the period of extended operation. The applicant

directed the staff to LRA Section 4.3.13,-"Crane Load Cycle Limit." The staff reviewed this

section, as it related to crane operation, and determined that the expected number of lifts is

significantly less than the design criteria. On this basis, the staff found this exception

acceptable.

In LRA Section B2.1.20, the applicant stated that its Structures Monitoring Program is

consistent with GALL AMP XL.S5, XL.S6, Xl.S7, and XL.M23, with enhancements. The applicant

stated that, for the "detection of aging effects" program element, enhancements include

revisions to existing implementing documents to perform specific inspections related to aging

effects, indicate the parameters to be monitored, and provide acceptance criteria. New

implementing procedures will be created and/or existing procedures revised to include those

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components not presently inspected. The staff considered these types of enhancements to be

administrative enhancements that do not require staff review.

ODerating Experience. The staff reviewed the applicant's operating experience for the

Structures Monitoring Program.

The applicant stated that masonry walls are inspected pursuant to plant procedures. Cracks in

masonry walls have been found primarily at the mortar joints and these findings have been

documented and resolved. Concrete structure inspections have been and continue to be a

large part of the Structures Monitoring Program as described in plant procedures. Cracks,

erosion, corrosion of embedded steel, and concrete spalling have been observed. These

findings are evaluated and resolved by engineering. Periodic inspections of the circulating

water pumphouse have been an ongoing program. Divers perform inspections during refueling

outages. Minor degradation of these concrete structures has been found and recorded. Zebra

mussels are periodically removed from the forebay areas. The structural members of the

cranes that are in the scope of this program are inspected. There has been no

corrosion-related degradation found on these structure components.

Also, the applicant stated that no signs of physical damage have been observed on the earthen

berm around the above-ground fuel oil storage tanks. Industry operating experience has shown

that degradation occurs in structural steel and concrete components. The inspections

performed at PBNP as part of the Structures Monitoring Program have revealed that

degradation has occurred in both concrete and structural steel components. The inspection

results are recorded in an annual report. Any degradation determined to be a potential cause

of failure or indicative of changing conditions that may lead to an increased degradation rate is

documented in the corrective action program.

The applicant performed a review of NRC inspection reports, QA audit/surveillance reports, and

self-assessments since 1999. The review revealed no issues or findings that could impact the

effectiveness of the Structures Monitoring Program. In the first quarter of 2003 PBNP

performed a maintenance rule assessment, which reviewed the structural monitoring portion of

the maintenance rule. The assessment concluded that the overall structural monitoring

program was acceptable with program enhancements recommended. These enhancements

were entered into the corrective action program and resolved. As additional operating experience is obtained, lessons learned may be used to adjust this program.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical staff to verify that the plant-specific operating experience did not reveal

any degradation not bounded by industry experience. On the basis of its review of the above

industry and plant-specific operating experience, the staff concluded that the Structures

Monitoring Program will adequately manage the aging effects that are identified in the LRA for

which this AMP is credited.

Pi i; : . . ;, :: - -e I I

FSAR Supplement. In LRA Section Al 5.2.20, the applicant provided the FSAR supplement for

the Structures Monitoring Program. The staff reviewed these Sections and determined that the

information in the FSAR supplement provides an adequate summary of the program activities.

The staff found these sections of the FSAR supplement meet the requirements

10 CFR 54.21(d).

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Conclusion. On the basis of its review and audit of the applicant's program, the staff found that

those program elements for which the applicant claimed consistency with the GALL Report are

consistent with the GALL Report. In addition, the staff reviewed the exceptions and the

associated justifications and determined that the AMP, with the exceptions, is adequate to

manage the aging effects for which it is credited. The staff found that the applicant had

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff also reviewed the FSAR supplement for this AMP

and found that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

3.0.3.2.20 Water Chemistry Control Program

Summary of Technical Information in the Apolication. The applicant's Water Chemistry Control

Program is described in LRA Section B2.1.24, Water Chemistry Control Program." The

applicant stated that this is an existing program that is consistent, with exceptions and

enhancements, with GALL AMP XI.M2, "Water Chemistry."

The applicant stated that the objective of the Water Chemistry Control Program is to protect the

integrity, reliability, and availability of systems and components by managing the water

chemistry in plant systems to ensure that water quality is compatible with the materials of

construction and to minimize corrosion of internal surfaces exposed to corrosive environments.

The program monitors and controls water chemistry based on the guidelines in EPRI

TR-1 05714, "PWR Primary Water Chemistry Guidelines," for primary water chemistry and EPRI

TR-1 02134, "PWR Secondary Water Chemistry Guidelines," for secondary water chemistry.

The applicant also stated that the One-Time Inspection Program verifies that the Water

Chemistry Control Program is managing the effects of aging in low flow or stagnant areas.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. Details of the staff's audit evaluation are documented in the

staff's audit and review report. Furthermore, the staff reviewed the exceptions and associated

justifications to determine whether the AMP, with the exceptions, remains adequate to manage

the aging effects for which it is credited.

In LRA Section B2.1.24, the applicant stated that its Water Chemistry Control Program is

consistent with GALL AMP XI.M2, with exceptions. The Water Chemistry Control Program
optimization of primary water chemistry to address individual plant circumstances and the

impact of the NEI SG initiative, NEI 97-06, "Steam Generator Program Guidelines," which

recommends that utilities meet the intent of the EPRI guidelines. EPRI TR-1 05714, Revision 4,

attempts to clearly distinguish between prescriptive requirements and non-prescriptive

guidance.

EPRI TR-102134, Revision 5, provides additional details regarding plant-specific optimization

and clarifies which portions of the EPRI guidelines are mandatory under NEI 97-06.

The applicant also stated that a review of NRC inspection reports, QA audit/surveillance

reports, and self-assessments since 1999 revealed no issues that could impact the

effectiveness of the Water Chemistry Control Program. Additionally, industry experience

indicates that using the EPRI guidelines for water chemistry has proven very effective in

managing the degradation of primary and secondary SSCs. The EPRI water chemistry

guidelines are revised periodically based upon industry experience.

As documented in the audit and review report, the staff reviewed the information and held

discussions with the applicant's technical staff. On the basis of its review, the staff determined

that the use of EPRI guidelines, EPRI TR-1 05714, Revision 4, for primary water chemistry and

EPRI TR-1 02134, Revision 5, for secondary water chemistry, is acceptable. As discussed

above, these revisions improve the effectiveness of the Water Chemistry Control Program and

are expected to ensure proper aging management. Therefore, the staff found this exception

acceptable.

The Water Chemistry Control Program also takes exception to the "parameters monitored or

inspected" program element for GALL AMP XL.M2 in that (1) EPRI TR-1 05714, Revision 4, lists

pH and conductivity as primary water diagnostic parameters to be monitored during power

operation, but does not provide acceptance limits; (2) the applicant does not routinely monitor

for lead; (3) PBNP deviates slightly from EPRI TR-1 02134, Revision 5, in the manner in which

the hydrazine concentration is maintained; and (4) EPRI TR-102134, Revision 5, lists pH and

conductivity as secondary water diagnostic parameters to be monitored when the RCS

temperature is greater than 200 'F, but does not provide acceptance criteria.

GALL AMP XL.M2 states that the water quality (pH and conductivity) is maintained in

accordance with the EPRI guidelines. EPRI TR-1 05714, Revision 4, lists pH and conductivity

as primary water diagnostic parameters to be monitored during power operation but does not

provide acceptance limits.

As discussed in its evaluation for the "scope of the program" program element, the staff

determined thatthe use of EPRI guidelines, EPRI TR-105714, Revision 4, for primary water

chemistry and EPRI TR-102134, Revision 5, for secondary water chemistry, Is acceptable.

The applicant stated that during startup conditions with the reactor coolant system at greater

than 200 OF but at less than 5 percent reactor power, EPRI requires that hydrazine in the SG

feedwater source be maintained at greater than 100 ppb (or greater than eight times the

oxygen level, whichever is higher). The applicant does not have the capability for maintaining a

continuous hydrazine feed at these conditions. Alternatively, the applicant makes batch

additions of hydrazine to SGs through the auxiliary feedwater system to maintain detectable

hydrazine levels in the SG blowdown.

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The applicant also stated that making batch additions of hydrazine to the SGs through the

auxiliary feedwater system to maintain detectable hydrazine levels in the SG blowdown is

adequate to ensure that there is little dissolved oxygen in the SG bulk water supply to contribute

to corrosive conditions.

As documented in the audit and review report, the staff reviewed information provided by the

applicant and held discussions with the applicant's technical staff. On the basis of its review,

the staff determines that the proposed bulk addition of hydrazine and the use of EPRI

guidelines (EPRI TR-1 05714, Revision 4, for primary water chemistry, and EPRI TR-1 02134,

Revision 5, for secondary water chemistry) are appropriate. On this basis, the staff found this

exception acceptable.

In LRA Section B2.1.24, the applicant stated that its Water Chemistry Control Program is

consistent with GALL AMP XI.M2, with enhancements. The applicant stated that, for the

"detection of aging effects" and "monitoring and trending" program elements, enhancements

include revisions to existing implementing procedures to include the applicable aging effects.

Procedures will also be revised to require additional sampling after corrective actions have been

taken whenever a parameter is not within the specified value and continuous monitoring is not

available. The staff considered these types of enhancements to be administrative

enhancements that do not require staff review.

Operating Experience. The staff reviewed the applicant's operating experience for the Water

Chemistry Control Program.

The applicant stated that Its Water Chemistry Control Program has been in effect since initial

plant operation and has been effective at maintaining the desired system water chemistry and

detecting abnormal conditions, which have been corrected in an expedient manner. The

applicant stated that a review of condition reports/action requests supports the above statement

as most are related to abnormal chemistry results during operational transients such as

startups where the abnormal condition is expected, but the corrective action program is used for

documentation.

The EPRI guidelines for water chemistry are being used and the controlling procedures refer

and adhere to the limits specified in them. The applicant stated that, over time, this has proven

to be an effective method of controlling concentrations of parameters such as sulfates,

chlorides, fluorides, dissolved oxygen, lithium, sodium, iron, and copper that are detrimental to

certain alloys in both the primary and secondary systems. Controlling these parameters

mitigates aging effects in primary and secondary system components.

The applicant also performed a historical review of reactor coolant system data for sulfates as

an indicator of a resin intrusion event and did not reveal any evidence of such an event. An

assessment performed by PBNP in 2003 concluded that the chemistry program meets

expectations. A self-assessment conducted in mid-2003 concluded that the primary and

secondary water chemistry programs meet station requirements; however, some process

weaknesses exist. These process weaknesses are being tracked via the corrective action

program.

In addition, the applicant performed a review of NRC inspection reports, QA audit/surveiltance

reports, and self-assessments since 1999. The review revealed no other issues or findings that

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could Impact the effectiveness of the Water Chemistry Control Program. Review of

plant-specific operating experience also indicates that the chemistry program is performing its

function of mitigating aging effects. No reports were found that attributed water chemistry as

the cause of component deterioration, showing signs of aging effects, or failing to perform an

intended function. Action requests are initiated when water chemistry is found to be out of

specification, and most of the instances occur during start-up when parameters are quickly

changing and it is more difficult to control water chemistry. The time duration of

out-of-specification water chemistry is minimal and there is no evidence of its having caused

detrimental effects on system components. As additional operating experience is obtained,

lessons learned may be used to adjust this program.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical staff to verify that the plant-specific operating experience did not reveal

any degradation not bounded by industry experience. The staff concluded that the operating

experience is consistent with industry practice. In addition, the staff found that the historical

review results did not identify resin intrusion. On the basis of its review of the above industry

and plant-specific operating experience, the staff concluded that the Water Chemistry Control

Program will adequately manage the aging effects that are identified in the LRA for which this

AMP is credited.

FSAR Supplement. In LRA Section Al 5.2.24, the applicant provided the FSAR supplement for

the Water Chemistry Control Program. The staff reviewed these sections and determined that

the information in the FSAR supplement provides an adequate summary of the program

activities. The staff found these sections of the FSAR supplement meet the requirements of

10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant's program, the staff found that

those program elements for which the applicant claimed consistency with the GALL Report are

consistent with the GALL Report. In addition, the staff reviewed the exceptions and the

associated justifications and determined that the AMP, with the exceptions, is adequate to

manage the aging effects for which it is credited. The staff found that the applicant had

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff also reviewed the FSAR supplement for this AMP

and found that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

3.0.3.2.21 Environmental Qualification Program

Summary of Technical Information in the Application. The applicant's Environmental

Qualification Program is described in LRA Section B3.1, "Environmental Qualification Program."

The applicant stated that this is an existing program that is consistent, with enhancements, with

GALL AMP X.E1, "Environmental Qualification of Electric Components."

The applicant stated that the Environmental Qualification Program manages component

thermal, radiation and cyclical aging, as applicable, through the use of aging evaluations based

on 10 CFR 50.49(f) qualification methods. In accordance with 10 CFR 54.21 (c)(1 )(iii), the

Environmental Qualification Program, which implements the requirements of 10 CFR 50.49, is

viewed as an AMP for license renewal. As required by 10 CFR 50.49, EQ components not

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qualified for the current license term are to be refurbished, replaced, or have their qualification

extended prior to reaching the aging limits established in the evaluation. Aging evaluations for

EQ components that specify a qualification of at least 40 years are considered TLAAs for

license renewal. The Environmental Qualification Program ensures that these EQ components

are maintained within the bounds of their qualification bases.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. Details of the staff's audit evaluation are documented in the

staff's audit and review report.

In LRA Section B3.1, the applicant stated that its Environmental Qualification Program is

consistent with GALL AMP X.E1, with enhancements. The applicant stated that enhancements

to its Environmental Qualification Program include completing the EQ backlog elimination

project to eliminate the backlog of outstanding EQ related tasks and addressing the

recommendations from an independent assessment of the program, which include field

verification of EQ components and the completion of EQ checklist reviews. These

enhancements are intended to improve the overall health and effectiveness of the

Environmental Qualification Program. The staff considered these types of enhancements to be

administrative enhancements that do not require staff review.

Operatina Exoerience. The staff reviewed the applicant's operating experience for the

Environmental Qualification Program.

The applicant stated that although some program execution issues have previously been

experienced, a review of plant-specific and industry operating experience identified no

premature failures due to aging effects that could affect the qualified life of an EQ component.

The applicant also performed a review of the NRC Inspection reports, QA audit/surveillance

reports, and self-assessments since 1 999 to determine the effectiveness of its EQ program as

it currently exists. The applicant stated that numerous weaknesses were identified from a

design and programmatic perspective. These weaknesses are indicative of issues related to

executing existing PBNP commitments to 10 CFR 50.49 and do not indicate that changes are

needed to the requirements (i.e., scope, qualification methods, acceptance criteria) established

by these commitments. The Environmental Qualification Program, as currently committed to

10 CFR 50.49, provides reasonable assurance that the intended functions of EQ components

will be maintained through the period of extended operation.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical staff to verify that the plant-specific operating experience did not reveal

any degradation not bounded by industry experience. The staff concluded that the operating

experience is consistent with industry practice. In addition, the staff expects that the applicant's

corrective actions program will ensure that the program will perform its intended function during

the period of extended operation. On the basis of its review of the above industry and

plant-specific operating experience, the staff concluded that the Environmental Qualification

Program will adequately manage the aging effects that are identified in the LRA for which this

AMP is credited. -

FSAR Supolement. In LRA Sections Al 5.3.2 and Al 5.4.6, the applicant provided the FSAR

supplement for the Environmental Qualification Program. The staff reviewed these sections

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and determined that the information in the FSAR supplement provides an adequate summary of

the program activities. The staff found these sections of the FSAR supplement meet the

requirements of 10 CFR 54.21 (d).

Conclusion. On the basis of its review and audit of the applicant's program, the staff found that

those program elements for which the applicant claimed consistency with the GALL Report are

consistent with the GALL Report. The staff found that the applicant had demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3). The staff also reviewed the FSAR supplement for this AMP and found that

it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.22 Fatigue Monitoring Program

Summary of Technical Information in the ADplication. The applicant's Fatigue Monitoring

Program is described in LRA Section B3.2, 'Fatigue Monitoring Program." The applicant stated

that this is an existing program that is consistent, with enhancements, with GALL AMP X.M1,

'Metal Fatigue or Reactor Coolant Pressure Boundary."

The applicant stated that the Fatigue Monitoring Program is a confirmatory program that

monitors loading cycles due to thermal and pressure transients and cumulative fatigue usage

for ASME Code Class 1 and selected Class 2 components analyzed to Class 1 rules for which a

cyclic or fatigue design basis exists. The program provides an analytical basis for confirming

that the actual number of cycles does not exceed the number of cycles used in the design

analysis, and that the cumulative fatigue usage will be maintained below the allowable limit

during the period of extended operation. The impact of the effects of reactor coolant

environment on component fatigue life, which is a TLAA, has been evaluated for a sample of

critical components, including the seven component locations selected in NUREG/CR-6260,

"Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear Power Plant

Components." The results of these analyses are discussed in LRA Section 4.3. The staff's

evaluation of this TLAA is documented in SER Section 4.3. The acceptability of these critical

component locations, including the effects of reactor coolant environment, will continue to be

confirmed by the Fatigue Monitoring Program.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. Details of the staff's audit evaluation are documented in the

staff's audit and review report.

In LRA Section B3.2, the applicant stated that its Fatigue Monitoring Program !sconsistent with

GALL AMP X.M1, with enhancements. The applicant stated that, for the "detec ion of aging

effects" program element, enhancements to the program include moziifying exsi ng plant

documents to monitor loading cycles and fatigue usage, including the effects qf reactor water

environment. The staff considered this type of enhancement to be an administrative

enhancement that does not require-staff review.

Operatina Experience. The staff reviewed the applicant's operating experience for the Fatigue

Monitoring Program. I

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The applicant stated that it documented a comprehensive review of industry issues and

service-induced fatigue cracking since the late 1 970s for Class 1 and 2 components and how its

operating experience to date is addressed in the Fatigue Monitoring Program. The review

included industry and plant-specific fatigue cracking operating experience associated with main

feedwater piping and nozzle fatigue cracking resulting from thermal stratification cycling during

low flow and hot standby conditions (NRC Bulletin 79-13, "Cracking in Feedwater System

Piping"), potential for fatigue cracking in normally stagnant piping systems attached to the

reactor coolant system (NRC Bulletin 88-08, 'Thermal Stresses in Piping Connected to Reactor

Coolant Systems"), and thermal fatigue cracking of pressurizer surge piping (NRC

Bulletin 88-11, "Pressurizer Surge Line Thermal Stratification"). The applicant's Fatigue

Monitoring Program includes reviews of both industry and plant-specific operating experience

regarding fatigue cracking for applicability to PBNP. These ongoing reviews are considered

when selecting additional monitored components.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical staff to verify that the plant-specific operating experience did not reveal

any degradation not bounded by industry experience. On the basis of its review of the above

industry and plant-specific operating experience, the staff concluded that the Fatigue Monitoring

Program will adequately manage the aging effects that are identified in the LRA for which this

AMP is credited.

FSAR Supplement. In LRA Section Al 5.3.3, the applicant provided the FSAR supplement for

the Fatigue Monitoring Program. The staff reviewed these sections and determined that the

information in the FSAR supplement provides an adequate summary of the program activities.

The staff found these sections of the FSAR supplement meet the requirements of

10 CFR 54.21 (d).

Conclusion. On the basis of its review and audit of the applicant's program, the staff found that

those program elements for which the applicant claimed consistency with the GALL Report are

consistent with the GALL Report. The staff found that the applicant had demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3). The staff also reviewed the FSAR supplement for this AMP and found that

it provides an adequate summary description of the program, as required by 10 CFR 54.21 (d).

3.0.3.2.23 Pre-Stressed Concrete Containment Tendon Surveillance Program

Summary of Technical Information in the Application. The applicant's Pre-Stressed Concrete

Containment Tendon Surveillance Program is described in LRA Section B3.3, "Pre-Stressed

Concrete Containment Tendon Surveillance Program." The applicant stated that this is an

existing program that is consistent, with enhancements, with GALL AMP X.S1, "Concrete

Containment Tendon Prestress."

The applicant stated that the Pre-Stressed Concrete Containment Tendon Surveillance

Program is a confirmatory program that monitors the loss of containment prestressing forces in

containment tendons throughout the life of the plant, including the period of extended operation.

This program consists of an assessment of the results of the tendon prestressing force

measurements performed in accordance with ASME Code Section Xl, Subsection IWL The

assessment related to the adequacy of the prestressing forces will consist of the establishment

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of (1) acceptance criteria and (2) trend lines. The acceptance criteria will normally consist of a

predicted lower limit (PLL) and the minimum required prestressing force or value (MRV).

Staff Evaluation. The staff's review of LRA Section B3.3 identified areas In which additional

information was necessary to complete the review of the applicant's program elements. The

applicant responded to the staff's RAI as discussed below.

In RAls B3.3-1, B3.3-2, B3.3-3, and B3.3-4, dated January 12, 2005,*the staff requested the

applicant to provide clarification with respect to the "scope of the program," "preventive actions,"

and "corrective actions" program elements. The applicant responded to the staff's RAls in a

letter dated January 28, 2005.

During a meeting, on February 15, 2005, both the staff and the applicant agreed that if the Loss

of Prelaod TLAA is performed in accordance with 10 CFR 54.21 (c)(1)(ii) this AMP is not I

required. Based on discussions with the staff, in a letter dated March 15, 2005, the applicant

withdrew LRA Section B3.3. Deletion of the Pre-Stressed Concrete Containment Tendon

Surveillance Program is documented in the LRA annual update, dated February 23, 2005.

The staff found the Pre-Stressed Concrete Containment Tendon Surveillance Program deletion

acceptable.

FSAR SuDolement, The applicant deleted LRA Section B3.3, Pre-Stressed Concrete

Containment Tendon Surveillance Program; therefore, an FSAR supplement, LRA

Section Al 5.3.1, is not required.

Conclusion. Based on discussions between the staff and the applicant, NMC, in a letter dated

March 15, 2005, withdrew LRA Section B3.3. Deletion of this AMP is documented in the LRA

annual update, dated February 23, 2005. For the reasons discussed above, the staff found this

program deletion acceptable.

3.0.3.3 AMPs That Are Not Consistent with or Not Addressed In the GAU Report

In LRA Appendix B, the applicant indicated that the following AMPs were plant-specific:

* : Periodic Surveillance and Preventive Maintenance Program (B2.1.15)

* Systems Monitoring Program (62.1.21)

* Tank Intemal Inspection Program (B2.1.22)

* Thimble Tube Inspection Program (B2.1.23)

For AMPs that are not consistent with or not addressed by the GALL Report, the staff

performed a complete review of the AMPs to determine if they are adequate to monitor and/or

manage aging. The staff's review of these plant-specific AMPs is documented in the following

SER sections.

3.0.3.3.1 Periodic Surveillance and Preventive Maintenance Program

Summary of Technical Information. The applicant's Periodic Surveillance and Preventive

Maintenance Program is described in LRA Section B2.1.15, "Periodic Surveillance and

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Preventive Maintenance Program.' The applicant stated that this is an existing plant-specific

program. The applicant credits this program for managing the aging effects of certain SSCs

within the scope of license renewal. The program provides for inspection, examination, or

testing of selected structures and components, including fasteners, for evidence of age-related

degradation on a specified frequency based on operating experience or other requirements

(e.g., Technical Specification or ASME Code requirements). Additionally, the program provides

for replacement of certain components on a specified frequency based on operating

experience. The Periodic Surveillance and Preventive Maintenance Program is also used to

verify the effectiveness of other AMPs.

In a letter dated July 12, 2004, the applicant provided additional information concerning the

function and structure for the Periodic Surveillance and Preventive Maintenance Program.

Staff Evaluation. In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information

included in LRA Section B2.1.15, regarding the applicant's demonstration of the Periodic

Surveillance and Preventive Maintenance Program to ensure that the effects of aging, as

discussed above, will be adequately managed so that the intended functions will be maintained

consistent with the CLB throughout the period of extended operation.

The staff reviewed the Periodic Surveillance and Preventive Maintenance Program against the

AMP elements found in the SRP-LR Section A.1.2.3, and SRP-LR Table A.1-1 and focused on

how the program manages aging effects through the effective incorporation of 10 elements

(i.e., program scope, preventive actions, parameters monitored or inspected, detection of aging

effects, monitoring and trending, acceptance criteria, corrective actions, confirmation process,

administrative controls, and operating experience).

The applicant indicated that the corrective actions, confirmation process, and administrative

controls are part of the site-controlled quality assurance program. The staff's evaluation of the

quality assurance program is provided separately in SER Section 3.0.4. The remaining seven

elements are discussed below.

(1) Scope of the Program - The applicant stated that the Periodic Surveillance and

Preventive Maintenance Program consists of activities that manage the aging effects for

components in the following systems and structures: auxiliary feedwater, circulating

water, Units 1 and 2 containment building structure, containment ventilation, emergency

power, essential ventilation, main and auxiliary steam, non-Class 1 RCS components,

plant air, pressurizer, primary auxiliary building structure, residual heat removal, service

water, SG, and waste disposal.

The staff reviewed and confirmed that the "scope of the program" program element

satisfies the criterion defined in SRP-LR Section A.1.2.3.1. The proposed scope

identifies the specific components for which the program manages aging. On this basis,

the staff found that the applicant's proposed program scope is acceptable.

(2) Preventive Actions - The applicant stated that there are no preventive measures

associated with the aging effects of concern for license renewal.

The staff confirmed that the "preventive actions" program element satisfies the criterion

defined in SRP-LR Section A.1.2.3.2. The staff did not identify the need for preventive

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actions for this AMP because it Is a condition monitoring program. Therefore, the staff

found this conclusion acceptable.

(3) Parameters Monitored or Inspected - The applicant stated that the condition of selected

structures and components is monitored through inspection, examination, or testing for

evidence of age-related degradation on a specified frequency based on operating

experience or other requirements (e.g., Technical Specification or ASME Code

requirements). Certain components are also replaced on a specified frequency based

on operating experience.

The staff confirmed the "parameters monitored or inspected" program element satisfies

the criteria defined in SRP-LR Section A.1.2.3.3. The specified examination method is

capable of identifying and characterizing the parameter monitored and providing data

sufficient to conclude that the associated aging effect is adequately managed. On this

basis, the staff found that the program element is acceptable.

(4) Detection of Aging Effects - In LRA Section B2.1.15 and its letter, dated July 12, 2004,

the applicant stated that the aging effects of concern are detected by inspection,

examination, or testing of selected structures and components. Certain components are

also replaced on a specified frequency based on operating experience. The applicant

also stated that (1) the parameters that are monitored or inspected are linked to the

aging effects that are to be managed, (2) the Periodic Surveillance and Preventive

Maintenance Program and the 23 other AMPs that credit the Periodic Surveillance and

Preventive Maintenance Program adequately describe the data collection, and (3) the

examination methods of this program are capable of detecting the aging effects of

concern based on industry or plant operating experience.

The staff reviewed and confirmed that the "detection of aging effects" program element

satisfies the criterion defined in SRP-LR Section A.1.2.3.4. The detection of aging

effects identifies the specific components for which the program manages aging. On

this basis, the staff found that the applicant's program element is acceptable.

(5) Monitoring and Trending - In LRA Section B2.1.15 and its letter dated July 12, 2004, the

applicant stated that the Periodic Surveillance and Preventive Maintenance Program inspection, examination, testing, and component replacement activities credited for

license renewal are performed on a specified frequency based on operating experience

or other requirements (e.g., Technical Specification or ASME Code requirements). The

results of these surveillance and preventive maintenance activities are documented, and

subject to review and approval.

The staff confirmed that the umonitoring and trending" program element satisfies the

criteria defined in SRP-LR Section A.1.2.3.5. Trending of inspection results will be

performed and will enhance the applicant's ability to detect aging effects before there is

a loss of intended function. On this basis, the staff found that the applicant's program

element is acceptable.

(6) Acceptance Criteria - The applicant stated that the acceptance criteria for inspection,

examination, or testing of selected structures and components for evidence of

age-related degradation are provided in the surveillance and preventive maintenance

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activities credited for license renewal. The acceptance criteria are related to the aging

effect(s) of concern and are tailored to each individual inspection, examination, or test

considering the aging effect(s) being managed. An action request will be initiated

whenever the acceptance criteria are not met. Certain components are also replaced

on a given frequency based on operating experience.

The staff confirmed that the 'acceptance criteria" program element satisfies the criteria

defined in SRP-LR Section A.1.2.3.6. The control function performed by this program,

management controls (e.g., the corrective action program and action requests), are in

place in the event that acceptance criteria are not met. On this basis, the staff found

that the applicant's program element is acceptable.

(10) Operating Experience - The applicant stated that its Periodic Surveillance and

Preventive Maintenance Program has been effective in maintaining the intended

functions of long-lived passive SSCs. Surveillance and preventive maintenance

activities are effectively managed, with an improving trend noted in internal and external

assessments performed over the past several years. Numerous condition reports,

action requests, and work orders have been generated and resolved through the

implementation of this program. This experience demonstrates the effectiveness of this

program to identify and correct age-related degradation prior to a loss of intended

function.

The staff confirmed that the "operating experience" program element satisfies the

criteria defined.in SRP-LR Section A.1.2.3.610. The staff reviewed, as documented in

the staff's audit and review report, the operating experience provided in the LRA and

interviewed the applicant's technical staff to verify that the plant-specific operating

experience did not reveal any degradation not bounded by industry experience. The

staff concluded that the operating experience is consistent with the industry practice.

On the basis of its review of the above industry and plant-specific operating experience,

the staff concluded that the Periodic Surveillance and Preventive Maintenance Program

will adequately manage the aging effects that are identified in the LRA for which this

AMP is credited.

FSAR SuDplement. In LRA Section A15.2.15, the applicant provided the FSAR supplement for

the Periodic Surveillance and Preventive Maintenance Program. The staff reviewed these

sections and determined that the information in the FSAR supplement provides an adequate

summary of the program activities. The staff found these sections of the FSAR supplement

meet the requirements of 10 CFR 54.21 (d).

Conclusion. On the basis of its review and audit of the applicant's program, as discussed

above, the staff found that the applicant had demonstrated that the effects of aging will be

adequately managed so that the intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also

reviewed the FSAR supplement for this AMP and found that it provides an adequate summary

description of the program, as required by 10 CFR 54.21 (d).

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3.0.3.3.2 Systems Monitoring Program

Summary of Technical Information. The applicant's Systems Monitoring Program is described

in LRA Section B2.1.21, "Systems Monitoring Program." The applicant stated that this is an

existing plant-specific program with portions of the program that are consistent, with exceptions

and enhancements, with GALL AMP XI.M29, U Above Ground Carbon Steel Tanks." The

applicant credited this program for managing the aging effects for certain SSCs within the

scope of license renewal. The program manages aging effects for normally accessible external

surfaces of piping, tanks, and other components and equipment within the scope of license

renewal.

The applicant stated that the scope of its Systems Monitoring Program includes visual

inspections of the external surfaces of components. The Systems Monitoring Program is

credited by Boric Acid Corrosion Program, for the inspection of SSC that do not contain borated

water, but may be subject to the degrading effects of borated water leakage. The applicant

also stated that its Systems Monitoring Program is also credited by the Bolting Integrity

Program, for the inspection of bolting. The Systems Monitoring Program credited the Tank

Internal Inspection Program for the inspection of inaccessible portions of the condensate

storage tanks external surfaces (ie., tank bottoms).

Staff Evaluation. In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information

included in LRA Section B2.1.21, regarding the applicant's demonstration of the Systems

Monitoring Program to ensure that the effects of aging, as discussed above, will be adequately

managed so that the intended functions will be maintained consistent with the CLB throughout

the period of extended operation. Also, during its audit and review, the staff confirmed the

applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation are

documented in the staff's audit and review report. Furthermore, the staff reviewed the

exceptions and associated justifications to determine whether the AMP, with the exceptions,

remains adequate to manage the aging effects for which it is credited.

In LRA Section B2.0, "Aging Management Correlation," the applicant did not identify this AMP

as a plant-specific AMP. However, in the discussion of the Systems Monitoring Program, the

applicant stated that the System Monitoring Program is an existing plant-specific program.

Further, the applicant stated that, since this program includes visual inspection of the external

surfaces of carbon steel tanks, it is also an existing program that is consistent with, but includes

exceptions to, GALL AMP XI.M29, "Above Ground Carbon Steel Tanks."

The staff reviewed the Systems Monitoring Program against the AMP elements found in the

SRP-LR Section A.1.2.3, and SRP-LR Table A.1-1 and focused on how the program manages

aging effects through the effective incorporation of 10 elements (i.e., program scope, preventive

actions, parameters monitored or inspected, detection of aging effects, monitoring and trending,

acceptance criteria, corrective actions, confirmation process, administrative controls, and

operating experience). The staff also reviewed the consistency of this AMP with GALL

AMP XL.M29, which is integrated into the plant-specific evaluations.

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The applicant indicated that the corrective actions, confirmation process, and administrative

controls are part of the site-controlled quality assurance program. The staff's evaluation of the

quality assurance program is discussed in SER Section 3.0.4. The remaining seven elements

are discussed below.

(1) Scope of the Program - The applicant stated that for this program element, the Systems

Monitoring Program consists of activities that manage the aging effects for components

in the following systems and structures: auxiliary feedwater, chemical and volume

control, circulating water, component cooling water, containment hydrogen detectors

and recombiners, containment isolation components, containment spray, containment

ventilation, emergency power, essential ventilation, feedwater and condensate, fire

protection, heating steam, main and auxiliary steam, non-class 1 RCS components,

plant air, residual heat removal, safety injection, service water, spent fuel cooling,

treated water, and waste disposal.

The applicant also stated that its Systems Monitoring Program takes exceptions to the

scope of the program" program element for GALL AMP XL.M29 in that it does not take

credit for any coating or paint for mitigating corrosion even though the tanks may be

painted or coated. GALL AMP XLM29 recommends preventive measures to mitigate

corrosion by protecting the external surfaces of above-ground carbon steel tanks with

paint or coatings. The applicant stated that inspections of the coating or paint will

provide an indication of the condition of the material underneath the coating or paint.

As documented in the audit and review report, the staff reviewed the information and

held discussions with the applicant's technical staff. The staff found that surface

corrosion would not occur without affecting the coating or paint and such surface

degradation would be readily observable. On this basis, the staff found this exception

acceptable.

The staff reviewed and confirmed that the "scope of the program" program element

satisfies the criterion defined in SRP-LR Section A.1.2.3.1. The proposed scope

identifies the specific components for which the program manages aging. On this basis,

the staff found that the applicant's proposed program element is acceptable.

(2) Preventive Actions - The applicant stated that there are no preventive measures

associated with the aging effects of concern for license renewal.

The applicant also stated that its Systems Monitoring Program takes exception to the

"preventive actions" program element for GALL AMP XLI.M29 in that (1) it does not take

credit for any coating or paint for mitigating corrosion even though the tanks may be

painted or coated and (2) sealant or caulking is not used at the interface edge between

the tank and the concrete foundation for the condensate storage tanks and

above-ground fuel oil storage tanks.

GALL AMP XL.M29 recommends that sealant or caulking be used at the interface edge.

The applicant stated that the intemals of the above-ground fuel oil storage tanks were

inspected in 2000 and no significant rust deposits, corrosion, or other obvious defects

were found. Thickness measurements of the bottom of the tanks were performed and

indicated no significant loss of material. Subsequent to the inspection and thickness

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measurements, the tanks were upgraded. The upgrade installed a polyester resin

coating on the inside of the tanks, covering the bottoms and extending approximately

two feet up the tank walls. The applicant considered that future thickness

measurements are not necessary or practical, because of potential thickness

measurement complications due to the polyester resin coating, and the absence of any

significant material loss due to corrosion in over 30 years of service. This program

credits the Tank Internal Inspection Program for thickness measurements of the

inaccessible portions of the condensate storage tanks external surfaces (i.e., tank

bottoms).

As documented in the audit and review report, the staff reviewed the information and

held discussions with the applicant's technical staff. The staff found that (1) surface

corrosion would not occur without affecting the coating or paint and such surface

degradation would be expected to be readily observable and (2) that the applicant

added additional protection barriers to mitigate any future material loss on the

above-ground fuel oil storage tanks. On this basis, the staff found these exceptions

acceptable.

The staff confirmed that the "preventive actions" program element satisfies the criterion

defined in SRP-LR Section A.1.2.3.2. The staff did not identify the need for preventive

actions for this AMP because it is a condition monitoring program.

(3) Parameters Monitored or Inspected - The applicant stated that the program utilizes

periodic plant system walkdowns to monitor for leakage and evidence of material

degradation. Above-ground carbon steel tank external coatings or paint are inspected

to provide an indication of the condition of the material underneath the coating or paint.

Sealants or caulking at the tank/support structure interface, if used to prevent water

intrusion, are also inspected for degradation.

The staff confirmed the "parameters monitored or inspected" program element satisfies

the criteria defined in SRP-LR Section A. 1.2.3.3. The Systems Monitoring Program

examination method is capable of identifying and characterizing the parameter

monitored and providing data sufficient to conclude that the associated aging effect is

adequately managed. On this basis, the staff found that this program element is

acceptable.

(4) Detection of Aging Effects - The applicant stated that the external surfaces of various

component types (e.g., pump casings, valve bodies, piping, expansion joints) are

visually inspected for leakage and evidence of material degradation, such as loss of

material due to corrosion. The outer surfaces of above-ground carbon steel tanks are

visually inspected for signs of coating or paint degradation to provide an indication of the

condition of the material underneath the coating or paint. The sealant or caulking at the

tank/support structure interface, if used to prevent water intrusion, is also inspected for

degradation. This program credits the Tank Internal Inspection Program for the

inspection of inaccessible external surfaces of the Condensate Storage Tanks (i.e., tank

bottoms). Degradation of bolted connections is detected by visual inspections of the

bolted components during system walkdowns. Bolted connections are inspected for

missing fasteners and degradation such as damaged threads and evidence of corrosion.

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The applicant also stated that its Systems Monitoring Program takes exception to the

"detection of aging effects" program element for GALL AMP XLI.M29 in that thickness

measurements of the inaccessible external surfaces (i.e., tank bottoms) of the

above-ground fuel oil storage tanks are not performed. As discussed with respect to the

"preventive actions" program element, this tank was inspected and upgraded in 2000.

The inspection did not detect any significant material loss after 33 years of service and

the new internal coating provides additional barrier protection.

As documented in the audit and review report, the staff reviewed the information and

held discussions with the applicant's technical staff. The staff found that the applicant

provided additional protection barriers to mitigate any future material loss on the

above-ground fuel oil storage tanks. On this basis, the staff found these exceptions

acceptable.

In LRA Section B2.1.21, the applicant stated that the Systems Monitoring Program is

consistent with GALL AMP XI.M29, with enhancements. The applicant stated that, for

the "detection of aging effects" program element, enhancements include revisions to

existing implementing documents to strengthen the requirements for system walkdowns,

documentation and records retention, and provide inspection guidance. Additionally, the

aging effects and mechanisms to be managed will be incorporated into the existing

implementing documents. The staff considered these types of enhancements to be

administrative enhancements that do not require staff review.

The staff reviewed and confirmed that the "detection of aging effects" program element

satisfies the criterion defined in SRP-LR Section A.1.2.3.4. The System Monitoring

Program identifies the specific components for which the program manages aging. On

this basis, the staff found that the applicant's program element is acceptable.

(5) Monitoring and Trending - As modified by letter dated February 3, 2005, the applicant

stated that visual inspections are performed at least once per operating cycle within the

limits of accessibility. The inspection frequency may be increased based on the safety

significance, production significance, and operating experience of each system. These

system walkdown inspections provide for timely detection of aging effects (ie., prior to a

loss of intended function). Walkdown results are also documented to provide a

historical record of items monitored during the walkdowns. This program credits the

Tank Internal Inspection Program for the inspection of inaccessible portions of carbon

steel tank external surfaces, such as tank bottoms.

The applicant also stated that its Systems Monitoring Program takes exception to the

"monitoring and trending" program element for GALL AMP XI.M29 in that thickness

measurements of the inaccessible external surfaces of the above-ground fuel oil storage

tanks are not performed. This exception is evaluated in the "detection of aging effects"

program element, as discussed above. For the reasons discussed above, the staff

found this exception acceptable.

The staff confirmed that the "monitoring and trending" program element satisfies the

criteria defined in SRP-LR Section A.1.2.3.5. Detail of the staff's evaluation is

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documented in its audit and review report. Monitoring of inspection results will be

performed and will enhance the applicant's ability to detect aging effects before there is

a loss of intended function. On this basis, the staff found that the applicant's program

element is acceptable.

(6) Acceptance Criteria - The applicant stated that an action request (which provides a

means to document the finding and enter the concern into the plant's corrective action

program) will be initiated for any discrepancies found that may affect the component's

ability to perform its intended function (i.e., significant degradation). Other types of

degradation are recorded for further evaluation. When bolted joints for

pressure-retaining components are observed to have significant degradation or be

leaking, corrective actions are taken in accordance with the corrective action program.

An action request is also initiated for significant degradation of tank coatings or paint,

and sealants or caulking (if applicable). Significant degradation consists of cracking,

flaking, or peeling of paint or coatings, and cracked sealant or caulking (if applicable).

This program credits the Tank Internal Inspection Program for thickness measurements

of inaccessible portions of carbon steel tank external surfaces, such as tank bottoms.

Thickness measurements will be evaluated against the design thickness.

The staff confirmed that the uacceptance criteria" program element satisfies the criteria

defined in SRP-LR Section A.1.2.3.6. Details of the staff's evaluation are documented

in its audit and review report. The staff concluded that evaluating thickness against its

design criteria and implementation of the corrective action program is expected to

ensure appropriate aging management. On this basis, the staff found that the

applicant's program element is acceptable.

(10) Operating Experience - The applicant stated that degradation of components that are

within the scope of this program has been documented in accordance with plant

procedures in the engineer's system handbooks. This includes inspections of bolting

and the external surfaces of tanks. A review of documentation for seven systems within

the scope of license renewal indicated that these walkdowns usually result in the

initiation of corrective Work Orders for the repair of minor leaks from both flanged

connections and valve stem packing, degraded grout under pumps, or pipe supports.

Thickness measurements of the bottoms of the above-ground fuel oil storage tanks

were performed in August of 2000, which indicated no significant loss of material due to

corrosion in over 30 years of service. A review of NRC inspection reports, QA

audit/surveillance reports, and self-assessments since 1999 revealed no issues or

findings that could impact the effectiveness of the Systems Monitoring Program.

The staff confirmed that the "operating experience" program element satisfies the

criteria defined in SRP-LR Section A.1.2.3.610. The staff reviewed, as documented in

the staff's audit and review report, the operating experience provided in the LRA and

interviewed the applicant's technical staff to verify that the plant-specific operating

experience did not reveal any degradation not bounded by industry experience. On the

basis of Its review of the above industry and plant-specific operating experience, the

staff concluded that the Systems Monitoring Program will adequately manage the aging

effects that are identified in the LRA for which this AMP is credited.

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FSAR Supplement. In LRA Section Al5.2.21, the applicant provided the FSAR supplement for

the system monitoring program. The staff reviewed these sections and determined that the

information in the FSAR supplement provides an adequate summary of the program activities.

The staff found these sections of the FSAR supplement meet the requirements

10 CFR 54.21 (d).

Conclusion. On the basis of its review and audit of the applicant's program, the staff found that

those program elements for which the applicant claimed consistency with the GALL Report are

consistent with the GALL Report. In addition, the staff reviewed the exceptions and the

associated justifications and determined that the AMP, with the exceptions, is adequate to

manage the aging effects for which it is credited. The staff found that the applicant had

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff also reviewed the FSAR supplement for this AMP

and found that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

3.0.3.3.3 Tank Internal Inspection Program

Summary of Technical Information in the ApDlication. The applicant's Tank Internal Inspection

Program is described in LRA Section B2.1.22, "Tank Internal Inspection Program." In the LRA,

the applicant stated that this is a new, plant-specific program.

The Tank Intemal Inspection Program manages aging effects on (1) internal surfaces of carbon

steel tanks, and (2) inaccessible external surfaces of carbon steel tanks (i.e., tank bottoms) in

the auxiliary feedwater and emergency power systems. This program is credited by the

Systems Monitoring Program for thickness measurements of the bottom of carbon steel tanks

that are sitting directly on the ground or other structures such that external inspection of all

surfaces is not possible.

This program provides for periodic inspections to confirm that aging effects will not impair

tank intended functions. Tank wall thinning of internal surfaces may be detected by direct

visual inspection from inside the tank or indirectly by UT wall thickness measurements from

outside the tank. Tank wall thinning of external surfaces that are inaccessible will be detected

by UT wall thickness measurements from inside the tank.

This new program is scheduled for implementation prior to the period of extended operation.

The applicant does not claim that this program is consistent with the GALL Report.

Staff Evaluation. In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information

included in LRA Section B2.1.22, regarding the applicant's demonstration of the Tank Internal

Inspection Program to ensure that the effects of aging, as discussed above, will be adequately

managed so that the intended functions will be maintained consistent with the CLB throughout

the period of extended operation.

The staff reviewed the Tank Internal Inspection Program against the AMP elements found in

the SRP-LR, Appendix A, Section A.1.2.3, and SRP-LR Table A.1-1 and focused on how the

program manages aging effects through the effective incorporation of 10 elements

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(i.e., program scope, preventive actions, parameters monitored or inspected, detection of aging

effects, monitoring and trending, acceptance criteria, corrective actions, confirmation process,

administrative controls, and operating experience).

The applicant indicated that the corrective actions, confirmation process, and administrative

controls are part of the site-controlled quality assurance program. The staff's evaluation of the

quality assurance program is discussed in SER Section 3.0.4. The remaining seven elements

are discussed below.

(1) Scope of the Program - The applicant stated that the Tank Internal Inspection Program

consists of plant-specific activities that manage the aging effect for components in the

auxiliary feedwater and emergency power systems. The applicant credits the program

for managing the aging effect loss of material due to corrosion on the internal and

inaccessible external surfaces (i.e., tank bottoms) of carbon steel tanks.

The staff confirmed that the "scope of the program" program element satisfies the

criterion defined in SRP-LR Section A.1.2.3.1. The staff concluded that this program

attribute is acceptable.

(2) Preventive Actions - The applicant stated that this is an inspection program and as such

there are no credited preventive actions. The applicant indicated that some tanks may

have internal coatings that aid in preventing loss of material and corrosion. However,

the applicant does not credit the coatings for prevention of corrosion within the

applicant's program. The applicant stated the coatings will be used as an indicator of

substrate condition during visual inspection when available. The staff agrees that the

Tank Internal Inspection Program does not include preventive actions and that coatings

may be used as an indicator of substrate condition.

The staff confirmed that the "preventive actions" program element satisfies the criterion

defined in SRP-LR Section A.1.2.3.2. The staff concluded that this program attribute is

acceptable.

(3) Parameters Monitored or Inspected - The applicant stated that the internal surfaces of

carbon steel tanks will be periodically visually inspected for the existence of corrosion.

Also, the applicant will perform UT thickness measurements to inspect inaccessible

external surfaces of carbon steel tanks (Le., tank bottoms) and may be used from

outside on portions of tanks inaccessible for internal visual inspection to detect wall

thinning due to corrosion. As discussed below, with regard to the 'detection of aging

effects" program elements, the staff requested the applicant to provide additional

information regarding the extent of the visual inspection and the UT inspections that will

be performed for this program. The applicant responded by indicating that visual

inspection of the condensate storage tank (CST) will consist of 100 percent of the

internal tank surface. The UT inspections of the tank bottom will sample a

representative area of the bottom using a grid system. Engineering judgment and

previous sample results will be employed by the applicant to establish the grid size. The

applicant stated that if degradation is identified, the grid sample size will be reduced to

determine the extent of degradation. The staff concluded that the program will

adequately monitor for internal tank age-related degradation, a 100 percent internal

visual surface inspection of the CST and UT thickness measurements of the tank

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bottom will be performed. The staff agrees that visual inspection and UT thickness

measurements are capable of detecting degradation potentially affecting tank internals.

The staff confirmed that the "parameters monitored or inspected" program element

satisfies the criterion defined in SRP-LR Section A.1.2.3.3. The staff concluded that the

program will adequately monitor age-related degradation and, therefore, is acceptable.

(4) Detection of Aging Effects - The applicant stated that loss of material caused by

corrosion will be determined by periodic visual inspection and UT inspection of

components within the program scope. Visual inspection will utilize signs of loss of

material resulting from degraded coatings, discoloration, pitting and other signs of

corrosion. UT inspection will detect loss of wall thickness for tank bottoms and external

portions of tanks when the external surfaces are inaccessible for visual inspection.

Where visual inspection indicates a loss of material, UT may be used to assess the wall

thickness to determine the extent of corrosion. The applicant indicated that the

inspection frequency will be based upon operating experience and the results of

previous inspections. The applicant indicated that corrective action will be taken

whenever acceptance criteria are not met or significant degradation of carbon steel

internal tank coating is identified.

The staff's review of LRA Section B2.1.22 identified an area in which additional

information was necessary to complete the review of the applicant's program elements.

The applicant responded to the staff's RAI as discussed below.

RAI B2.1.22-1. In RAI B2.1.22-1, dated November 18,2004, the staff requested the

applicant to provide additional information relative to the periodicity of inspection, the

inspection scope and bases for the inspection strategies. In its response, dated

January 6, 2005, the applicant stated that 100 percent internal surface visual inspection

of the condensate storage tanks is conducted at four- to five-year intervals. The

applicant indicated that UT inspection of the tank bottom will be conducted on a

representative sample of the tank bottom using a grid pattern. The grid size will be

based upon engineering judgment. If degradation is identified, a smaller grid will be

employed, as well as additional UT measurements to determine the extent of

degradation. UT inspection of the tank bottom will be conducted prior to the period of

extended operation. Periodic additional UT inspection of the tank bottom will be

conducted based upon the results of the initial UT inspection. The DG starting air

receivers are inspected at three-year intervals using a combination of internal visual and

external UT inspection. Inspections conducted in 2002 and 2003 revealed no adverse

conditions.

The staff concluded that the applicant's response is acceptable. The tanks are currently

inspected on an established periodicity that is expected to manage aging resulting from

loss of material prior to loss of the component's function. The staff also concluded that

the applicant's inspections of the condensate storage tank bottoms prior to the period of

extended operation is acceptable. This inspection is expected to provide reasonable

assurance that potential age-related degradation of the tank bottom will be identified

prior to the period of extended operation. The inspection results will be utilized to

determine future inspection periodicity. The staff's concern described in RAtI B2.t 22-1

is resolved.

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For the reasons discussed above, the staff confirmed that the 'detection of aging

effects" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.4.

The staff concluded that this program attribute is acceptable.

(5) Monitoring and Trending - The applicant stated that monitoring and trending will occur if

loss of material is detected.

The staff's review of LRA Section B2.1.22, identified areas in which additional

information was necessary to complete the review of the applicant's program elements.

The applicant responded to the staff's RAls as discussed below.

RAI B2.1.22-2. In RAI B2.1.22-2, dated November 18, 2004, the staff requested the

applicant to provide additional information relative to when monitoring and trending

would occur and how accurate rates of degradation would be determined.

RAI B2.1.22-3. In RAI B2.1.22-3, dated November 18, 2004, the staff requested the

applicant to explain what is considered as usignificant material loss (as identified in

detection of aging effects).

In its response, dated January 6, 2005, the applicant stated that significant coating

degradation was considered to exist when the bare substrate was exposed as a result of

the degraded coating, and that significant material loss requiring trending is considered

to exist when a detectable reduction in the wall thickness exists.

The staff concluded the applicant's response is acceptable. The applicant is expected

to commence trending whenever a detectable reduction in wall thickness is identified

that Is expected to support accurate assessment of aging. The staff's concerns

described in RAls B2.1.22-2 and B2.1.22-3 are resolved.

For the reasons discussed above, the staff confirmed that the "monitoring and trending"

program element satisfies the criteria defined in SRP-LR Section A.1.2.3.5. The staff

concluded that this program attribute is acceptable.

(6) Acceptance Criteria - The applicant stated that any degradation of the carbon steel tank

internal surfaces will be recorded and evaluated to ensure minimum wall thickness is

maintained until the next scheduled inspection. The applicant also indicated that

thickness measurements of inaccessible tank bottoms will be evaluated against design

thickness values.

The staff confirmed that the "acceptance criteria" program element satisfies the criteria

defined in SRP-LR Section A.1.2.3.6. If degradation is identified, the program's

evaluation will attempt to ensure that minimum or design thickness values will not be

exceeded in the operating interval prior to the next inspection. The staff concluded that

this program attribute is acceptable.

(10) Operating Experience - The applicant stated that in January, 2000, a visual inspection of

the south condensate storage tank was conducted. The applicant's inspection identified

minor surface rust on the floor of the tank and signs of corrosion through the tank

coating on the lower 6 to 8 inches of the tank wall. The applicant documented the

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observation in a condition report and evaluated the condition of the tank and coating.

The applicant stated that the north condensate storage tank was also inspected as a

result of the conditions identified in the south condensate storage tank. The inspection

of the north condensate storage tank revealed minor surface rust, similar to that found in

the other tank. An engineering evaluation was performed by the applicant on both

tanks; the tanks were cleaned and returned to service.

The applicant indicated that the emergency diesel generator starting air receivers, G01

and G02 pressure vessels, are periodically inspected in accordance with Wisconsin

Administrative Code requirements. The applicant used visual inspection and UT

thickness measurements to inspect the starting air receivers in 2002 and 2003 and

found no adverse conditions.

The staff's review of LRA Section B2.1.22, identified an area in which additional

information was necessary to complete the review of the applicant's program elements.

The applicant responded to the staff's RAI as discussed below.

RAI B2.1.22-4. Based on related operating experience, tank internal inspections of the

north and south condensate tanks have occurred. In RAI B2.1.22-4, dated

November 18, 2004, the staff requested the applicant to clarify if these inspections

included UT of the tank bottoms. In its response, dated January 6, 2005, the applicant

stated that the referenced inspections did not include UT of the tank bottoms. The

applicant also stated that, upon implementation of the Tank Internal Inspection Program

AMP, condensate tank inspections will include UT of the tank bottoms as a means to

monitor any significant corrosion. The applicant indicated that the latest inspection

occurred in 2002.

The staff concluded that the applicant's related operating experience is acceptable. It

illustrates that the applicant recently completed inspections of components within the

program. The operating experience illustrated that, where conditions indicated a

potential loss of material, evaluations were performed to assess the tank condition and

the inspection scope was expanded to similar components. The staff's concern

described in RAI B2.1.22-4 is resolved.

For the reasons discussed above, the staff confirmed that the "operating experience"

program element satisfies the criteria defined in SRP-LR Section A.1.2.3.10. The staff

concluded that this program attribute is acceptable.

FSAR SugPlement. In LRA Section Al 5.2.22, the applicant provided the FSAR supplement for

the Tank Internal Inspection Program. The staff reviewed these sections and determined that

the information in the FSAR supplement provides an adequate summary of the program

activities. The staff found these sections of the FSAR supplement meet the requirements of

10 CFR 54.21 (d).

Conclusion. On the basis of its review, the RAI responses discussed above, and its audit of the

applicant's program, the staff found the AMP exceptions and the associated justifications, are

adequate to manage the aging effects for which it is credited. The staff found that the applicant

had demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

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required by 10 CFR 54.21 (a)(3). The staff also reviewed the FSAR supplement for this AMP

and found that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

3.0.3.3.4 Thimble Tube Inspection Program

Summary of Technical Information in the ApDlication. The applicant's Thimble Tube Inspection

Program is described in LRA Section B2.1.23, "Thimble Tube Inspection Program." In the LRA,

the applicant stated that this is an existing, plant-specific program.

The staff's regulatory basis for establishment of the applicant's Thimble Tube Inspection

Program is given in NRC Bulletin 88-09, "Thimble Tube Thinning in Westinghouse Reactors,"

dated July 26, 1988, which was addressed to all holders of operating licenses or construction

permits for nuclear reactors designed by Westinghouse that utilize bottom-mounted

instrumentation. In this Bulletin, the staff requested that the addressees establish a Thimble

Tube Inspection Program with the following attributes:

* Establish, with technical justification, an appropriate thimble tube wear acceptance

criterion (e.g., percent through-wall loss). The staff recommended that the acceptance

criterion should include allowances for such items as inspection methodology and wear

scar geometry uncertainties.

* Establish, with technical justification, an appropriate inspection frequency.

* Establish an inspection methodology that is capable of adequately detecting wear of the

thimble tubes, such as eddy current testing (ECT).

Staff Evaluation. In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information

included in LRA Section B2.1.23 regarding the applicant's demonstration that the Thimble Tube

Inspection Program will ensure that the effects of aging, as discussed above, will be adequately

managed so that the intended functions will be maintained consistent with the CLB throughout

the period of extended operation.

The staff reviewed the Thimble Tube Inspection Program against the AMP elements found In

the SRP-LR, Appendix A, Section A.1.2.3 and SRP-LR Table A.1-1 and focused on how the

program manages aging effects through the effective incorporation of 10 elements (i.e.,

program scope, preventive actions, parameters monitored or;inspected, detection of aging

effects, monitoring and trending, acceptance criteria, corrective actions, confirmation process,

administrative controls, and operating experience).

The applicant indicated that the corrective actions, confirmation process, and administrative

controls are part of the site-controlled quality assurance program. The staff's evaluation of the

quality assurance program is discussed in SER Section 3.0.4. The remaining seven elements

are discussed below.

(1) Scope of the Program - The applicant stated that the program will include flux map

thimble tubes for both units. The program utilizes ECT to determine thimble tube wall

thickness and predict wear rates for the early identification of potential thimble tube

failures. All of the thimble tubes on both units will be periodically inspected. The

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applicant confirmed that it will continue to perform 100 percent inspection and the

inspection frequency will be based on the wear rates.

The staff's review of LRA Section B2.1.23 identified an area in which additional

information was necessary to complete the review of the applicant's program elements.

The applicant responded to the staff's RAI as discussed below.

RAI B2.1.23-1.- In RAI B2.1.23-1, dated November 17, 2004, the staff requested the

applicant to explain the determination of wear rates and the impacts of uncertainties.

In its response, dated January 25, 2005, the applicant stated that to ensure that tube

failure does not occur between inspections, tubes predicted to exhibit a wall loss in

excess of 60 percent before the next inspection will be capped and taken out of service.

The 60 percent criterion is based on maximum allowable wall loss of 83 percent, a 10

percent error in ECT, and a 10 percent uncertainty in wall loss geometry. The staff

concluded that the applicant's approach to inspection frequency is acceptable. The staff

found that the applicant implements conservative measures and appropriate corrective

actions, therefore, the staff's concern described in RAI B2.1.23-1 is resolved.

The staff confirmed that the "scope of the program" program element satisfies the

criterion defined in SRP-LR Section A.1.2.3.1. The staff concluded that this program

attribute is acceptable.

(2) Preventive Actions - The applicant stated that the evaluation of the remaining thimble

tube wall thicknesses, obtained from the ECT, will be used to predict the remaining life

of the thimble tubes and to take corrective action before the failure occurs. The staff

determined that the Thimble Tube Inspection Program is an inspection-based condition

monitoring program and that, as such, does not include preventive or mitigative actions

to preclude the occurrence of an aging effect.

(3) Parameters Monitored or Inspected - The applicant stated that wall thickness will be

monitored using ECT through periodic inspections

The staff confirmed that the "parameters monitored or inspected" program element

satisfies the criterion defined in SRP-LR Section A.1.2.3.3. Since ECT is a standard

NDE technique that is appropriate for the detection of wear, the staff concluded that the

applicant's program attribute is acceptable.

(4) Detection of Aging Effects - The applicant stated that wear is detected by periodic ECT

of the thimble tubes. One hundred percent of the thimble tubes are examined in each

thimble tube inspection cycle. The data will be evaluated and remaining wall thickness

will be calculated along with the remaining years of life expectancy. In addition, the next

inspection cycle will be determined and will take place prior to expiration of calculated

expected life. The applicant stated that this will ensure that no leaks occur due to wear

of a thimble tube. The applicant will be using ECT inspection methods and, therefore,

will detect any aging effects on the thimble tubes. The applicant also confirmed, in

response to RAI B2.1.23-1 above, that inspections will normally be performed during the

outage prior to the outage identified with the lowest minimum thimble tube lifecalculation, or at least every six years, to ensure conservative testing intervals. For

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example, if the lowest minimum thimble tube life is 5.5 years, the next inspection would

be at 3 years, one outage prior to the 4.5 year outage.

The staff confirmed that the "detection of aging effects" program element satisfies the

criterion defined in SRP-LR Section A.1.2.3.4. The process adequately provides a

method of identifying aging effects and the time to act accordingly. Therefore, the staff

concluded that this program attribute is acceptable.

(5) Monitoring and Trending - The applicant stated that the ECT results will be trended and

wear rates will be calculated. The wear rate is calculated by considering the total wall

loss over the life of the thimble tube divided by the operating time of the tube. The

frequency of inspection is based on the maximum wall loss noted in a region of active

fretting and the projected wear that would occur based on a known wear rate. The wear

rate is determined for each thimble tube and wear location (i.e., thimble tubes may have

fretting wear at multiple locations).

The staff confirmed that the "monitoring and trending" program element satisfies the

criteria defined in SRP-LR Section A.1.2.3.5. Based on the above described monitoring

and trending plan, the staff concluded that the program attribute is conservative and

failures of the tubes will be prevented prior to a leak occurring. The staff, therefore,

concluded that this program attribute is acceptable.

(6) Acceptance Criteria - The applicant stated that the thimble tubes will be capped if their

indicated wall loss plus the predicted wall loss before the next inspection exceeds 60

percent. This is a conservative criterion, since calculations have shown that a tube

would have to wear 83 percent of wall tube thickness prior to failing and causing a leak.

The 83 percent loss of wall tube failure determination was also conservatively

calculated, since it assumes even wear around the tube although wear is a localized

degradation mode. As discussed in RAI B2.1.23-1, the applicant stated that the 60

percent criterion includes consideration of error in ECT inspection and uncertainty in wall

loss geometry. In addition, the applicant's inspection will normally be performed during

the outage prior to the outage that would be identified with the lowest minimum thimble

tube life calculation, or at least every six years, to ensure conservative testing intervals.

The staff confirmed that the "acceptance criteria, program element satisfies the criteria

defined in SRP-LR Section A.1 .2.3.6. Based on the above discussion, the staff

concluded that the applicant provided an appropriate wall loss acceptance criteria. The

staff, therefore, concluded that this program attribute is acceptable.

(10) Operating Experience - The applicant stated that thimble tubes were replaced in 1985

for Unit 1 and in 1984 for Unit 2 due to internal blockages. No leaking in core thimble

tubes was discovered during the first 13 years of operation. The replacement tubes are

made of Type 316 stainless steel with a nominal outside diameter of 0.313 inches and a

nominal inside diameter of 0.21 inches.

The Thimble Tube Inspection Program was initiated in response to NRC Bulletin 88-09.

As a result of inspections performed by the program, five tubes on Unit 1 have been

replaced, due to wear, since 1985. One of these five tubes had been capped, one other

showed significant wear and three others were replaced because they showed the most

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wear of the remaining tubes. These last three tubes were not at minimum wall thickness

nor did any calculations indicate that they would be at a minimum wall thickness before

the next inspection.

In the LRA, the applicant discussed several concerns related to inspection deferrals,

calculation methodology, and record retention. As discussed above with respect to the

resolution of RAI B2.1.23-1, the applicant stated the following:

* In the past it has deferred the thimble tube inspections for both units. However,

in no case did the inspection interval exceed the lowest minimum thimble tube

life on either unit. These deferrals were without a documented evaluation

showing that there would be no problems with the extended inspection interval.

The current implementing document requires an engineering evaluation or

calculation to be performed, demonstrating with a high degree of confidence that

there would be no thimble tube problems with an extended inspection interval

prior to deferral being allowed.

* Following the Unit 2 thimble tube inspection performed during the 2000 refueling

outage, it was discovered that the ECT contractor had reported the results using

an averaged flaw depth method (i.e., mixed frequency and amplitude wall loss)

instead of the worst case flaw depth method (ie., maximum wall loss). The

results were subsequently reanalyzed using the worst case flaw depth method.

It was also discovered that the worst case flaw depth method has been largely

replaced in the industry with the mixed frequency amplitude wall loss method.

Future inspections may be analyzed using both of these methods to determine if

PBNP should change to the current industry standard method.

* The concern expressed in the LRA regarding record retention involved copies of

the official records maintained by the Thimble Tube Condition Assessment

Engineer for ease of reference. The previous Thimble Tube Condition

Assessment Program Engineer had disposed of these working copies, since

they were redundant to the official records being maintained. However, in all

cases, the official records were retained and stored appropriately.

By letter, dated July 19, 2005, the applicant informed the staff that two inspections have

occurred in 2004 and 2005. Based on a review of those results, NMC concluded that

the current industry method is appropriate; therefore, NMC is adopting the current

industry standard of the mixed frequency amplitude wall loss data analysis method to

begin during the PBNP fall 2005 Unit 1 refueling outage. The staff found this

acceptable, as both methods (average flaw depth and worse case flaw depth) were

previously found satisfactory.

The staff confirmed that the "operating experience" program element satisfies the

criteria defined in SRP-LR Section A.1.2.3.10. The applicant demonstrated operating

experience of no leakage due to failure of thimble tubes. Moreover, the process of

inspection deferral, calculation methodology, and record retention have been

appropriately addressed. The staff concluded that this program attribute is acceptable.

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FSAR Supplement. In LRA Section A15.2.23, the applicant provided the FSAR supplement for

the Thimble Tube Inspection Program. The staff reviewed these sections and determined that

the information in the FSAR supplement provides an adequate summary of the program

activities. The staff found these sections of the FSAR supplement meet the requirements of

10 CFR 54.21(d).

Conclusion. On the basis of its review, the RAI response discussed above, and its audit of the

applicant's program, the staff found that the AMP exceptions and the associated justifications

are adequate to manage the aging effects for which it is credited. The staff found that the

applicant had demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the FSAR supplement

for this AMP and found that it provides an adequate summary description of the program, as

required by 10 CFR 54.21 (d).

3.0.4 Quality Assurance Program Attributes Integral to Aging Management Programs

Pursuant to 10 CFR 54.21 (a)(3), a license renewal applicant is required to demonstrate that the

effects of aging on SCs subject to an AMR will be adequately managed so that their intended

functions will be maintained consistent with the CLB for the period of extended operation.

NUREG-1800, Branch Technical Position RLSB-1, "Aging Management Review - Generic,"

describes ten attributes of an acceptable AMP. Three of these ten attributes are associated

with the QA activities of corrective action, confirmation process, and administrative control.

Branch Technical Position RLSB-1 Table A.1 -1, "Elements of an Aging Management Program

for License Renewal," provides the following description of these quality attributes:

* corrective actions, including root cause determination and prevention of recurrence,

should be timely;

* the confirmation process should ensure that preventive actions are adequate and that

appropriate corrective actions have been completed and are effective; and

* administrative controls should provide a formal review and approval process.

NUREG-1 800, Branch Technical Position IOMB-I, "Quality Assurance For Aging Management Programs," noted that those aspects of the AMP that affect quality of safety-related SSCs are

subject to the QA requirements of 10 CFR Part 50, Appendix B. Additionally, for

nonsafety-related SCs subject to an AMR, the existing 10 CFR Part 50, Appendix B, QA

program may be used by the applicant to address the elements of corrective action,

confirmation process, and administrative control. Branch Technical Position IQMB-1 provides

the following guidance with regard to the QA attributes of AMPs:

* Safety-related SCs are subject to 10 CFR Part 50, Appendix B, requirements which are

adequate to address all quality-related aspects of an AMP consistent with the CLB of

the facility for the period of extended operation.

* For, nonsafety-related SCs that are subject to an AMR, an applicant has an option to

expand the scope of its 10 CFR Part 50, Appendix B, program to include these SCs to

address corrective action, confirmation process, and administrative control for aging

management during the period of extended operation. In this case, the applicant should

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document such commitment in the FSAR supplement in accordance with

10 CFR 54.21(d).

3.0.4.1 Summary of Technical Information

LRA Section 3.0 provides an AMR summary for each unique structure, component, or

commodity group at Units 1 and 2 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. LRA Appendices A and B

demonstrate how the identified programs manage aging effects using attributes consistent with

the industry and NRC guidance. In LRA Section A15.1, the applicant stated that the QA

program includes the elements of corrective action, confirmation process, and administrative

controls and is applied to both safety-related and nonsafety-related SSCs that are within the

scope of license renewal. In LRA Section B1.3, the applicant discusses the implementation of

10 CFR Part 50, Appendix B, and its consistency with the summary in NUREG-1 800

Appendix A.2 (Reference B-1). The QA Program includes the elements of corrective action,

confirmation process, and administrative control, and is applicable to the safety-related and

nonsafety-related SSCs that are subject to an AMR. In many cases, existing programs were

found to be adequate for managing aging effects during the period of extended operation.

Generically the three elements are applicable as follows:

Corrective Action. A single corrective action process is applied regardless of the safety

classification of the structure or component. Corrective actions are implemented through the

initiation of an action request in accordance with plant procedures established pursuant to

10 CFR Part 50, Appendix B. Plant procedures require the initiation of an action request for

actual or potential problems, including unexpected plant equipment degradation, damage,

failure, malfunction or loss. Site documents that implement AMPs for license renewal will direct

that an action request be prepared in accordance with those procedures whenever

non-conforming conditions are found (i.e., the acceptance criteria are not met). Equipment

deficiencies are corrected through the initiation of a work order in accordance with plant

procedures. Although equipment deficiencies may initially be documented by a work order, the

corrective action process specifies that an action request also be initiated if required.

Confirmation Process. The focus of the confirmation process is on the follow-up actions that

must be taken to verify effective implementation of corrective actions. The measure of

effectiveness is 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 are taken. The action request process is also monitored for potentially

adverse trends. The existence of an adverse trend due to recurring or repetitive adverse

conditions will result in the initiation of an action request. The AMPs required for license

renewal would also be expected to uncover any unsatisfactory condition due to ineffective

corrective action. Since the same 10 CFR Part 50, Appendix B, corrective action and

confirmation process is applied for non-conforming safety-related and nonsafety-related SCs

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subject to AMR for license renewal, the corrective action program is consistent with

NUREG-1 800.

Administrative Control. Aging management programs are administered through various plant

implementation documents which are subject to administrative controls, including a formal

review and approval process in accordance with the requirements of 10 CFR Part 50,

Appendix B. The applicant stated the programs are, therefore, consistent with NUREG-1 800.

3.0.4.2 Staff Evaluation

The staff reviewed the applicant's AMPs described in LRA Sections A15.1 and B1.3. 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 IOMB-1)," regarding QA attributes of AMPs.

Based on the staff's evaluation, the descriptions and applicability of the plant-specific AMPs and

their associated quality attributes provided in the LRA, the staff concluded that the program

descriptions are consistent with the staff's position, the SRP-LR and the Branch Technical

Position discussed in IOMB-1.

3.0.4.3 Conclusion

On the basis of its review, as discussed above, the staff concluded that the QA attributes of the

applicant's AMPs will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as requested by

10 CFR 54.21 (a)(3). Specifically, the applicant described the quality attributes of the programs

and activities for managing the effects of aging for both safety-related and nonsafety-related

SSCs within the scope of license renewal and stated that the 10 CFR 50, Appendix B, QA

program addresses the elements of corrective action, confirmation process, and administrative

control. Therefore, the applicant's QA attributes for its AMPs are acceptable.

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

This section of the SER documents the staff's review of the applicant's AMR results for the

reactor vessel, internals, and reactor coolant system components and component groups associated with the following systems:

* Class 1 piping/components system

* reactor vessel

* reactor vessel internals

* pressurizer

* steam generators

* non-Class 1 RCS components system

3.1.1 Summary of Technical Information In the Application

In LRA Section 3.1, the applicant provided AMR results for reactor vessel, internals, and reactor

coolant system (RCS) components and component groups. In LRA Table 3.1.1, Summary of

Aging Management Evaluations in Chapter IV of NUREG-1 801 for Reactor Coolant System,"

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the applicant provided a summary comparison of its AMRs with the AMRs evaluated in the

GALL Report for the reactor vessel, intemals, and RCS components and component groups.

The applicant's AMRs incorporated applicable operating experience in the determination of

aging effects requiring management (AERM). 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 AERM. The

applicant's review of industry operating experience included a review of the GALL Report and

operating experience issues identified since the issuance of the GALL Report.

3.1.2 Staff Evaluation

The staff reviewed LRA Section 3.1 to determine 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).

Also, the staff performed an onsite audit of AMRs to confirm the applicant's claim that certain

identified AMRs are consistent with the GALL Report. The staff did not repeat its review of the

matters described in the GALL Report. However, the staff did verify that the material presented

in the LRA was applicable and that the applicant had identified the appropriate GALL AMRs.

The staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff's

audit evaluations are documented in the PBNP audit and review report and are summarized in

SER Section 3.1.2.1.

The staff also performed an onsite audit of those selected AMRs that are consistent with the

GALL Report and for which further evaluation is recommended. The staff confirmed that the

applicant's further evaluations were consistent with the acceptance criteria in NUREG-1 800

Section 3.1.2.2, "Standard Review Plan for Review of License Renewal Applications for Nuclear

Power Plants," dated July 2001. The staff's audit evaluations are documented in the PBNP

audit and review report and are summarized in SER Section 3.1.2.2.

The staff performed an onsite audit and conducted a technical review of the remaining AMRs

that were not consistent with or not addressed in the GALL Report. The audit and technical

review included evaluating whether all plausible aging effects had been identified and whether

the aging effects listed were appropriate for the combination of materials and environments

specified. The staff's audit evaluations are documented in the PBNP audit and review report

and summarized in SER Section 3.1.2.3. The staff's evaluation of its technical review is also

documented in SER Section 3.1.2.3.

Finally, the staff reviewed the AMP summary descriptions in the FSAR supplement to ensure

that they provided an adequate description of the programs credited with managing or

monitoring aging for the reactor vessel, internals, and reactor coolant system components.

Table 3.1-1 below provides a summary of the staff's evaluation of components, aging

effects/mechanisms, and AMPs listed in LRA Section 3.1 that are addressed in the GALL

Report.

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

Components In the GALL Report

Component Group Aging Effect/ AMP In GALL AMP in LRA Stafvaluation E 

Mechanism Rep0ort__ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

Reactor coolant Cumulative fatigue TLAA, evaluated TLAA This TLAA is

pressure boundary damage in accordance with evaluated in

components 10 CFR 54.21 (c) Section 4.3, Metal

(Item Number Fatigue (See 3.1.1-01) Section 3.1.2.2.1)

Steam generator Loss of material Inservice Steam Generator Consistent with

shell assembly due to pitting and inspection; water Integrity Program, GALL, which

(Item Number crevice corrosion chemistry Inservice Inspection recommends further

3.1.1-02) Program, Water evaluation. (See Chemistry Control Section 3.1.2.2.2)

Program

Pressure vessel Loss of fracture TLAA, evaluated TLAA This TLAA is

ferritic materials toughness due to in accordance with evaluated in

that have a neutron neutron irradiation Appendix G of Section 4.2, Reactor

fluence greater than embrittlement 10 CFR 50 and Vessel Neutron

1017n/cm2 (E>1 RG 1.99 Embrittlement

MeV)

(Item Number

3.1.1-04)

Reactor vessel Loss of fracture Reactor vessel Reactor Vessel Consistent with

beltline shell and toughness due to surveillance Surveillance GALL, which

welds neutron irradiation Program, recommends further

(Item Number embrittlement TLAA (see evaluation. (See

3.1.1-05) Section 4.2 and 4.4) Section 3.1.2.2.3)

Westinghouse and Loss of fracture Plant-specific Reactor Vessel Consistent with

Babcock & Wilcox toughness due to Internals Program GALL, which

baffle/former bolts neutron irradiation recommends further

(Item Number embrittlement and evaluation. (See 3.1.1-06) void swelling Section 3.1.2.2.3)

Small-bore RCS Crack initiation and Inservice Water Chemistry Consistent with

and connected growth due to SCC, inspection, water Control Program, GALL, which

systems piping intergranular SCC, chemistry, Inservice Inspection recommends further

(Item Number and thermal and one-time Program evaluation. .(See 3.1.1-07) mechanical loading inspection Section 3.1.2.2.4)

Vessel shell Crack growth due to TLAA TLAA This TLAA is

(Item Number cyclic loading evaluated in

3.1.1-10) Section 4.4,

Fracture

Mechanisms (See Section 3.1.2.2.5)

Reactor internals Changes in Plant-specific Reactor Vessel Consistent with

(Item Number dimension due to Intemals Program GALL, which

3.1.1-11) void swelling recommends further

evaluation. (See

Section 3.1.22.6)

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componentGrou AgI lng Eftic AMP Ing GALL P IR S Evaluation

Mechan sm Report __ '_i__;-____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 Reactor Coolant recommends further

penetrations), water stress System Alloy 600 evaluation. (See pressurizer spray corrosion cracking Inspection Program, Section 3.1.2.2.7)

heads, and nozzles (PWSCC) Inservice Inspection for the steam Program

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 Inservice Inspection recommends further

(Item Number evaluation. (See 3.1.1-13) Section 3.1.2.2.7)

Pressurizer Crack initiation and Inservice Not Applicable Not Applicable (See

Instrumentation growth due to inspection, water Section 3.12.2.7) penetrations and PWSCC chemistry heater sheaths and

sleeves made of

nickel alloys (Item Number

3.1.1-14) l

Westinghouse and Crack initiation and Plant-specific Water Chemistry Consistent with

B&W baffie/former growth due to SCC Control Program, GALL, which

bolts and IASCC Reactor Vessel recommends further

(Item Number Internals Program evaluation. (See 3.1.1-15) Section 3.1.22.8)

Westinghouse and Loss of preload due Plant-specific Reactor Vessel Consistent with

B&W baffle/former to stress relaxation Intemals Program GALL, which

bolts recommends further

(Item Number evaluation. (See 3.1.1-16) Section 3.1.22.9)

Steam generator Loss of section Plant-specific Water Chemistry Consistent with

(PWRs only) thickness due to Control Program, GALL, which

feedwater erosion Steam Generator recommends further

impingement plate Integrity Program evaluation. (See and support Section 3.1.2.2.10)

(Item Number

3.1.1-17) _

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Component Group Effect; A n G AP in L 'A i Staff ZAgn Evaluation.

M echanIsm' Report _ _ ; _ _ 

Alloy 600 steam Crack initiation and Steam generator Water Chemistry Consistent with

generator tubes), growth due to tubing integrity, Control Program, GALL, which

repair sleeves, and PWSCC, outside water chemistry Steam Generator recommends further

plugs diameter stress Integrity Program evaluation. (See (Item Number corrosion cracking Section 3.1.2.2.11) 3.1.1-18) (ODSCC), and/or

intergranular attack

(IGA) or loss of

material due to

wastage and pitting

corrosion, and

fretting and wear:

or deformation due'

to corrosion at tube

support plate intersections

Tube support lattice Loss of section Plant-specific Water Chemistry Consistent with

bars made of thickness due to Control Program, GALL, which

carbon steel FAC Steam Generator recommends further

(Item Number Integrity Program evaluation. (See 3.1.1-19) Section 3.1.2.2.12)

Carbon steel tube Ligament cracking Plant-specific Water Chemistry Consistent with

support plate due to corrosion Control Program, GALL, which

(Item Number Steam Generator recommends further

3.1.1-20) Integrity Program evaluation. (See

Section 3.1.2.2.13)

Reactor vessel Crack initiation and Reactor head Inservice Inspection Consistent with

closure studs and growth due to SCC closure studs Program GALL, which

stud assembly and/or IGSCC recommends no

(Item Number further evaluation.

3.1.1-22) (See

Section 3.1.2.1)

CASS pump casing Loss of fracture Inservice Inservice Inspection Consistent with

and valve body toughness due to Inspection Program GALL, which

(Item Number thermal aging recommends no

3.1.1-23) embrittlement further evaluation.

(See

Section 3.1.2.1)

CASS piping Loss of fracture Thermal aging TLAA This TLAA is

(Item Number toughness due to embrittlement of evaluated in

3.1.1-24) thermal aging CASS Section 4.4,

embrittlement Leak-Before-Break

(See _ ' Sectior3.1.2.1.1)

BWR piping and Wall thinning due to Flow-accelerated Flow-Accelerate . Consis ent with

fitings; steam flow-accelerated corrosion Corros gram, G ALL, ich

generator corrosion Steam Generator recommnds no

components Integrity Programr ' further evlaluation.

(Item Number (See

3.1.1-25) _ e Section 3.1.2.1)

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Component Group Agn Efe --AMP In GALL A In LRA StaffEvaluation

_ _ _ _ _ _ _ _ _ _ _ _ _ _ iM ec hanism 0 R epo r ti _________:_______L^0 ^000X54e

RCPB valve closure Loss of material Bolting integrity Bolting Integrity Consistent with

bolting, manway due to wear; loss of Program, Inservice GALL, which

and holding bolting, preload due to Inspection Program, recommends no

and closure bolting stress relaxation; Boric Acid Corrosion further evaluation.

in high pressure crack initiation and Program (See

and high growth due to cyclic Section 3.1.2.1)

temperature loading and/or SCC

systems

(Item Number

3.1.1-26)

CRD nozzle Crack initiation and Ni-alloy nozzles Water Chemistry Consistent with

(Item Number growth due to and penetrations, Control Program, GALL, which

3.1.1-35) PWSCC water chemistry Reactor Coolant recommends no

System Alloy 600 further evaluation.

Inspection Program (See

Section 3.1.2.1)

Reactor vessel Crack initiation and Inservice Inservice Inspection Consistent with

nozzles safe ends growth due to cyclic inspection, water Program, Water GALL, which

and CRD housing; loading, and/or chemistry Chemistry Control recommends no

RCS components SCC, and PWSCC Program further evaluation.

(except CASS and (See bolting) Section 3.1.2.1) (Item Number

3.1.1-36)

Reactor vessel Loss of fracture Thermal aging Reactor Vessel Consistent with

internals CASS toughness due to and neutron Internals Program GALL, which

components thermal aging, irradiation recommends no

(Item Number neutron irradiation embrittlement further evaluation.

3.1.1-37) embrittlement, and (See

void swelling Section 3.1.2.1)

External surfaces of Loss of material Boric acid Borc Acid Corrosion Consistent with

carbon steel due to boric acid corrosion Program GALL, which

components in RCS corrosion recommends no

pressure boundary further evaluation.

(Item Number (See

3.1.1-38) Section 3.1.2.1)

Steam generator Loss of material Inservice Not Applicable Not Applicable

secondary due to erosion inspection

manways and

handholds (carbon

steel)

(Item Number

3.1.1-39) -

Reactor internals, Loss of material Inservice Inservice Inspection Consistent with

reactor vessel due to wear inspection Program, Thimble GALL, which

closure studs, and Tube Inspection recommends no

core support pads Program, Reactor further evaluation.

(Item Number Vessel Internals (See

3.1.1-40) Program Section 3.1.2.1)

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Component Group Ain t AMP In GALL D A ff Evalaion

_______________ M e ha nis m - R eport _ _ _ _ _______- _^i _____

Pressurizer integral Crack initiation and Inservice TLAA This TLAA Is

support growth due to cyclic inspection evaluated In

(Item Number loading Section 4.3, Metal

3.1.1-41) Fatigue

Upper and lower Loss of preload due Inservice Reactor Vessel Consistent with

internals assembly to stress relaxation inspection, loose Internals Program GALL, which

(Westinghouse) part and/or recommends no

(Item Number neutron noise further evaluation.

3.1.1-42) monitoring (See

Section 3.1.2.1)

Reactor vessel Loss of fracture PWR vessel Reactor Vessel Consistent with

internals in fuel toughness due to internals, water Internals Program GALL, which

zone region (except neutron irradiation chemistry recommends no

Westinghouse and embrittlement, and further evaluation.

B&W baffle/former void swelling (See bolts) Section 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, Water GALL, which

heads, tubesheets, PWSCC and IASCC chemistry Chemistry Control recommends no

and primary nozzles Program further evaluation.

and safe ends (See

(Item Number Section 3.1.2.1)

3.1.1-44)

Vessel Internals Crack initiation and PWR vessel Reactor Vessel Consistent with

(except growth due to SCC Internals, water Internals Program, GALL, which

Westinghouse and and IASCC chemistry Water Chemistry recommends no

B&W baffle/former Control Program further evaluation.

bolts) (See

(Item Number Section 3.1.2.1)

3.1.1-45)

Reactor internals Loss of preload due Inservice Not Applicable Not Applicable

(B&W screws and to stress relaxation inspection, loose

bolts) part monitoring (Item Number

3.1.1-46) i _e; 

Reactor vessel Loss of material Reactor head Inservice Inspection Consistent with

closure studs and due to wear closure studs Program GALL, which

stud assembly iecommends no

(Item Number further evaluation.

3.1.1-47) I 1

Reactor Intemals Loss of preload due Inservice Reactor Vessel Consistent with

(Westinghouse to stress relaxation inspection, loose Internals Prograrp I DALL Qtkich

upper and lower part monitoring Pe rconmends no

internal assemblies, further evaluation.

CE bolts and tie (See

rods) Section 3.1.2.1)

(Item Number

3.1.1-48) ,

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The staff's review of the PBNP reactor vessel, internals, and RCS components and associated

components followed one of several approaches. One approach, documented in SER

Section 3.1.2.1, involves the staff's review of the AMR results for components in the reactor

vessel, internals, and RCS components that the applicant indicated are consistent with the

GALL Report and do not require further evaluation. Another approach, documented in SER

Section 3.1.2.2, involves the staff's review of the AMR results for components in the reactor

vessel, internals, and RCS components that the applicant indicated are consistent with the

GALL Report and for which further evaluation is recommended. A third approach, documented

in SER Section 3.1.2.3, involves the staff's review of the AMR results for components in the

reactor vessel, internals, and RCS components that the applicant indicated are not consistent

with the GALL Report or are not addressed in the GALL Report. The staff's review of AMPs

that are credited to manage or monitor aging effects of the RCS components is documented in

SER Section 3.0.3.

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 Apolication. In LRA Section 3.1.2.1, the applicant

identified the materials, environments, and aging effects requiring management. The applicant

identified the following programs that manage the aging effects related to the reactor vessel,

internals, and RCS components:

* Bolting Integrity Program

* Boric Acid Corrosion Program

* Closed-Cycle Cooling Water System Surveillance Program

* Flow-Accelerated Corrosion Program

* Inservice Inspection Program

* One-Time Inspection Program

* Periodic Surveillance and Preventive Maintenance Program

* Reactor Coolant System Alloy 600 Inspection Program

* Reactor Vessel Internals Program

* -Reactor Vessel Surveillance Program

* Steam Generator Integrity Program

* Systems Monitoring Program

* Thimble Tube Inspection Program

* Water Chemistry Control Program

Staff Evaluation. In LRA Tables 3.1.2-1 through 3.1.2-6, the applicant provided a summary of

AMRs for Class 1 piping/components system, reactor vessel, reactor vessel internals,

pressurizer, steam generators, and non-Class 1 RCS components and identified which AMRs it

considered to be consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed

consistency with the GALL Report, and for which the GALL Report does not recommend further

evaluation, the staff performed an audit and review to determine whether the plant-specific

components contained in these GALL Report component groups were bounded by the GALL

Report evaluation.

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The applicant provided a note for each AMR line item. The notes described how the

information in the tables aligns with the information in the GALL Report. The staff's audit of

those AMRs with Notes A through E, indicated the AMR was consistent with the GALL Report.

Note A indicated that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the AMP

identified in the GALL Report. The staff audited these line items to verify consistency with the

GALL Report and the validity of the AMR for the site-specific conditions.

Note B indicated that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

AMP identified in the GALL Report. The staff audited these line items to verify consistency with

the GALL Report. The staff verified that the identified exceptions to the GALL AMPs had been

reviewed and accepted by the staff. The staff also determined whether the AMP identified by

the applicant was consistent with the AMP identified in the GALL Report and whether the AMR

was valid for the site-specific conditions.

Note C indicated that the component for the AMR line item, although different, is consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent

with the AMP identified by the GALL Report. This note indicates that the applicant was unable

to find a listing of some system components in the GALL Report. However, the applicant

identified a different component in the GALL Report that had the same material, environment,

aging effect, and AMP as the component that was under review. The staff audited these line

items to verify consistency with the GALL Report. The staff also determined whether the AMR

line item of the different component was applicable to the component under review and whether

the AMR was valid for the site-specific conditions.

Note D indicated that the component for the AMR line item, although different, is consistent

with, the GALL Report for material, environment, and aging effect. In addition, the AMP takes

some exceptions to the AMP identified in the GALL Report., The staff audited these line items

to verify consistency with the GALL Report. The staff verified whether the AMR line item of the

different component was applicable to the component under review. The staff verified whether

the identified exceptions to the GALL AMPs had been reviewed and accepted by the staff. The

staff also determined whether the AMP identified by the applicant was consistent with the AMP

identified in the GALL Report and whether the AMR was valid for the site-specific conditions.

Note E indicated that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but a different aging management program is credited. The

staff audited these line items to verify consistency with the GALL Report. The staff also

determined whether the identified AMP would manage the aging effect consistent with the AMP

identified by the GALL Report and whether the AMR was valid for the site-specific conditions.

The staff conducted an audit and review of the information provided in the LRA, as documented

in its PBNP audit and review report. The staff did not repeat its review of the matters described

in the GALL Report. However, the staff did verify that the material presented In the LRA was

applicable and that the applicant had identified the appropriate GALL Report AMRs. The staff's

evaluation is discussed below.

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3.1.2.1.1 Loss of Fracture Toughness Due to Thermal Aging Embrittlement

The staff's review of LRA Section 3.1 identified an area in which additional information was

necessary to complete the review of the applicant's results. The applicant responded to the

staff's RAI as discussed below.

In the discussion section of LRA Table 3.1.1, Item 24, the applicant stated that it does not have

CASS RCS piping, but does have CASS primary loop elbows. The applicant stated that CASS

thermal aging is addressed using a leak-before-break (LBB) evaluation method and that

significant margin exists between detectable flaw size and flaw instability." LBB is a TLAA, as

defined in 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with

10 CFR 54.21 (c)(1). SER Section 4.4 documents the staff's review of the applicant's evaluation

of this TLAA. On that basis, the applicant concluded that an aging management program is not

required to manage the aging effects of thermal embrittlement for CASS primary loop elbows.

The staff also noted that LRA Table 3.1.2-1, "Reactor Coolant System - Class 1

Piping/Components System - Summary of Aging Management Review," lists the primary loop

elbows component type, but does not list loss of fracture toughness due to thermal aging

embrittlement as an aging effect requiring management.

On the basis of its review, the staff determined that it does not agree with the applicant's

conclusions because, for CASS piping, loss of fracture toughness due to thermal aging

embrittlement is an aging effect requiring management in accordance with the criteria contained

in 10 CFR 54.21 (a)(3). This is further supported by the GALL AMP XI.M12, Thermal Aging

Embrittlement of Cast Austenitic Stainless Steel (CASS)," which identifies acceptable aging

management options as fenhanced volumetric examination to detect and size cracks or plantor component-specific flaw tolerance evaluation. In addition, the staff found, with regard to the

applicant's use of LBB evaluation method, that LBB is not equivalent to a flaw tolerance

methodology because it assumes through wall leakage and, therefore, does not assure the

safety function of pressure boundary integrity.

RAI 3.1.1-1. In RAI 3.1.1-1, dated March 30, 2005, the staff requested the applicant to clarify

how it manages the aging effect of loss of fracture toughness due to thermal aging

embrittlement for CASS primary loop elbows. During conversations with the staff, the applicant

agreed to revise its position and perform flaw tolerance evaluations. This was identified as

confirmatory item (Cl) 3.1.1-1.

In its response to Cl 3.1.1-1, by letter dated June 9, 2005, the applicant stated that PBNP will

follow the recommendation of GALL AMP XLI.M12, and that it will use enhanced volumetric

examinations or a plant-specific or component-specific flaw tolerance evaluation to demonstrate

that CASS primary loop elbows, potentially susceptible to thermal embrittlement, have adequate

fracture toughness.

The staff found the applicant's response to RAI 3.1.1-1 acceptable as it results in actions

consistent with the GALL Report recommendations. The staff's concern is resolved and,

therefore, Cl 3.1.1-1 is closed.

The staff reviewed the LRA to confirm that the applicant had (1) provided a brief description of

the system, components, materials, and environment; (2) stated that the applicable aging

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effects had been reviewed and are evaluated in the GALL Report; and (3) identified those aging

effects for the RCS components that are subject to an AMR. On the basis of its audit and

review, the staff determined that, for AMRs not requiring further evaluation, as identified in LRA

Table 3.1.1 (Table 1), the applicant's references to the GALL Report are acceptable and no

further staff review is required.

Conclusion. The staff 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 found that, except for CASS piping, the AMR results that the applicant claimed

to be consistent with the GALL Report, are consistent with the AMRs in the GALL Report.

Therefore, the staff found that the applicant had demonstrated that the effects of aging for

these components will be adequately managed so that their intended function(s) will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

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

Evaluation is Recommended

Summary of Technical Information in the ADplication. In LRA Section 3.1.2.2, the applicant

provided further evaluation of aging management as recommended by the GALL Report for

reactor vessel, intemals, and RCS components. 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

* loss of fracture toughness due to neutron irradiation embrittlement

* crack initiation and growth due to thermal and mechanical 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 primary water stress

corrosion cracking

* crack initiation and growth due to stress corrosion cracking or irradiation-assisted stress

corrosion cracking

* loss of preload due to stress relaxation

* loss of section thickness due to erosion

* crack initiation and growth due to primary water stress corrosion cracking (PWSCC),

outside diameter stress corrosion cracking (ODSCC), or intergranular attack (IGA) or

loss of material due to wastage and pitting corrosion or loss of section thickness due to

fretting and wear or denting due to corrosion of carbon steel tube support plate

* loss of section thickness due to flow-accelerated corrosion

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* ligament cracking due to corrosion

* loss of material due to flow-accelerated corrosion

Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant

claimed consistency with the GALL Report, and for which the GALL Report recommends further

evaluation, the staff audited and reviewed the applicant's evaluation to determine whether it

adequately addressed the issues that were further evaluated. In addition, the staff reviewed the

applicant's further evaluations against the criteria in SRP-LR Section 3.1.3.2. Details of the

staff's audit are documented in the staff's PBNP audit and review report. The staff's evaluation

is discussed below.

3.1.2.2.1 Cumulative Fatigue Damage

In LRA Section 3.1.2.2.1, the applicant stated that fatigue is a TLAA, as defined in

10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21 (c)(1). SER

Section 4.3 documents the staff's review of the applicant's evaluation of this TLAA.

3.1.2.2.2 Loss of Material Due to Pitting and Crevice Corrosion

The staff reviewed LRA Section 3.1.2.2.2 against the criteria in SRP-LR Section 3.1.2.2.2.

In LRA 3.1.2.2.2, the applicant addressed loss of material of steam generator assemblies due

to pitting and crevice corrosion.

SRP-LR Section 3.1.2.2.2 states that loss of material due to pitting and crevice corrosion could

occur in the steam generator shell assembly. The existing program relied on control of water

chemistry to mitigate corrosion and inservice inspections to detect loss of material. NRC

Information Notice (IN) 90-04, "Cracking of the Upper Shell-to-Transition Cone Girth Welds in

Steam Generators," states that if general corrosion pitting of the shell exists the existing

program may not be sufficient. In that case, the GALL Report recommends augmented

inspections to manage the aging effect.

The AMPs recommended by the GALL Report for managing the aging of steam generator

assemblies due to pitting and crevice corrosion are GALL AMP Xl.M1, "ASME Section Xl

Inservice Inspection, Subsections IWB, IWC, and IWD," to detect loss of material, and

GALL AMP XI.M2, 'Water Chemistry," to mitigate corrosion. The GALL Report also

recommends a plant-specific program to conduct augmented inspections.

The applicant stated that its Water Chemistry Control Program and inservice inspections

performed in accordance with its ASME Code Section Xl, Subsections IWB, IWC, and IWD

Inservice Inspection Program, are used to manage loss of material due to pitting and crevice

corrosion on the internal surfaces of the steam generator shell. The applicant also stated that it

augments its Water Chemistry Control Program and inservice inspections with a plant-specific

aging management program, the Steam Generator Integrity Program, that provides all-inclusive

guidance for the management of steam generator assets.

The staff reviewed the applicant's Water Chemistry Control Program, ASME Code Section Xl,

Subsections IWB, IWC, and IWD Inservice Inspection Program, and Steam Generator Integrity

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Program. Its evaluation of these programs is documented in SER Sections 3.0.3.2.1;

3.0.3.2.18, and 3.0.3.2.20.

The staff found that, based on the programs identified above, the applicant has met the criteria

of SRP-LR Section 3.1.2.2.2. For those line items that apply to LRA Section 3.1.2.2.2, the staff

found that the applicant is consistent with the GALL Report and demonstrated that the effects

of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB during the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.1.2.2.3 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement

The staff reviewed LRA Section 3.1.2.2.3 against the criteria in SRP-LR Section 3.1.2.2.3.

In LRA Section 3.1.2.2.3, the applicant addressed (1) loss of fracture toughness due to neutron

irradiation embrittlement, (2) loss of fracture toughness due to irradiation embrittlement of the

reactor vessel beftline shell and weld materials, and (3) loss of fracture toughness due to

embrittlement for baffle/former bolts.

SRP-LR Section 3.1.2.2.3 states that certain aspects of neutron irradiation embrittlement are

TLAAs as defined in 10 CFR 54.3 and that TLAAs are required to be evaluated in accordance

with 10 CFR 54.2.(c)(1). Secondly, SRP-LR Section 3.1.2.2.3 states that loss of fracture

toughness due to neutron irradiation embrittlement could occur in the reactor vessel. A Reactor

Vessel 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 10 CFR 50, Appendix H, an applicant is required to submit its

proposed withdrawal schedule for approval prior to implementation. Finally, the SRP-LR

Section 3.1.2.2.3 states that loss of fracture toughness due to neutron irradiation embrittlement

and void swelling could occur in Westinghouse and B&W baffle/former bolts.

In LRA Section 3.1.2.2.3.1, the applicant states that certain aspects of neutron irradiation

embrittlement are TLAAs as defined in 10 CFR 54.3. Applicants must evaluate TLAAs in

accordance with 10 CFR 54.21 (c)(1). SER Section 4.2 documents the staff's review of the

evaluation of this TLAA.

In LRA Section 3.1.2.2.3.2, the applicant stated that loss of fracture toughness in reactor vessel

beltline shell and weld materials due to neutron irradiation embrittlement was identified as an

aging effect requiring management. The upper shell and nozzles are not subject to significant

neutron irradiation exposure because of their physical distance from the reactor core. The

limiting beltline material is the Unit 2 reactor vessel at the intermediate-to-lower shell beftline

circumferential weld.

The AMP recommended by the GALL Report for managing loss of fracture toughness due to

neutron irradiation embrittlement in the reactor vessel is GALL AMP XI.M31, 'Reactor Vessel

Surveillance," which complies with the requirements of 10 CFR 50, Appendices G and H, and

10 CFR 50.61.

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The applicant stated that its Reactor Vessel Surveillance Program, in conjunction with TLAA

analyses, effectively manages loss of fracture toughness in the beltline materials. The Reactor

Vessel Surveillance Program provides adequate material property and neutron dosimetry data

to predict fracture toughness in beltline materials at the end of the period of extended operation.

In addition, equivalent margins analyses have been performed in accordance with 10 CFR 50

Appendix G methods. The staff's review of this program is documented in SER

Section 3.0.3.2.17.

In LRA Section 3.1.2.2.3.3, the applicant stated that loss of fracture toughness due to neutron

irradiation embrittlement was also identified as an aging effect requiring management for the

baffle/former bolts. The Reactor Vessel Intemals Program will be used to manage this aging

effect.

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 10 CFR 50, Appendix H, an

applicant is required to submit its proposed withdrawal schedule for approval prior to

implementation. Therefore, further staff evaluation is required for license renewal.

NUREG-1 801 recommends further evaluation of the reactor vessel materials surveillance

program for the period of extended operation. The staff verified that the applicant proposed an

adequate reactor vessel materials surveillance program for the period of extended operation.

The staff's evaluation of this program is discussed in SER Section 3.0.3.2.17.

The limiting beltline material at PBNP is the intermediate-to-lower shell beltline circumferential

weld of the Unit 2 reactor vessel. The applicant's Reactor Vessel Surveillance Program, in

conjunction with TLAA analyses, effectively manages loss of fracture toughness in the beltline

materials. The Reactor Vessel Surveillance Program provides adequate material property and

neutron dosimetry data to predict fracture toughness in beltline materials at the end of the

period of extended operation. The analyses, as discussed in SER Section 4.2, for upper shelf

energy and pressurized thermal shock provide assurance that beltline material toughness

values in the reactor vessel will remain at acceptable levels through the period of extended

operation. The staff reviewed the applicant's Reactor Vessel Surveillance Program. Its

evaluation is documented in SER Section 3.0.3.2.17.

During the 1998 refueling outage, the entire population of 728 Type 347 stainless steel

baffle/former bolts was selected for inspection at Unit 2. A total of 175 bolts were replaced with

Type 316 stainless steel bolts during the outage. The Westinghouse Owners Group developed

an NRC-approved methodology, WCAP-1 5029-P-A, to determine number and distribution of

intact and functional baffle bolts required to ensure safe plant operation. Plant-specific

applications of the Westinghouse methodology were performed in support of the inspection and

replacement programs at Unit 2.

GALL Section IV.132.4-f recommends plant-specific aging management. The applicant stated

that, because of its change to Type 316 stainless steel baffle/former bolts in 1998, no further

inspections of Unit 2 bolts are planned. However, in its letter dated July 12, 2004, the applicant

stated that it will continue to monitor and participate in industry initiatives (MRP activities) with

regard to reactor vessel internals to support aging management for the baffle/former bolts.

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The staff concluded that the applicant's LRA commitment is acceptable because: (1) it will

apply industry guidelines that will ensure that inspections capable of detecting degradation prior

to a loss of component intended function will be used, (2) it will allow the staff to review the

applicant's inspection plans for the reactor vessel internals as based on industry

recommendations, and (3) It will provide the staff an opportunity to resolve with the applicant

any issues that may arise with the inspection plan.

The staff found that, based on the programs identified above, the applicant has met the criteria

of SRP-LR Section 3.1.2.2.3. For those line items that apply to LRA Section 3.1.2.2.3, the staff

found that the applicant is consistent with the GALL Report and has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB during the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.1.2.2.4 Crack Initiation and Growth Due to Thermal and Mechanical Loading or Stress

Corrosion Cracking

The staff reviewed LRA Section 3.1.2.2.4 against the criteria in SRP-LR Section 3.1.2.2.4.

In LRA Section 3.1.2.2.4, the applicant stated that crack initiation and growth due to SCC was

identified as an aging effect requiring management in small-bore (less than 4-inch NPS) RCS

piping and branch lines. Aging management of service-induced cracking will be accomplished

by a combination of the Water Chemistry Control Program and the Inservice Inspection

Program. PBNP implemented a Risk-Informed Inservice Inspection Program and, as part of

this transition, some small-bore RCS locations were identified for inspection. These inspections

of small-bore RCS piping will meet the intent of the one-time inspections referenced in

NUREG-1 800.

SRP-LR Section 3.1.2.2.4 states that the GALL Report recommends that a plant-specific

destructive examination or a nondestructive examination (NDE) that permits inspection of the

inside surfaces of the piping be conducted 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 service-induced weld cracking is not occurring in small-bore piping.

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's 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 4-inch NPS, does not receive

volumetric inspection.

The AMPs recommended by the GALL Report are GALL AMP Xl.M1, "ASME Section Xl

Inservice Inspection, Subsections IWB, IWC, and IWD," to detect loss of material, and GALL

AMP XI.M2, "Water Chemistry," to mitigate SCC.

The applicant stated that Its Water Chemistry Control Program and inservice inspections

performed in accordance with its ASME Code Section XI, Subsections IWB, IWC, and IWD,

Inservice Inspection Program, are used to manage crack initiation and growth due to thermal

and mechanical loading or stress corrosion cracking. The staff reviewed the applicant's Water

Chemistry Control Program and ASME Code Section Xl, Subsections IWB, IWC, and IWD,

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Inservice Inspection Program. Its evaluation is documented in SER Sections 3.0.3.2.20 and

3.0.3.2.1, respectively.

The staff's review of LRA Section 3.1.2.2.4 identified areas in which additional information was

necessary to complete the review of the applicant's results. The applicant responded to the

staff's RAls as discussed below.

The applicant stated that Westinghouse had performed a generic aging management

evaluation of Class 1 piping and associated pressure boundary components for the

Westinghouse Owners Group. The applicant stated that Westinghouse Generic Topical Report

(GTR), "Aging Management Review for Class 1 Piping and Associated Pressure Boundary

Components," WCAP-1 4575-A, was approved by the staff.

RAI 3.1.2-1. LRA Section 3.1 states that WCAP-14575-A and 14574-A were approved by the

staff. In RAI 3.1.2-1, dated November 17, 2004, the staff requested the applicant to indicate

the dates of the approval letters/safety evaluation for the subject WCAPs.

In its response, dated January 25, 2005, the applicant stated that the approval letters for

WCAP-1 4575-A and 14574-A were dated November 8, 2000, and October 26, 2000,

respectively. The staff's review found that the subject GTRs were approved by the staff on the

dates specified. Therefore, the staff concluded that the applicant appropriately used generic

topical reports acceptable to the staff in its aging management review for the RCS and

pressurizer. The staff's concern described in RAI 3.1.2-1 is resolved.

The applicant also stated that the RI-ISI Program inspections of piping welds less than 4-inch

NPS will include volumetric examinations, with the exception of socket welded connections.

Because no meaningful volumetric inspection technique exists for the geometry presented by

socket welds, a surface examination will be performed. The staff notes that plant experience at

Susquehanna Steam Electric Station (Susquehanna), Units 1 and 2, involved the successful

ultrasonic examination (UT) of small-bore piping socket welds to detect cracking. The licensee

had worked with the Electric Power Research Institute to develop a go/no-go method to detect

cracking in the socket welds for the 1-inch vent lines for the reactor recirculation piping. The

UT method was successful in identifying cracking at Susquehanna, and a number of socket

welds were removed from service due to potential short-term cracking from fatigue.

RAI 3.1.2-2. LRA Section 3.1 states that meaningful volumetric inspection techniques do not

exist for socket welds in the Class 1 piping. In RAI 3.1.2-2, dated November 17, 2004, the staff

requested the applicant to consider the Susquehanna operating experience and discuss the

applicability of UT of socket-welded joints in 1-inch piping at PBNP. If the applicant determined

that UT is not suitable, the staff requested the applicant's basis and justification for the

determination.

In its response, dated January 25, 2005, the applicant stated that the Susquehanna UT

technique shows promise in situations dealing with frequent fatigue-related socket-welded joint

failures. The technique is not an ASME Code-acceptable inspection, as it does not meet the

inspection requirements for a volumetric examination, and has not been thoroughly investigated

nor accepted by the industry. The applicant stated that, because the UT technique cannot

characterize indications, its application can result in rejecting socket welds that may otherwise

be acceptable, as was the case at Susquehanna.

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i

I
Additionally, the applicant provided a more in-depth account of the socket-weld failures that

have occurred at PBNP. It stated that three 2-inch socket-weld cracks were identified in the

auxiliary feedwater pump recirculation lines downstream of the pressure reducing orifices

following a system modification that allowed an increase in the pump recirculation flow rates.

Another socket-weld failure occurred in a 3/4-inch socket weld in a drain line connection in the

safety-injection/containment spray system full-flow test line following a system modification.

Two 3/8-inch socket weld cracks were identified on the steam generator channel head drain line

isolation valve following replacement of the Unit 1 steam generators. The applicant stated that

the failures resulted in minor leakage identified by plant personnel during walkdowns and

post-modification testing. The staff concluded from the socket-weld failure history provided by

the applicant that the statement "no significant socket weld failures" refers to short-term failures

resulting from modifications rather than failures caused by aging effects requiring management.

The applicant further stated that the staff approved the Risk-informed Inservice Inspection

(RI-ISI) methodology to monitor the Class 1 piping systems that collectively use the socket

welds, and that to deploy the UT methodology of testing would result in unnecessary radiation

exposure to plant personnel. The applicant cited the following passage from the staff's safety

evaluation of its RI-ISI Program:

The objective of inservice inspection required by the ASME Code, Section Xl, is to

identify conditions that are precursors to leaks and ruptures in the pressure boundary

that may impact plant safety. The RI-ISI program is judged to meet this objective.

The staff agreed that the socket-weld failures resulted from failure mechanisms other than

those caused by aging and that sufficient monitoring is in place such that no significant safety

condition exists. The staff, therefore, concluded that using the Susquehanna UT methodology

would result in unnecessary radiation exposure and that the response to RAI 3.1.2-2 is

acceptable. The staff's concern described in RAI 3.1.2-2 is resolved.

The applicant indicated that the staff had specified Renewal Applicant Action Items that were

required as part of its acceptance of WCAP-1 4575-A, and that the items are discussed in LRA

Table 3.1.0-1. For the Class 1 piping and associated pressure boundary components, the LRA

indicated that there were 10 staff-identified action items, and similarly, 10 items for the

pressurizer. The applicant's responses to the action items were acceptable with two

exceptions. The applicant's response to action item (6) in LRA Table 3.1.0-1 reflected its earlier

position regarding UT on small-bore piping socket welds. Based on its response to RAI 3.1.2-2,

the staff considered this item resolved.

Under Renewal Applicant Action Item (4) of LRA Table 3.1.0-3, the staff discusses the

development of SCC in the bolting materials. The staff stated that to take credit for the criteria

in EPRI Report NP-5769, the applicant must state that the acceptable yield strengths for the

quenched and tempered low-alloy steel bolting materials (SA-1 93, Grade B7) are in the range

of 105 to150 ksi. In its plant-specific response, the applicant stated that because the maximum

yield strength is not specified for this bolting material, absolute assurance that the yield strength

of the bolting would not exceed 150 ksi cannot be provided. The applicant stated that control of

contaminants and bolt torquing will ensure that SCC will not occur, and that a review of

inservice inspection and general documentation databases supports the conclusion that no

pressure boundary bolting degradation due to SCC is occurring. Staff experience with this

phenomenon is that design changes to the bolting configuration and surface coatings aid in the

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prevention of SCC. Also, the extent and type of nondestructive examination performed on the

bolting is important in determining if cracking is active.

RAI 3.1.2-4. Under the plant-specific response in LRA Table 3.1.0-3 for Renewal Applicant

Action Item (4), the applicant stated that absolute assurance could not be provided that the

yield strength of the SA-1 93, Grade B7 bolting, is under 150 ksi. Furthermore, it is stated that

because the inservice inspection database results show that no cracking is occurring, SCC is

not considered an aging effect requiring management for the pressurizer bolting. In

RAI 3.1.2-4, dated November 17, 2004, the staff requested the applicant to explain in detail the

type, extent, and frequency of nondestructive examinations on this pressure-retaining bolting

performed under the Inservice Inspection Program.

In its response, dated January 25, 2005, the applicant stated that the pressurizer bolting is

inspected in accordance with the requirements of item Table IWB-2500-1, category B-G-2, item

B7.20. The ASME Code requires a visual examination (VT-1) at each interval.

The applicant's inspection frequency is once per interval, consistent with the inspection

frequency listed in ASME Code Section Xl. The staff concluded that sufficient inspections exist

for SA-1 93, Grade B7 pressurizer bolting such that the effects of aging are managed, and

considers the response to RAI 3.1.2-4 acceptable. The staff's concern described in RAI 3.1.2-4

is resolved.

The staff found that, based on the programs identified above, the applicant has met the criteria

of SRP-LR Section 3.1.2.2.4. For those line items that apply to LRA Section 3.1.2.2.4, the staff

found that the applicant is consistent with the GALL Report and has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB during the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.1.2.2.5 Crack Growth Due to Cyclic Loading

In LRA Section 3.1.2.2.5, the applicant stated that underclad cracking in carbon/low-alloy steel

that was clad with austenitic stainless steel using weld-overlay processes was identified as an

aging effect requiring management and is considered a TLAA as defined in 10 CFR 54.3.

Applicants must evaluate TLAAs in accordance with 10 CFR 54.21 (c)(2). SER Section 4.4

documents the staff's review of the applicant's evaluation of this TLAA.

3.1.2.2.6 Changes in Dimension Due to Void Swelling

The staff reviewed LRA Section 3.1.2.2.6 against the criteria in SRP-LR Section 3.1.2.2.6.

In LRA Section 3.1.2.2.6, the applicant addressed changes in dimension due to void swelling

that could occur in reactor Internals components.

SRP-LR Section 3.1.2.2.6 states that the GALL Report recommends that changes in dimension

due to void swelling in reactor internals components be evaluated to ensure that this aging

effect is adequately managed. The GALL Report recommends that a plant-specific AMP be

evaluated to manage the effects of changes in dimension due to void swelling and the loss of

fracture toughness associated with swelling.

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The applicant stated that the void swelling of reactor vessel internals is managed by its Reactor

Vessel Internals Program. Further, the applicant stated that transmission electron microscopy

studies of thin foils prepared from an intact baffle/former bolt and locking device removed from

the Unit 2 reactor vessel internals in 1999 indicated that voids were present in the threaded end

of the bolt but not in the head or the 304 stainless steel locking device. The maximum void

volume observed in the 347 stainless steel bolt material, 0.03 percent, is small and preliminary

extrapolation to the end of extended life using a simple square law suggests that void swelling

should not be a concern. The industry is currently developing technical guidance to address

the issue of void swelling. The applicant committed to further understanding of this aging effect

through industry programs that may provide additional bases for supplemental examinations or

component-specific evaluations.

The staff evaluated the applicant's Reactor Vessel Intemals Program. Its evaluation is

documented in SER Section 3.0.3.2.15. The staff found the applicant's approach for managing

changes in dimension due to void swelling acceptable because the approach will be based on

the guidelines developed by the ongoing industry activities related to void swelling. The

applicant committed to implement the appropriate recommendations resulting from the industry

efforts. The applicant also committed, in its letter dated July 12, 2004, that the revised program

description, including a comparison with the 10 program elements of the NUREG-1801

program, will be submitted to the NRC for approval two years prior to the period of extended

operation.

The staff found that, based on the programs identified above, the applicant has met the criteria

of SRP-LR Section 3.1.2.2.6. For those line items that apply to LRA Section 3.1.2.2.6, the staff

found that the applicant is consistent with the GALL Report and has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB during the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.1.2.2.7 Crack Initiation and Growth Due to Stress Corrosion Cracking or Primary Water

Stress Corrosion Cracking

The staff reviewed LRA Section 3.1.2.2.7 against the criteria in SRP-LR Section 3.1.2.2.7.

In LRA Section 3.1.2.2.7.1, the applicant stated that the core support pads and the bottom head

instrument penetrations are fabricated from Alloy 600. Crack initiation and growth of the bottom

head penetrations due to SCC/PWSCC Is managed by a combination of the Water Chemistry

Control Program and the Reactor Coolant System Alloy 600 Inspection Program. The Reactor

Coolant System Alloy 600 Inspection Program is a plant-specific program, which includes

participation in industry initiatives related to management of Alloy 600 penetration cracking

issues. The core support pads are susceptible to crack initiation and growth due to

SCC/PWSCC and are managed by a combination of the Water Chemistry Control Program and

the Inservice Inspection Program.

In LRA Section 3.1.2.2.7.2, the applicant stated that the primary loop elbows are CASS material

and are subject to aging effects. The Water Chemistry Control Program monitors and controls

primary water chemistry in accordance with the guidelines of EPRI TR-1 05714 and, therefore,

effectively manages crack initiation and growth due to SCC. Additionally, in LRA

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____ __ __ - ------

Section 3.1.2.2.7.3, the applicant stated that there are no components fabricated from Alloy 600

in the pressurizers.

The staff reviewed the applicant's Water Chemistry Control Program, the Reactor Coolant

System Alloy 600 Inspection Program, and the ASME Code Section Xl, Subsections IWB, IWC,

and IWD Inservice Inspection Program. Its evaluation is documented in SER

Sections 3.0.3.2.20, 3.0.3.2.15, and 3.0.3.2.1, respectively. The staff found that these

programs will manage the aging effects of crack initiation and growth due to SCC/PWSCC in

the RCS components.

In LRA Section 3.1.2.2.7.1, the applicant stated that the reactor vessel leak detection line is

outside the primary pressure boundary and, is therefore, not within the scope of license

renewal. The pressurizer spray head performs no license renewal intended function at PBNP,

including Appendix R considerations (the pressurizer cooldown rate required for an Appendix R

scenario is achievable without a functioning spray head). The steam generator instrument

nozzles are low-alloy steel, not Alloy 600 or stainless steel and, therefore, are not included in

this component group.

The staff reviewed the applicant's claims that these components are not within the scope of the

license renewal scoping and screening. This review is documented in SER Sections 2.3.1.2.2

and 2.3.1.4.2, and response to RAI 2.3.1.2-1. On the basis of its review, the staff determined

that these components are not safety-related and, therefore, are not within the scope of license

renewal.

The applicant identified cracking due to SCC and flaw growth as applicable aging effects for

Alloy 600 components that are exposed to primary water with a temperature greater than

480 OF. NUREG-1 801 also identified crack initiation and growth and primary water stress

corrosion cracking as an aging effect/mechanism.

The applicant credited its Water Chemistry Control Program to manage this aging effect. In the

Water Chemistry Control Program, the applicant credits the EPRI TR-1 0574, Revision 4, and

TR-102134, Revision 5. This program controls concentrations of known chemical species such

as halogens, sulfates, and dissolved oxygen below the levels known to cause degradation. The

program provides assurance that an acceptable level of contaminants and oxygen is

maintained in the systems and components covered by the program and, therefore, minimizes

the occurrence of aging effects.

In addition, the applicant credited either the Reactor Coolant System Alloy 600 Inspection

Program or the ASME Code Section Xi, Subsections IWB, IWC, and IWD Inservice Inspection

Program inspections to identify and correct degradation in Class 1, 2, and 3 piping,

components, and their integral attachments. These programs include periodic visual, surface

and/or volumetric examinations and leakage tests of all Class 1, 2, and 3 pressure-retaining

components, and their integral attachments, including welds, pump casings, valve bodies, and

pressure-retaining bolting. The GALL Report recommends the applicant to provide a

plant-specific AMP or participate in industry programs to determine appropriate aging

management. The Reactor Coolant System Alloy 600 Inspection Program is a plant-specific

program for PBNP that includes participation in industry initiatives related to management of

Alloy 600.

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In LRA Section 3.1.2.2.7.2, the applicant stated the primary loop'elbows are CASS material and

are subject to these aging effects. The applicant proposed to manage these aging effects

using the Water Chemistry Control Program and ASME Code Section Xl, Subsections IWB,

IWC, and IWD Inservice Inspection Program.

The staff reviewed the applicant's Water Chemistry Control Program and the ASME Code

Section Xi, Subsections IWB, IWC, and IWD Inservice Inspection Program. Its evaluation is

documented in SER Sections 3.0.3.2.20 and 3.0.3.2.1, respectively. On the basis of its review,

the staff found that these programs will manage the aging effects of crack initiation and growth

due to SCC/PWSCC in the RCS components.

In LRA Section 3.1.2.2.7.3, the applicant stated that there are no components fabricated from

Alloy 600 in the pressurizer and, therefore, this line item was not used. Instrument

penetrations, heater well tubes, and adapters are stainless steel. During the audit, the staff

held discussions with the applicant's technical staff. The applicant confirmed that there are no

Alloy 600 components in the pressurizers. On this basis, the staff found this explanation is

acceptable.

The staff's review of LRA Section 3.1.2.2.7 identified an area in which additional information

was necessary to complete the review of the applicant's results. The applicant responded to

the staff's RAI as discussed below.

The staff reviewed Renewal Applicant Action Item (10) of LRA Table 3.1.0-1. The staff's safety

evaluation for WCAP-1 4575-A notes that, if a repair or replacement was performed on CASS, a

new LBB analysis would be required to determine the effect of thermal aging on CASS

components. In its response to Renewal Applicant Action Item (10), the applicant indicated that

the LBB analyses were revised utilizing a methodology consistent with the original analyses.

Furthermore, the applicant indicated that plant process control procedures (design control,

repair/replacement, and welding) will be revised to ensure that repair or replacement of Class 1

piping components (welded connections or CASS would require a new LBB analysis based on

the replacement process and/or material properties. Because the applicant indicated that the

revised LBB analyses had been completed, the staff questioned whether the revision to the

plant process control procedures is still required.

RAI 3.1.2-3. PBNP's plant-specific response, LRA Table 3.1.0-1 Item (10), indicated that plant

process control procedures (i.e., design control, repair/replacement, and welding) will be

revised to ensure that repair or replacement of Class 1 piping components welded connections

or CASS would require a new LBB analysis based on replacement process and/or material

properties. Prior to that statement, it was indicated that the subject LBB analyses addressinrg

steam generator replacement, power uprate, and a 60-year operating period had been revised.

Because these LBB analyses revisions typically address the effects of thermal aging on CASS

components, in RAI 3.1.2-3, dated November 17, 2004, the staff requested the applicant to

explain in detail why the revisions to the procedures were necessary. The staff also requested

the applicant to advise H the revised LBB analyses addressed the effects of thermal aging on

CASS components. If the revisions to the plant control procedures were required per plant

administrative program controls, the applicant was requested to provide a commitment in the

LRA stating that the subject revisions would be completed prior to the period of extended

operation.

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In its response, dated January 25, 2005, the applicant stated that the revised LBB analyses

account for the effects of thermal aging of CASS materials. The applicant also stated that

Applicant Action Item (10) of the NRC Safety Evaluation for WCAP-1 4575-A, uAging

Management Evaluation for Class 1 Piping and Associated Pressure Boundary Components,"

requires that the provisions for management of thermal aging (LBB analyses) include

addressing the impacts of repairs/replacements of CASS components on the LBB analyses,

making the proposed revisions to PBNP procedures/processes necessary. The applicant also

indicated that LRA Section B2.1.1 identifies the necessary program enhancements to address

maintenance of the LBB analyses.

The staff concluded that the applicant is complying with the requirements to maintain the LBB

analyses, that a documented commitment was listed, and that the response to RAI 3.1.2-3 is

acceptable. The staff's concerns described in RAI 3.1.2-3 are resolved.

The staff found that, based on the programs identified above, the applicant has met the criteria

of SRP-LR Section 3.1.2.2.7. For those line items that apply to LRA Section 3.1.2.2.7, the staff

found that the applicant is consistent with the GALL Report and has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB during the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.1.2.2.8 Crack Initiation and Growth Due to Stress Corrosion Cracking or Irradiation-assisted

Stress Corrosion Cracking

The staff reviewed LRA Section 3.1.2.2.8 against the criteria in SRP-LR Section 3.1.2.2.8.

In LRA Section 3.1.2.2.8, the applicant addressed crack initiation and growth due to SCC or

irradiation-assisted stress corrosion cracking (IASCC) that could occur in baffle/former bolts in

the reactor.

SRP-LR Section 3.1.2.2.8 states that crack initiation and growth due to SCC or IASCC could

occur in baffle/former bolts in the reactors. The GALL Report recommends further evaluation to

ensure that these aging effects are adequately managed.

In LRA Section 3.1.2.2.8, the applicant stated that crack initiation and growth due to SCC and

IASCC were identified as aging effects requiring management for the baffle/former bolts. A

combination of the Water Chemistry Control Program and the Reactor Vessel Internals

Program is used to manage this aging effect.

In LRA Table 3.1.2-3, the applicant identified that cracking is an applicable aging effect for the

baffle/barrel former bolts that are exposed to the borated water environment and categorized

the AMR for these components as a need for plant-specific aging management. GALL line Item

IV.B2.4-c for baffle/former bolts also recommends a plant-specific program with appropriate

augmented visual inspections be used to manage cracking in this component. Historically,

VT-3 visual examinations have not identified baffle/former bolt cracking because cracking

occurs at the juncture of the bolt head and shank, which is not accessible for visual inspection.

Ultrasonic testing (UT) examinations of the baffle/former bolts have identified cracking in

several plants.

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The applicant credits a combination of the Water Chemistry Control Program and the Reactor

Vessel Internals Program to manage this aging effect. LRA Section B2.1.17 discusses the

applicant's Reactor Vessel Internals Program. During the 1998 refueling outage, the entire

population of 728 Type 347 stainless steel baffle/former bolts was selected for inspection by UT

at Unit 2. A total of 175 bolts were replaced with Type 316 stainless steel bolts during the

outage. These bolts were part of a pre-qualified minimum bolt pattern for PBNP.

The applicant used the Westinghouse Methodology (WCAP-1 5029-P-A) in support of the

inspection and replacement programs at Unit 2. However, the applicant stated in LRA

Section B2.1.17 that it will "Actively participate in industry groups studying reactor vessel

internals materials degradation issues, such as the EPRI MRP RI-ITG and Westinghouse

Owner's Group. Implement NRC approved industry activities resulting from the MRP, as

appropriate, to manage any applicable aging effects identified through the EPRI MRP effort." In

addition, the applicant stated in its letter, dated July 12, 2004, that it will submit an inspection

plan for the Reactor Vessel Internals Program for NRC review and approval at least 24 months

prior to entering the period of extended operation.

The staff concluded that the applicant's LRA commitment is acceptable because: (1) it will

apply industry guidelines that will ensure that inspections capable of detecting degradation prior

to a loss of component intended function will be used, (2) it will allow the staff to review the

applicant's inspection plans for the Reactor Vessel Internals Program as based on the industry

recommendations, and (3) it will provide the staff an opportunity to resolve with the applicant

any issues that may arise with the inspection plan.

The staff found that, based on the program identified above, the applicant has met the criteria

of SRP-LR Section 3.1.2.2.8. For those line items that apply to LRA Section 3.1.2.2.8, the staff

found that the applicant is consistent with the GALL Report and has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB during the period of extended operation, as required by

10 CFR 54.21(a)(3).

3.1.2.2.9 Loss of Preload Due to Stress Relaxation

The staff reviewed LRA Section 3.1.2.2.9 against the criteria in SRP-LR Section 3.1.2.2.9.

In LRA Section 3.1.2.2.9, the applicant addressed loss of preload due to stress relaxation that

could occur in baffle/former bolts in the reactor.

SRP-LR Section 3.1.2.2.9 states that loss of preload due to stress relaxation could occur in

baffle/former bolts In the reactor. The GALL Report recommends a plant-specific AMP to

ensure that these aging effects are adequately managed.

In LRA Section 3.1.2.2.9, the applicant credits the Reactor Vessel Internals Program for

managing loss of preload. Loss of preload due to stress relaxation was identified as an aging

effect requiring management of baffle/former bolts. GALL recommended that visual VT-3

inspection needs to be augmented to detect relevant conditions of stress relaxation because

only the heads of the baffle/former bolts are visible, and a plant-specific aging management

program is required. The applicant stated that aging will be managed by the Reactor Vessel

Internals Program. The applicant will continue to participate in industry initiatives regarding

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managing aging effects applicable to reactor vessel internals as stated in its letter dated

July 12, 2004.

The staff concluded that the applicant's LRA commitment is acceptable because: (1) it will

apply industry guidelines that will ensure that inspections capable of detecting degradation prior

to a loss of component intended function will be used, (2) it will allow the staff to review the

applicant's inspection plans for the reactor vessel internals as based on the industry

recommendations, and (3) it will provide the staff an opportunity to resolve with the applicant

any issues that may arise with the inspection plan.

The staff found that, based on the program identified above, the applicant has met the criteria

of SRP-LR Section 3.1.2.2.9. For those line items that apply to LRA Section 3.1.2.2.9, the staff

found that the applicant is consistent with the GALL Report and has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB during the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.1.2.2.10 Loss of Section Thickness Due to Erosion

The staff reviewed LRA Section 3.1.2.2.10 against the criteria in SRP-LR Section -3.1.2.2.10.

In LRA Section 3.1.2.2.10, the applicant addressed loss of section thickness due to erosion that

could occur in steam generator feedwater impingement plates and supports.

SRP-LR Section 3.1.2.2.10 states that loss of section thickness due to erosion could occur in

steam generator feedwater impingement plates and supports. The GALL Report recommends

further evaluation of a plant-specific AMP to ensure that this aging effect is adequately

managed.

The applicant stated that this component group is not applicable for the steam generator

design. The feedwater delivery to the steam generators at PBNP is through feed rings to

J-tubes. The feed rings and J-tubes perform no license renewal intended function.

The staff's review of LRA Section 3.1.2.2.10 identified an area in which additional information

was necessary to complete the review of the applicant's program elements. The applicant

responded to the staff's RAI as discussed below.

RAI 3.1.1-2. In RAI 3.1.1-2, dated March 30, 2005, the staff requested the applicant to justify

why the SG feedrings and associated J-tubes would not be scoped in the license renewal.

During conversations with the staff, the applicant agreed to scope and manage the aging

effects associated with the SG feedrings and J-tubes. This was identified a confirmatory item

(Cl) 3.1.1-2.

In its response to Cl 3.1.1-2, by letter dated June 9, 2005, the applicant stated that J-nozzles,

feedrings, and feedring supports have been added to the scope of license renewal to address a

potential issue, where failures of nonsafety-related components could affect the safety-related

SG tubing. Therefore, the aging management programs for these components need to ensure

that the feedring components stay in place and not fall on the SG tubes. The applicant will

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age-manage the SG feedrings, J-nozzles, and feedring supports using the Water Chemistry

Control Program and the Steam Generator Integrity Program. The Steam Generator Integrity

Program provides for various inspections of the secondary side of the SGs, which will provide

verification that aging effects are not progressing, thereby ensuring that the feedring and

J-nozzles remain in place.

The staff found the applicant's response to RAI 3.1.1-2 acceptable because it brought the

J-nozzles, feedrings, and feedring supports into the scope of license renewal and appropriately

manages the aging effects to assure that the component will not prevent safety-related

components from performing its associated safety functions. The staff's concern is resolved

and, therefore, Cl 3.1.1-2 is closed.

The staff found that, based on the programs identified above, the applicant has met the criteria

of SRP-LR Section 3.1.2.2.10. For those line items that apply to LRA Section 3.1.2.2.10, the

staff found that the applicant Is consistent with the GALL Report and has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB during the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.1.2.2.11 Crack Initiation and Growth Due to PWSCC, ODSCC, or IGA or Loss of Material

Due to Wastage and Pitting Corrosion or Loss of Section Thickness Due to Fretting and Wear

or Denting Due to Corrosion of Carbon Steel Tube Support Plate

The staff reviewed LRA Section 3.1.2.2.11 against the criteria in SRP-LR Section 3.1.2.2.11.

In LRA Section 3.1.2.2.11, the applicant addressed crack initiation and growth due to PWSCC,

SCC, IGA, or loss of material due to wastage and pitting corrosion that could occur in

nickel-based alloy components of the steam generator tubes and plugs.

SRP-LR Section 3.1.2.11 states that crack initiation and growth due to PWSCC, ODSCC, IGA,

or loss of material due to wastage and pitting corrosion or deformation due to corrosion could

occur in Alloy 600 components of the steam generator tubes, repair sleeves, and plugs. All

PWR licensees have committed voluntarily to a SG degradation management program

described in NEI 97-06; these guidelines are currently under staff review. The GALL Report recommends that an AMP, based on the recommendations of staff-approved NEI 97-06

guidelines or alternative regulatory basis for SG degradation management, be developed to

ensure that this aging effect is adequately managed.

In LRA Section 3.1.2.2.11, the applicant stated that cracking due to PWSCC, IGAIlGSCC, and

loss of material due to pitting and wear had been identified as aging effects requiring

management for the steam generator tubes and plugs. The applicant stated that these aging

effects will be managed by the Water Chemistry Control Program and the Steam Generator

Integrity Program.

Unit 1 has two replacement SGs, which were installed in 1984. The Unit 1 SGs use thermally

treated Alloy 600 tubes. Unit 2 has two replacement SGs which were installed in 1996. The

Unit 2 SGs use thermally treated Alloy 690 tubes. Alloy 690 plugs are used to repair tubes.

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The staff's review of aging effects that are applicable to the steam generators includes the

review of aging management during the period of extended operation for the following internal

and external aging effects: (1) cracking and (2) loss of material.

Steam generator (SG) aging management incorporates provisions of NEI 97-06, "Steam

Generator Program Guidelines." The industry guidelines include an assessment of degradation

mechanisms considering the operating experience from similar SGs to identify all potential

degradation mechanisms that should be considered during inspection. For each identified

mechanism, NEI 97-06 defines the inspection techniques, measurement uncertainty and

sampling strategies. The industry guidelines provide criteria for the qualification of personnel,

specific techniques and the associated acquisition and analysis of data, including procedures,

probe selection, analyses protocols and reporting data. Performance criteria which pertain to

structural integrity, accident induced leakage, and operational leakage are specified.

The Steam Generator Integrity Program includes guidance on assessment of degradation

mechanisms, inspection, tube integrity, maintenance, repair, leakage monitoring as well as

control of water chemistry. Water chemistry control of both primary and secondary water is an

integral component outlined in NEI 97-06 and is a method to limit age-related degradation.

NEI 97-06 identifies a provision for monitoring secondary-side SG components to ensure that

failure of a secondary-side component will not impact the ability of the SG to fulfill its

safety-related function.

The staff found that, based on the programs identified above, the applicant has met the criteria

of SRP-LR Section 3.1.2.2.11. For those line items that apply to LRA Section 3.1.2.2.11, the

staff found that the applicant is consistent with the GALL Report and has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB during the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.1.2.2.12 Loss of Section Thickness Due to Flow-accelerated Corrosion

The staff reviewed LRA Section 3.1.2.2.12 against the criteria in SRP-LR Section 3.1.2.2.12.

In the LRA Section 3.1.2.2.12, the applicant addressed loss of section thickness due to

flow-accelerated corrosion (FAC) that could occur in tube support lattice bars made of stainless

steel or Alloy 600.

SRP-LR Section 3.1.2.2.12 states that loss of section thickness due to FAC could occur in tube

support lattice bars made of carbon steel. The GALL Report recommends that a plant-specific

AMP be evaluated and, on the basis of the guidelines of GL 97-06, an inspection program for

steam generator internals be developed to ensure that this aging effect is adequately managed.

The staff's review of LRA Section 3.1.2.2.12 identified an area in which additional information

was necessary to complete the review of the applicant's results. The applicant responded to

the staff's RAI as discussed below.

The applicant identified that the Unit 1 SG anti-vibration bars are fabricated from chrome-plated

Alloy 600 and the Unit 2 anti-vibration bars are fabricated from stainless steel. These

components are identified by the applicant as being potentially susceptible to cracking in the

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secondary water environment. The applicant proposes to utilize a combination of the Water

Chemistry Control Program and the Steam Generator Integrity Program to manage aging of

this component. The SG tube support plates are stainless steel and are also subjected to the

same aging effect and environment.

RAI 3.1-1. In RAI 3.1 -1, dated November 18, 2004, the staff requested the applicant to provide

details regarding how the Steam Generator Integrity Program would support monitoring of the

anti-vibration bars for cracking.

In its response, dated January 6, 2005, the applicant stated that the Water Chemistry Control

Program conforms to the guidelines in EPRI TR-1 02134, Revision 5, and that the Water

Chemistry Control Program mitigates aging effects, such as cracking due to SCC, by controlling

the environment to which the secondary side of the SGs is exposed. The applicant stated that

aging effects are minimized by controlling the chemical species that cause the underlying

mechanisms that result in this aging effect and that the program provides assurance that an

elevated level of contaminants and oxygen does not exist on the secondary-side of the SGs,

and thereby minimizes this aging effect. The applicant indicated that the Water Chemistry

Control Program has been in use since early in the plant's operation and has been effective at

maintaining the desired system water chemistry and detecting abnormal conditions, which have

been corrected in an expedient manner. The applicant also concluded that verification

inspections are not required by the Water Chemistry Control Program, because the

secondary-side of the SGs is not a low-flow or stagnant area and, therefore, the Water

Chemistry Control Program alone effectively manages this aging effect on the secondary-side

of the SGs.

Further, the applicant stated that the Steam Generator Integrity Program is utilized to

conservatively augment the Water Chemistry Control Program to verify the effectiveness of

water chemistry. The applicant indicated that the Steam Generator Integrity Program is

intended to provide a general condition assessment of the secondary side of the steam

generators. The applicant stated that, although the anti-vibration bars are inaccessible for

visual inspection due to the construction of the tube bundle and their location within the tube

bundle, periodic visual inspections of accessible areas are performed to verify the integrity of

secondary-side components. The applicant also stated that the secondary-side inspections will

assess representative material environment combinations similar to the inaccessible

components in the SGs.

The staff found the applicant's response acceptable. Secondary-side visual inspection will be

performed on representative materiaVenvironment combinations that may be used to provide

indication of degradation. The staff's concern described in RAI 3.1-1 is, therefore, resolved.

The staff confirmed that the lattice bars are not made of carbon steel. The staff considered

industry experience and agrees that lattice bars made of stainless steel or Alloy 600 are not

susceptible to flow assisted corrosion. Furthermore,-based on industry experience the staff

agrees that components made from stainless steel or Alloy 600 in secondary treated water with

temperatures greater than 120 OF are susceptible to cracking due to SCC. The staff's

evaluation of the Steam Generator Integrity and Water Chemistry Control Programs are

documented in Sections 3.0.3.2.18 and 3.0.3.2.20, respectively. The staff agrees that the

Water Chemistry Control Program is expected to mitigate cracking and that the Steam

Generator Integrity Program is expected to confirm that cracking is not occurring.

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On the basis of its review of the steam generator integrity and water chemistry control programs

and the fact that the component is made from either stainless steel or Alloy 600, the staff found

that the applicant appropriately evaluated AMR results involving plant-specific programs to

address these aging mechanisms.

The staff found that, based on the programs identified above, the applicant has met the criteria

of SRP-LR Section 3.1.2.2.12. For those line items that apply to LRA Section 3.1.2.2.12, the

staff found that the applicant is consistent with the GALL Report and has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB during the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.1.2.2.13 Ligament Cracking Due to Corrosion

The staff reviewed LRA Section 3.1.2.2.13 against the criteria in SRP-LR Section 3.1.2.2.13.

In the LRA Section 3.1.2.2.13, the applicant addressed ligament cracking due to corrosion that

could occur in carbon steel components in the SG tube support plate.

The applicant stated that carbon steel components are not part of the SG tube support-plates.

However, cracking due to SCC was identified as the aging effect requiring management for the

stainless steel tube support plates in the PBNP steam generators. The applicant also stated

that this aging effect is managed by the Water Chemistry Control Program and augmented by

the Steam Generator Integrity Program, which provides for secondary-side inspections to verify

the effectiveness of water chemistry control.

The staff confirmed that these components are not made of carbon steel. Furthermore, based

on industry experience, the staff agrees that components made of stainless steel or Alloy 600 in

secondary treated water, with temperatures greater than 120 OF, are susceptible to cracking due

to SCC. The staff's evaluation of the Steam Generator Integrity Program and the Water

Chemistry Control Program are documented in Section 3.0.3.2.18 and 3.0.3.2.20, respectively.

The staff agrees that the Water Chemistry Control Program will mitigate cracking and that the

steam generator integrity program will confirm that cracking is not occurring.

On the basis of its review of the Steam Generator Integrity and Water Chemistry Control

Programs, the staff found that the applicant had appropriately evaluated AMR results involving

plant-specific programs to address these aging mechanisms.

The staff found that, based on the programs identified above, the applicant has met the criteria

of SRP-LR Section 3.1.2.2.13. For those line items that apply to LRA Section 3.1.2.2.13, the

staff found that the applicant is consistent with the GALL Report and demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB during the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.1.2.2.14 Loss of Material Due to Flow-Accelerated Corrosion

Loss of material due to flow-accelerated corrosion is only applicable to PWR Combustion

Engineering designs. Therefore, this item is not applicable for Units 1 and 2.

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3.1.2.2.15 Quality Assurance for Aging Management of Non-Safety-Related Components

SER Section 3.0.4 provides the staff's evaluation of the applicant's quality assurance program.

Conclusion. On the basis of its review, for component groups evaluated in the GALL Report for

which the applicant claimed consistency with the GALL Report, and for which the GALL Report

recommends further evaluation, the staff determines that (1) those attributes or features for

which the applicant claimed consistency with the GALL Report were indeed consistent, and (2)

the applicant had adequately addressed the issues that were further evaluated. The staff found

that the applicant had demonstrated that the effects of aging will be adequately managed so

that the intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

3.1.2.3 AMR Resufts That Are Not Consistent with or Not Addressed In the GALL Report

Summary of Technical Information in the Avolication. In LRA Tables 3.1.2-1 through 3.1.2-6,

the applicant provided additional details of the results of the AMRs for material, environment,

aging effect requiring management, and AMP combinations that are not consistent with the

GALL Report or are not addressed in the GALL Report.

As documented under RAI 2.1-1 in SER Section 2.1, by letter dated April 29, 2005, the

applicant changed the methodology used to determine the nonsafety-related SCs that are

within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(2).

As a result of the implementation of the scoping methodology changes, the applicant identified

no changes to LRA Tables 3.1.2-1 through 3.1.2-6.

In LRA Tables 3.1.2-1 through 3.1.2-6, the applicant indicated, via Notes F through J, that

neither the identified component nor the material and environment combination is evaluated in

the GALL Report, and provided information concerning how the aging effect will be managed.

Staff Evaluation. For component type, material, and environment combinations that are not

evaluated in the GALL Report, the staff reviewed the applicant's evaluation to determine

whether the applicant had demonstrated that the effects of aging will be adequately managed

so that the intended function will be maintained consistent with the CLB during the period of

extended operation.

The staff's review of LRA Section 3.1 identified an area in which additional information was

necessary to complete the review of the applicant's results. The applicant responded to the

staff's RAI as discussed below.

In LRA Tables 3.1.2-1 and 3.1.2-4, the applicant listed, as Note H, the following components:

* orifices and reducers (stainless steel)

* piping and fittings less than 4-inch NPS (wrought stainless steel)

* piping and fittings greater than or equal to 4-inch NPS (wrought stainless steel)

* primary loop elbows (cast stainless steel)

* reactor coolant pump thermal barrier flange (wrought stainless steel)

* Ithermowells (stainless steel)

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* valves less than 4-inch NPS (cast stainless steel)

* valves greater than or equal to 4-inch NPS (cast stainless steel)

* pressurizer heater shell and heater sheath (stainless steel)

* pressurizer instrument nozzles (stainless steel)

* pressurizer lower head (carbon steel with stainless steel cladding)

* pressurizer manway cover (carbon steel with stainless steel disc insert)

* pressurizer relief nozzle (carbon steel with stainless steel cladding)

* pressurizer relief nozzle safe end (stainless steel)

* pressurizer safety nozzle (carbon steel with stainless steel cladding)

* pressurizer safety nozzle safe end (stainless steel)

* pressurizer shell (alloy steel with stainless steel cladding)

* pressurizer spray nozzle (carbon steel with stainless steel cladding)

* pressurizer spray nozzle safe end (stainless steel)

* pressurizer spray nozzle thermal sleeve (stainless steel)

* pressurizer surge nozzle (carbon steel with stainless steel cladding)

* pressurizer surge nozzle safe end, thermal sleeve (stainless steel)

* pressurizer upper head (carbon steel with stainless steel cladding)

* reactor coolant pump casing and main flange (cast stainless steel)

Note H items are defined as those whose aging effect was not in NUREG-1801 for this

component, material, and environment combination. The applicant's plant-specific program

designated Notes 5 and 21 for those components. Note 5 states that "The

materiaVenvironment combination and/or aging effect is not identified in NUREG-1 801. The

aging management program(s) referenced are appropriate for the aging effects identified and

provides assurance that the aging effects are effectively managed through the period of

extended operation." Note 21 states that "Materials science supports loss of material due to

pitting (stagnant or low-flow conditions) and crevice corrosion for all temperatures. The Water

Chemistry Control Program is credited for managing the aging effects for all temperatures."

Published literature indicates that pitting corrosion and crevice corrosion may occur in ASME

Code Class 1 stainless steel or NiCrFe 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. The

applicant indicated that the Water Chemistry Control Program manages the aging effects of

corrosion/pitting. The Water Chemistry Control Program is discussed in SER Section 3.0.

Under the program description section of GALL AMP XI.M2, it is stated that the water chemistry

programs are generally effective in removing impurities from intermediate-flow and

high-flow areas. The report identifies those circumstances in which the water chemistry

programs may not be effective in low-flow or stagnant-flow areas. In certain cases, GALL

AMP XL.M2 recommends verification of the effectiveness of the chemistry control program to

ensure significant degradation is not occurring and that the component intended function will be

maintained during the period of extended operation. For specific cases, an acceptable

verification program is a one-time inspection of selected components at susceptible locations in

the system.

RAI 3.1.2-5. LRA Tables 3.1.2-1 and 3.1.2-4 indicate that the Water Chemistry Control

Program is used to manage the effects of loss of material due to corrosion in low-flow and

stagnant areas for a variety of stainless and cast stainless materials. These components are

designated by Note H with footnotes 5 and 21. NUREG-1 801, XL.M2, recommends a One-Time

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Inspection Program to validate the effectiveness of the Water Chemistry Control Program for

low-flow and stagnant areas. In RAI 3.1.2-5, dated November 17, 2004, the staff requested the

applicant to discuss how the aging effect of loss of material for components specified under

Note H of the two listed tables is managed for low-flow/stagnant areas because NUREG-1 801,

XL.M2, specifies that the mitigating effects of a Water Chemistry Control Program alone are not

sufficient.

In its response, dated January 25, 2005, the applicant stated that the GALL Report (GALL)

tables did not reference the aging effect of corrosion in these materials because the primary

coolant environment is strictly controlled through the Water Chemistry Control Program. The

applicant also referenced NRC statements made in its safety evaluations for WCAP-1 4575-A,

Aging Management Evaluation for Pressurizers, along with LRA Applicant Action Item 3.2.2.1-1.

In the safety evaluation, the staff agreed that hydrogen overpressure can mitigate the

aggressive effect of oxygen in creviced geometries on the internal pressurizer surfaces.

Applicant Action Item 3.2.2.1-1 states that applicants for license renewal should provide a basis

in their plant-specific applications about how their Water Chemistry Control Program will provide

for a sufficient level of hydrogen overpressure to manage crevice corrosion of the internal

surfaces of their pressurizer.

The staff's review of the plant-specific response to Applicant Action Item 3.2.2.1-1 indicated that

the applicant maintains strict control of hydrogen overpressure to minimize crevice corrosion for

pressurizers and other Class 1 components through the implementation of the Water Chemistry

Control Program. Furthermore, published literature indicates that the use of hydrogen water

chemistry inhibits the onset of cracking and corrosion and has been used effectively on many

reactor coolant systems in operating reactors to date.

Based on the applicant's use of hydrogen water chemistry, the staff concluded that the aging

effects of corrosion in low-flow areas are managed through the Water Chemistry Control -

Program, which acts as a reasonable deterrent measure in place of a One-Time Inspection

Program. The staff's concern described in RAI 3.1.2-5 is resolved.

3.1.2.3.1 Reactor Coolant System Components That Have No Aging Effect - Tables 3.1.2-1

through 3.1.2-6

In LRA Tables 3.1.2-1 through 3.1.2-6, the applicant identified line items where no aging effects

were identified as a result of the aging review process. Specifically, instances in which the

applicant stated that no aging effects were identified occurred when components fabricated

from carbon steel, low-alloy steel, Alloy 600, stainless steel, copper alloy, or stainless steel clad

material were exposed to air or to an inert gas (e.g., nitrogen). Neither air nor inert gas is

identified in the GALL Report as an environment for these components and materials. No

aging effects are considered to be applicable to carbon steel, low-alloy steel, Alloy 600,

stainless steel, copper alloy, or stainless steel clad components exposed to air, or to an inert

gas environment.

On the basis of its review of current industry research and operating experience, the staff found

that dry air on metal will not result in aging that will be of concern during the period of extended

operation. These RCS components are exposed to high-temperature internal flow, which

creates a dry air environment. Stainless steel and nickel-based alloy components in air or an

inert gas environment are not susceptible to general corrosion that would affect their intended

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function. Therefore, the staff concluded that there are no applicable aging effects requiring

management for carbon steel, low-alloy steel, Alloy 600, stainless steel, copper alloy, or

stainless steel clad components exposed to air, or to an inert gas environment.

3.1.2.3.2 Class 1 Piping/Components System - Aging Management Evaluation - Table 3.1.2-1

The staff reviewed LRA Table 3.1.2-1, which summarizes the results of AMR evaluations for the

Class 1 piping/components system component groups.

The Class 1 piping/components system /experiences loss of material due to corrosion of

stainless steel, wrought stainless steel, low-alloy and nickel-based alloy materials for the

following component types:

* thermowells - valves

* thermal barrier * piping weld and vent connections

* orifices and reducers * RCP pump (casing and main flange)

* piping and fittings * RCP pump (thermal barrier flange)

* primary loop elbows

For those components requiring staff review, the environments are listed below:

treated water - primary (1 40 0F<T<480 0F)(intenal)

* treated water - primary (T>4800 F)(intemal)

* treated water - other

The applicant proposed to manage the Class 1 piping/components loss of material aging

effects by using the Water Chemistry Control Program. The staff's evaluation of this AMP is

documented in SER Section 3.0.3.2.20. On the basis of its review of the applicant's

plant-specific and industry operating experience, the staff found that the effects of loss of

material (pitting and crevice corrosion) on stainless steel, cast stainless steel, low-alloy

stainless steel cladding, and nickel-based alloy components in treated water are effectively

managed using the Water Chemistry Control Program. On this basis, the staff found that

management of loss of material in Class 1 piping/components system is acceptable.

The applicant proposed to manage cracking in stainless steel, cast stainless steel, nickel-based

alloy and low-alloy steel clad components exposed to treated water - primary

(140 0F<T<480 OF)(intemal) and treated water - primary (T>480 0F)(internal) using the Water

Chemistry Control Program, Closed-Cycle Cooling Water System Surveillance Program, and

the ASME Code Section Xl, Subsections IWB, IWC, and IWD Inservice Inspection Program.

The staff reviewed the Water Chemistry Control Program, Closed-Cycle Cooling Water System

Surveillance Program, and ASME Code Section Xl, Subsections IWB, IWC, and IWD Inservice

Inspection Program. The evaluations are documented in SER Sections 3.0.3.2.20, 3.0.3.2.9,

and 3.0.3.2.1, respectively.

On the basis of its review of the applicant's plant-specific and industry operating experience,

the staff found that the effects of cracking in stainless steel, cast stainless steel, nickel-based

alloy and low-alloy steel clad components exposed to treated water are effectively managed

using the Water Chemistry Control Program and the ASME Code Section Xl, Subsections IWB,

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IWC, and IWD Inservice Inspection Program. On this basis, the staff found that management

of cracking in Class 1 piping/components system is acceptable.,

The applicant proposed to manage erosion of stainless steel orifices and reducers exposed to

treated water using the One-Time Inspection Program. The applicant stated that when used to

detect the aging effect of loss-of-wall thickness due to erosion, the One-Time Inspection

Program uses wall thickness as a parameter that must be monitored and visual inspection

(VT-3) and/or volumetric inspection (RT/UT) as the appropriate inspection method. Volumetric

NDE methods to measure wall thickness are currently used by industry to detect and monitor

erosion/corrosion in piping systems at nuclear power plants. The applicant stated that it will use

wall thickness measurements and compare those wall thickness measurements against criteria

based upon design criteria for the subject component.

The staff reviewed the One-Time Inspection Program. Its evaluation is documented in SER

Section 3.0.3.2.13. On the basis of its review of the applicant's plant-specific and industry

operating experience, the staff found that the effects of erosion of stainless steel orifices and

reducers exposed to treated water are effectively managed using the One-Time Inspection

Program. On this basis, the staff found that management of loss of material in Class 1

piping/components system using this program is acceptable.

In LRA Table 3.1.2-1, the applicant listed as Note F for the following components that correlate

to material not in GALL:

* piping welds and vent connections (Alloy 690 and 82/152) (Unit 2 only)

* reactor coolant pumps thermal barrier flange (wrought stainless steel)

* valves less than 4-inch NPS (wrought stainless steel)

* valves greater than or equal to 4-inch NPS (wrought stainless steel)

Plant-specific Note 5 accompanied each of the above components. Note 5 states: -

The material/environment combination and/or aging effect is not identified in

NUREG-1 801. The aging management program(s) referenced are appropriate for the

aging effects identified and provides assurance that the aging effects are effectively

managed through the period of extended operation.

The staff compared the component items in LRA Table 3.1.2-1 against Table 1 of GALL. The

applicant's AMR specified the appropriate AMP suggested by GALL that correlated to the aging

effect for the component's material. For the piping welds made out of Alloy 690 and 82/152

weld material, the applicant specified the Reactor Coolant System Alloy 600 Program, the

Water Chemistry Control Program and the Inservice Inspection Program as the AMPs to

manage the effects of aging. Though the GALL Volume 2 line item number does not agree with

the GALL material type (cast stainless steel), the appropriate plant-specific AMP was specified

by the applicant for the material types.

For component C2.4-b, GALL Table 2 lists crack initiation and growth/SCC as the aging

effect/mechanisms. Though the material in Table 2 for that component identification is cast

stainless steel, the applicant appropriately identified the aging effect for its plant-specific

material and the appropriate AMP recommended by GALL in Table 1. Based on the above

discussion, the staff concluded that the items listed as Note F in the applicant's aging

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management review are consistent with the intent of GALL. The staff concluded that this

consistency with GALL provides reasonable assurance the effects of aging will be managed

and, therefore, the AMP is acceptable for the period of extended operation.

3.1.2.3.3 Reactor Vessel - Aging Management Evaluation - Table 3.1.2-2

The staff reviewed LRA Table 3.1.2-2, which summarizes the results of AMR evaluations for the

reactor vessel component groups.

Loss of material due to wear and corrosion for Alloy 600 and stainless steel components

including the core support pads and the RV components exposed to primary treated water'

(T > 480 IF) is proposed to be managed by using the ASME Code Section XI, Subsections

IWB, IWC, and IWD Inservice Inspection Program or the Water Chemistry Control Program.

Inspections under the requirements of the ASME Code Section Xl, Subsections IWB, IWC, and

IWD Inservice Inspection Program provide a combination of volumetric and visual examinations

that will detect loss of material and confirm the effectiveness of the Water Chemistry Control

Program.

The applicant proposed to manage cracking due to SCC and flaw growth for stainless steel and

Alloy 600 components including bottom-mounted instrument guide tubes, core support pads,

and seal table fittings exposed to primary treated water (T > 480 'F) (T < 140 IF) by using the

Water Chemistry Control Program and the ASME Code Section Xl, Subsections IWB, IWC, and

IWD Inservice Inspection Program.

The applicant proposed to manage loss of mechanical closure integrity due to stress relaxation

for low-alloy steel components including closure studs, nuts, and washers exposed to

containment (external) by using the ASME Code Section Xl, Subsections IWB, IWC, and IWD

Inservice Inspection Program.

The staff reviewed the applicant's Water Chemistry Control Program and the ASME Code

Section XI, Subsections IWB, IWC, and IWD Inservice Inspection Program. Its evaluation is

documented in SER Sections 3.0.3.2.20 and 3.0.3.2.1, respectively.

On the basis of its review of the applicant's plant-specific and industry operating experience, the

staff found that the effects of aging are effectively managed by using the Water Chemistry

Control Program and the ASME Code Section XI, Subsections IWB, IWC, and IWD Inservice

Inspection Program. On this basis, the staff found that aging management in the reactor vessel

components group is acceptable.

3.1.2.3.4 Reactor Vessel Intemals - Aging Management Evaluation - Table 3.1.2-3

The staff reviewed the LRA Table 3.1.2-3, which summarizes the results of AMR evaluations in

the SRP-LR for the reactor vessel internals component groups.

The applicant proposed to manage loss of material in stainless steel material of reactor vessel

internals component types exposed to primary treated water (T>480 IF) using the Water

Chemistry Control Program.

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The staff reviewed the applicant's Water Chemistry Control Program. Its evaluation is

documented in SER Section 3.0.3.2;20. On the basis of its review of the applicant's

plant-specific and industry operating experience, the staff found that the loss of material in

stainless steel for component types of reactor vessel internals exposed surfaces and crevice

locations exposed to treated water is effectively managed using the Water Chemistry Control

Program. On this basis, the staff found that management of loss of material in reactor vessel

internals using this program is acceptable.

The applicant proposed to manage loss of fracture toughness due to neutron irradiation

embrittlement in stainless steel components in the fuel zone, including the flux thimbles reactor

vessel upper core plate and the reactor vessel upper core plate fuel alignment pin exposed to

primary treated water (T>4800F) using the Reactor Vessel Internals Program.

The applicant stated that it performed destructive examinations of baffle/former bolts removed

during the 1999 refueling outage and these examinations suggest that void swelling and loss of

fracture toughness should not present a concern during the period of extended operation. The

reactor vessel upper core plate and the reactor vessel upper core plate fuel alignment pin

components are not included among the components subject to significant irradiation

embrittlement because of their remote location from the fuel zone.

The staff found that, based on its review of the description of the applicant's Reactor Pressure

Vessel Internals Program and on the commitment that the applicant will provide the Reactor

Pressure Vessel Internals Program for staff review prior to the period of extended operation, as

discussed in SER Section 3.0.3.2.16, management of loss of fracture toughness using the

Reactor Vessel Internals Program is acceptable.

3.1.2.3.5 Pressurizer - Aging Management Evaluation - Table 3.1.2-4

The staff reviewed LRA Table 3.1.2-4, which summarizes the results of AMR evaluations for the

pressurizer component groups.

The pressurizer experiences loss of material of stainless steel, and carbon steel or alloy steel

with stainless steel cladding or disc insert for the following component types:

* heater well * shell

* heater sheath * spray nozzle

* instrument nozzles * spray nozzle safe ends

* manway cover * nozzle thermal sleeve

* relief nozzle * surge nozzle

* relief nozzle safe ends * surge nozzle thermal sleeve

* safety nozzle * surge nozzle safe ends

* safety nozzle safe ends * upper and lower head

Those components requiring staff review are exposed to an environment of primary treated

water with temperature greater than 480 OF.

The applicant proposed to manage the pressurizer loss of material aging effects by using the

Water Chemistry Control Program. During the audit the applicant clarified that the use of only

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the Water Chemistry Control Program was considered sufficient to manage these components

because industry operating experience has not identified material loss on these components.

The staff reviewed the applicant's Water Chemistry Control Program. Its evaluation is

documented in SER Section 3.0.3.2.20. On the basis of its review of the applicant's

plant-specific and industry operating experience, the staff found that the effects of loss of

material of stainless steel, and low-alloy carbon steel with stainless steel cladding components

in treated borated water are effectively managed using the Water Chemistry Control Program.

On this basis, the staff found that management of loss of material in the pressurizer using this

program is acceptable.

3.1.2.3.6 Steam Generators - Aging Management Evaluation - Table 3.1.2-5

The staff reviewed LRA Table 3.1.2-5, which summarizes the results of AMR evaluations for the

steam generator component groups.

The SG experiences loss of material of stainless steel, Alloy 600/690, and alloy steel materials

for the following component types:

* components in contact with primary water

* feedwater nozzles

* steam flow limiter

For those components requiring staff review, the environments are listed below:

* treated water - primary (T>480 OF)(intemal)

* treated water - secondary (T>120 'F)(internal)

The applicant proposed to manage the SG loss of material aging effects by using the Steam

Generator Integrity Program and Water Chemistry Control Program.

The applicant also proposed to manage cracking of Alloy 600, alloy steel, and stainless steel for

component types of anti-vibration bars, feedwater nozzles, transition cone girth weld (Unit 1

only), tube sheet, upper and lower shell, elliptical head, transition cone, tube support plates,

and steam outlet nozzle exposed to secondary treated water with temperatures greater than

120'F by using the Water Chemistry Control Program, Steam Generator Integrity Program, and

ASME Section Xi, Subsections IWB, IWC, and IWD Inservice Inspection Program.

The staff's review of LRA Table 3.1.2-5 identified areas in which additional information was

necessary to complete the review of the applicant's results. The applicant responded to the

staff's RAls as discussed below.

In LRA Table 3.1.2-5, the applicant identified that the SG divider plates are fabricated from

Alloy 600/690 and that these components are potentially susceptible to cracking in the primary

water environment. The applicant proposed to use the Water Chemistry Control Program to

manage this aging effect.

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RAI 3.1-3. In RAI 3.1-3, dated November 18, 2004, the staff requested the applicant to justify

why the Water Chemistry Control Program alone is sufficient to manage aging for Alloy 600/690

sub-components.

RAI 3.1-4. In RAI 3.1-4, dated November 18, 2004, the staff requested the applicant to justify

why inspections are not used to support the Water Chemistry Control Program for SG divider

plates.

In its response, dated January 6, 2005, the applicant stated that the divider plate acts as a flow

baffle with minimal primary stresses resulting from the low differential pressure across the plate

and that the main contributor to operating stress results from thermal stress. The applicant

indicated that inspection could be performed in connection with other SG inspection activities,

but that dose considerations would preclude inspection. The applicant also indicated that there

has been no industry operating experience indicating problems with stress corrosion cracking of

the divider plate.

The staff concluded that use of the Water Chemistry Control Program was sufficient to manage

age-related degradation of this component because this component is not located in a low-flow

or stagnant area, there Is no industry experience of failure, and, if necessary, inspection could

be performed during steam generator inspection activities. The staff's concerns described in

RAls 3.1-3 and 3.1-4 are resolved.

The applicant identified that aging would be managed for a number of secondary-side steam

generator components (i.e., steam outlet nozzle, feedwater nozzle) potentially susceptible to

loss of material by the Water Chemistry Control Program and Steam Generator Integrity

Program. Other components (i.e., steam generator blowdown piping and secondary shell

penetrations) also identified as potentially susceptible to loss of material would be managed by

the Water Chemistry Control Program and Steam Generator Integrity Program.

RAI 3.1-2. In RAI 3.1-2, dated November 18, 2004, the staff requested the applicant to clarify if

the Steam Generator Integrity Program (steam generator secondary-side inspection) was

intended to meet the inservice inspection requirements for those secondary-side components

that do not use the Inservice Inspection Program. The staff also requested additional details

regarding how the Steam Generator Integrity Program could manage aging of components such as the blowdown piping nozzle and secondary shell penetrations.

In its response, dated January 6, 2005, the applicant stated that the Inservice Inspection

Program was only identified for those components that are within the Inservice Inspection

Program scope. Items such as the blowdown nozzles and secondary penetrations are not

within scope. The applicant indicated that inservice inspection was identified to supplement

water chemistry and the Steam Generator Integrity Program because the inservice Inspections

were capable of detecting loss of material, although detection of loss of material is not the

primary focus of the inservice inspection exam. The applicant relies on the Water Chemistry

Control Program and the Steam Generator Integrity Program to manage loss of material for all

of these components. The applicant indicated that the Water Chemistry Control Program

maintains an environment limiting the potential susceptibility for loss of material and that the

Steam Generator Integrity Program employs secondary-side inspection. The applicant

indicated that where secondary components are inaccessible, similar materials in a similar

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environment are used to evaluate the potential for degradation of those inaccessible

components.

The staff found the applicant's response acceptable. The applicant will establish a framework

that is expected to manage loss of material using a combination of a low-susceptibility

environment created by the Water Chemistry Control Program to minimize the potential for

degradation and inspection by the Steam Generator Integrity Program and, when possible, the

Inservice Inspection Program, to identify the potential for degradation. The staff's concern

described in RAI 3.1.2 is resolved.

LRA Table 3.1.2-5 identifies Notes H, 21 and J, 5 for loss of material in stainless steel, carbon

steel clad with stainless steel and Alloy 600/690 materials. For these AMRs only the Water

Chemistry Control Program is identified as the applicable AMP. PBNP personnel have

indicated that the basis for using only the mitigative Water Chemistry Control Program is that

the program does not require lack of aging effect validation if the flow is moderate or high. The

staff considers this a misinterpretation of the GALL AMP. The GALL Report identifies stagnant

or low flow conditions as examples of when it would be appropriate to validate the effectiveness

of the Water Chemistry Control Program. The GALL Report utilizes this example to

demonstrate when a validation of aging management program is appropriate, but does not

define, by default, when a validation should not be used. In conditions of moderate or high flow,

an SSC could have crevice or other locations of low or stagnant flow. Furthermore, all systems

are shut down and flow is reduced to stagnant conditions at some point in the SCC's service

life. Therefore, this was identified as open item (01) 3.1.1-3.

In its response to 01 3.1.1-3, by letter dated June 10, 2005, the applicant stated that, for SG

components in contact with primary water, the same material types in the same environments

exist in the RV, the vessel internals, the pressurizer, and the Class 1 piping and components.

In all of these systems and components, loss of material is proposed to be managed with the

Water Chemistry Control Program alone (and was found by the staff to be acceptable in the

draft safety evaluation report (D-SER)). The primary side of the SG is no different. Stainless

steel and nickel alloy are corrosion-resistant materials, and industry and plant-specific operating

experience has shown that loss of material is not an active degradation mechanism on

primary-side components, primarily due to the strict water chemistry controls used in PWRs.

Other components in this same environment are routinely inspected (i.e., SG tubes), and these

inspections would provide leading indications to the susceptibility of these materials to loss of

material.

The staff reviewed the applicant's characterization and re-evaluated the GALL Report for loss of

material in stainless steel, carbon steel clad with stainless steel and Alloy 600/690 materials

and concluded that the applicant's response is acceptable. The staff's concern is resolved and,

therefore, 01 3.1.1-3 is closed.

3.1.2.3.7 Non-Class 1 RCS Components - Aging Management Evaluation - Table 3.1.2-6

The staff reviewed LRA Table 3.1.2-6, which summarizes the results of AMR evaluations for the

non-Class 1 RCS components groups.

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The non-Class 1 RCS components experience loss of material of stainless steel, copper alloy

(Zn<1 5%), copper alloy (Zn>1 5%), and CASS materials for the following component types:

* flow indicators * valve bodies

* instrument valve assemblies * tanks

* piping and fittings * thermowells

* heat exchangers

For those components requiring staff review, the environments are listed below:

* treated water - borated (T<1 40 'F)(internal)

* treated water - other (internal)

* treated water - primary (T>480 1F)(internal)

* treated water - primary (T<1 40 0F)(internal)

* treated water - primary (140 OF<T<480 OF)(internal)

* air and gas - wetted (T<140 0F)(internal)

* treated water - other (stagnant)(internal)

The applicant proposed to manage the non-Class 1 RCS components loss of material aging

effects by using the Water Chemistry Control Program, Closed-Cycle Cooling Water System

Surveillance Program and One-Time Inspection Program.

The staff reviewed the Water Chemistry Control Program, Closed-Cycle Cooling Water System

Surveillance Program and One-Time Inspection Program. Its evaluations are documented in

SER Sections 3.0.3.2.20, 3.0.3.2.9 and 3.0.3.2.13, respectively. On the basis of its review of

the applicant's plant-specific and industry operating experience, the staff found that the effects

of loss of material on stainless steel, copper alloys, and CASS material for components

exposed to treated borated water, treated water, and wetted air and gas are effectively

managed using the Water Chemistry Control Program, Closed-Cycle Cooling Water System

Surveillance Program, and One-Time Inspection Program. On this basis, the staff found that

management of loss of material in non-Class 1 RCS components using these programs is

acceptable.

The applicant proposed to manage cracking of stainless steel for component types of

Instrument valve assemblies, pipings, fittings, and valve bodies exposed to primary treated

water with temperatures greater than 480 OF and temperatures between 140 OF and 480 OF by

using the Water Chemistry Control Program and the One-Time Inspection Program.

The staff reviewed the applicant's Water Chemistry Control Program and One-Time Inspection

Program. Its evaluations are documented in SER Sections 3.0.3.2.20 and 3.0.3.2.13,

respectively. On the basis of its review of the applicant's plant-specific and industry operating

experience, the staff found that the effects of cracking on instrument valve assemblies, pipings,

fittings, and valve bodies for components exposed to primary treated borated water with

temperatures greater than 480 OF, and temperatures between 140 OF and 480 OF are effectively

managed using the Water Chemistry Control Program and One-Time Inspection Program. On

this basis, the staff found that management of cracking in non-Class 1 RCS components using

these programs is acceptable. -<-

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Conclusion. On the basis of its review, the staff found that the applicant had appropriately

evaluated AMR results involving material, environment, AERM, and AMP combinations that are

not evaluated in the GALL Report. The staff found that the applicant had demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.1.3 Conclusion

On the basis of its review, the staff concluded that the applicant demonstrated that the aging

effects associated with the RCS components will be adequately managed so that the intended

functions will be maintained 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 concluded

that they adequately describe the AMPs credited for managing aging of the reactor coolant

systems as required by 10 CFR 54.21(d).

3.2 Agina Management of Enaineered Safety Features'

This section of the SER documents the staff's review of the applicant's AMR results for the

engineered safety features (ESF) and component groups associated with the following

systems:

* safety injection system

* containment spray system

* residual heat removal system

* containment isolation components system

3.2.1 Summary of Technical Information In the Application

In LRA Section 3.2, the applicant provided AMR results for ESF components and component

groups. In LRA Table 32.1, "Summary of Aging Management Evaluations in Chapter V of

NUREG-1 801 for Engineered Safety Features," the applicant provided a summary comparison

of its AMRs with the AMRs evaluated in the GALL Report for the ESF components and

component groups.

The applicant's AMRs incorporated applicable operating experience in the determination of

AERM. 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 AERM. 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.

32.2 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 ESF components that are within the scope of

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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).

Also, the staff performed an onsite audit of AMRs to confirm the applicant's claim that certain

identified AMRs are consistent with the GALL Report. The staff did not repeat its review of the

matters described in the GALL Report. However, the staff did confirm that the material

presented in the LRA was applicable and that the applicant had identified the appropriate GALL

AMPs. The staff's evaluations of the AMPs are documented in SER Section 3.0.3. The staff's

audit evaluations are documented in the PBNP audit and review report and are summarized in

SER Section 3.2.2.1.

The staff also performed an onsite audit of those AMRs that are consistent with the GALL

Report and for which further evaluation is recommended. The staff confirmed that the

applicant's further evaluations were consistent with the acceptance criteria in NUREG-1 800

Section 3.2.2.2, "Standard Review Plan for Review of License Renewal Applications for Nuclear

Power Plants," dated July 2001. The staff's audit evaluations are documented in the PBNP

audit and review report and are summarized in SER Section 3.2.2.2.

The staff performed an onsite audit and conducted a technical review of the remaining AMRs

that were not consistent with or not addressed in the GALL Report. The review included

evaluating whether all plausible aging effects had been identified and whether the aging effects

listed were appropriate for the combination of materials and environments specified. The staff's

audit evaluation is documented in the PBNP audit and review report and is summarized in SER

Section 3.2.2.3. The staff's evaluation of its technical review is also documented in SER

Section 3.2.2.3.

Finally, the staff reviewed the AMP summary descriptions in the FSAR supplement to ensure

that they provided an adequate description of the programs credited with managing or

monitoring aging for the ESF components.

Table 3.2-1 provides a summary of the staff's evaluation of components, aging

effects/mechanisms, and AMPs listed in LRA Section 3.2 that are addressed in the GALL

Report.

Table 3.2-1 Staff Evaluation for Engineered Safety Features System Components In the

GALL Report -

Component Group Aging ltffecti APIn GALAMPi JA tafvaato

Piping, fittings, and Cumulative fatigue TLAA, evaluated in TLAA 'This TLAA jsis

valves in damage accordance with evaluated in II

emergency core 10 CFR 54.21 (c) Section 4.3, Metal

cooling system Fatigue (See" (Item Number Section 3.2.2.2.1)

3.2.1-01) _ : .

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Cmbponent Group A Effectl AMP n A AMPin LRA St^ - iluation

ichanism - Report - -

Components in Loss of material Plant-specific Not Applicable Not Applicable (See

containment spray due to general Section.3.2.2.2.2)

(PWR only), corrosion

standby gas

treatment (BWR

only), containment

isolation, and

emergency core

cooling systems

(Item Number

3.2.1-03)

Components In Loss of material Plant-specific Water Chemistry Consistent with

containment spray due to pitting and Control Program; GALL, which

(PWR only), crevice corrosion One-Time recommends further

standby (BWR Inspection Program evaluation (See

only), containment Section 3.2.2.2.3)

isolation, and

emergency core

cooling systems

(Item Number

3.2.1-05)

Containment Loss of material Plant-specific Not Applicable Not Applicable (See

isolation valves and due to Section 3.2.2.2.4)

associated piping microbiologically

(Item Number influenced corrosion

3.2.1-06)

High-pressure Loss of material Plant-specific One-Time Consistent with

safety injection due to erosion Inspection Program GALL (See

(charging) pump Section 3.2.2.2.6)

miniflow orifice

(Item Number

3.2.1-08)

Extemal surfaces of Loss of material Plant-specific System Monitoring Consistent with

carbon steel due to general Program GALL, which

components corrosion recommends further

(Item Number evaluation (See

3.2.1-10) Section 3.0.3.3.2)

Piping and fittings Loss of fracture Thermal aging Not Applicable Not Applicable

of CASS in toughness due to embrittlement of

emergency core thermal aging CASS

cooling systems embrittlement

(Item Number

3.2.1-11)

Component Local loss of Open-cycle cooling Not Applicable Not Applicable

serviced by material due to water system

open-cycle cooling corrosion and/or

system buildup of deposit

(Item Number due to biofouling

3.2.1-12)

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Component Group Ag:ng A GALL AP it In Evaluation _____ ____ ____ M echanism R p r _ _ _ _ _ _ _ _ _ _ _ _ _ _

Components Loss of material Closed-cycle One-Time Consistent with

serviced by due to general cooling water Inspection Program; GALL, which

closed-cycle cooling pitting and crevice system Closed-Cycle recommends no

system corrosion Cooling Water further evaluation

(Item Number System Surveillance (See 3.2.1-13) Program; Water Section 3.2.2.1)

Chemistry Control

Program

Pumps, valves, Crack initiation and Water chemistry Water Chemistry Consistent with

piping, fittings, and growth due to SCC Control Program; GALL, which

tanks in One-Time recommends no

containment spray Inspection Program further evaluation

and emergency (See

core cooling Section 3.2.2.1)

systems

(Item Number

3.2.1-15) . ._._._.

Carbon steel LOSS of material Boric acid corrosion Boric Acid Corrosion Consistent with

components due to boric acid Program GALL, which

(Item Number corrosion recommends no

3.2.1-17) further evaluation

(See ._ ._ - .Section 3.2.2.1)

Closure bolting in Loss of material Bolting integrity Bolting Integrity Consistent with

high-pressure or due to general Program GALL, which

high-temperature corrosion, loss of recommends no

systems preload due to further evaluation

(Item Number stress relaxation (See 3.2.1-18) and crack initiation Section 3.2.2.1)

and growth due to

cyclic loading or

SOC

The staff's review of the ESF components and associated components followed one of several

approaches. One approach, documented in SER Section 3.2.2.1, involves the staff's review of

the AMR results for components in the ESF that the applicant indicated are consistent with the

GALL Report and do not require further evaluation. Another approach, documented in SER

Section 3.2.2.2, involves the staff's review of the AMR results for components in the ESF that

the applicant indicated are consistent with the GALL Report and for which further evaluation is

recommended. A third approach, documented in SER Section 3.2.2.3, involves the staff's;

review of the AMR results for components in the ESF that the applicant indicated are not

consistent with the GALL Report or are not addressed in the GALL Report. The staff's review

of AMPs that are credited to manage or monitor aging effects of the ESF components is

documented in SER Section 3.0.3.

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3.2.2.1 AMR Results That Are Consistent with the GALL Report, for Which Further

Evaluation Is Not Recommended

Summary of Technical Information in the Aomlication. In LRA Section 3.2.2.1, the applicant

identified the materials, environments, and aging effects requiring management. The applicant

identified the following programs that manage the aging effects related to the ESF components:

* Bolting Integrity Program

* Boric Acid Corrosion Program

* Closed-Cycle Cooling Water System Surveillance Program

* One-Time Inspection Program

* Periodic Surveillance and Preventive Maintenance Program

* Systems Monitoring Program

* Water Chemistry Control Program

Staff Evaluation. In LRA Tables 3.2.2-1 through 3.2.2-4, the applicant provided a summary of

AMRs for the safety injection system, containment spray system, residual heat removal system,

and containment isolation components system 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 plant-specific

components contained in these GALL Report component groups were bounded by the GALL

Report evaluation.

The applicant provided a note for each AMR line item. The notes described how the

information in the tables aligns with the information in the GALL Report. The staff's audit of

those AMRs with Notes A through E, indicated the AMR was consistent with the GALL Report.

Note A indicated that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the AMP

identified in the GALL Report. The staff audited these line items to verify consistency with the

GALL Report and the validity of the AMR for the site-specific conditions.

Note B indicated that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

AMP identified in the GALL Report. The staff audited these line items to verify consistency with

the GALL Report. The staff verified that the identified exceptions to the GALL AMPs had been

reviewed and accepted by the staff. The staff also determined whether the AMP identified by

the applicant was consistent with the AMP identified in the GALL Report and whether the AMR

was valid for the site-specific conditions.

Note C indicated that the component for the AMR line item, although different, is consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent

with the AMP identified by the GALL Report. This note indicates that the applicant was unable

to find a listing of some system components in the GALL Report. However, the applicant

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identified a different component in the GALL Report that had the same material, environment,

aging effect, and AMP as the component that was under review. The staff audited these line

items to verify consistency with the GALL Report. The staff also determined whether the AMR

line item of the different component was applicable to the component under review and whether

the AMR was valid for the site-specific conditions.

Note D indicated that the component for the AMR line item, although different, is consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP takes some

exceptions to the AMP identified in the GALL Report. The staff audited these line items to

verify consistency with the GALL Report. The staff verified whether the AMR line item of the

different component was applicable to the component under review. The staff determined that

the identified exceptions to the GALL AMPs had been reviewed and accepted by the staff. The

staff also determined whether the AMP identified by the applicant was consistent with the AMP

identified in the GALL Report and whether the AMR was valid for the site-specific conditions.

Note E indicated that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but a different aging management program is credited. The

staff audited these line items to verify consistency with the GALL Report. The'staff also

determined whether the identified AMP would manage the aging effect consistent with the AMP

identified by the GALL Report and whether the AMR was valid for the site-specific conditions.

The staff conducted an audit and review of the information provided in the LRA, as documented

in its PBNP audit and review report. The staff did not repeat its review of the matters described

in the GALL Report. However, the staff did verify that the material presented in the LRA is

applicable and that the applicant had identified the appropriate GALL Report AMRs. The staff

reviewed the LRA to confirm that the applicant had (1) provided a brief description of the

system, components, materials, and environment, (2) stated that the applicable aging effects

have been reviewed and are evaluated in the GALL Report, and (3) identified those aging

effects for the ESF components that are subject to an AMR. On the basis of its audit and

review, the staff determined that for AMRs not requiring further evaluation, as identified in LRA

Table 3.2.1 (Table 1), the applicant's references to the GALL Report are acceptable and no

further staff review is required.

Conclusion. The staff evaluated the applicant's claim of consistency with GALL Report. The

staff also reviewed information pertaining to the applicant's consideration of recent operating

experience and proposals for managing associated aging effects. On the basis of its review,

the staff found that the AMR results that the applicant claimed to be consistent with the GALL

Report are consistent with the AMRs in the GALL Report. Therefore, the staff found that the

applicant had demonstrated that the effects of aging for these components will be adequately

managed so that their intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

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

Evaluation Is Recommended

Summary of Technical Information in the Application. In LRA Section 3.2.2.2, the applicant

provided further evaluation of aging management as recommended by the GALL Report for

ESF. The applicant provided information concerning how it will manage the following aging

effects:

* cumulative fatigue damage

* loss of material due to general corrosion

* local loss of material due to pitting and crevice corrosion

* local loss of material due to microbiologically influenced corrosion

* changes in properties due to elastomer degradation

* local loss of material due to erosion

* buildup of deposits due to corrosion

Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant

claimed consistency with the GALL Report, and for which the GALL Report recommends further

evaluation, the staff reviewed the applicant's evaluation to determine whether it adequately

addressed the issues that were further evaluated. In addition, the staff reviewed the applicant's

further evaluations against the criteria in SRP-LR Section 3.2.2.2. Details of the staff's audit

are documented in the staff's PBNP audit and review report.

3.2.2.2.1 Cumulative Fatigue Damage

In LRA Section 3.2.2.2.1, the applicant stated that fatigue is a TLAA, as defined in

10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21 (c)(1). SER

Section 4.3 documents the staff's review of the applicant's evaluation of this TLAA.

3.2.2.2.2 Loss of Material Due to General Corrosion

The staff reviewed LRA Section 3.2.2.2.2 against the criteria in SRP-LR Section 3.2.2.2.2.

In LRA Section 3.2.2.2.2, the applicant addressed loss of material due to general corrosion for

external and internal environments in ESF components.

SRP-LR Section 3.2.2.2.2 states that loss of material due to general corrosion could occur in

the containment spray, containment isolation valves and associated piping, and the external

surfaces of carbon steel components. The GALL Report recommends further evaluation on a

plant-specific basis to ensure that the aging effect is adequately managed.

In LRA Section 3.2.2.2.2, the applicant stated that the loss of material due to general corrosion

line item was not used, although PBNP does have carbon steel components in the ESF. The

applicant addresses this aging effect for external environments in Item Number 3.2.1-1 0, and

credits the Systems Monitoring Program for aging management. Internal environments are

addressed in loss of material due to pitting and crevice corrosion, for which the Water

Chemistry Control Program and/or the One-Time Inspection Program are credited.

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As documented in the audit and review report, the applicant stated that one-time inspections for

general corrosion will monitor component wall thickness. Monitoring methods will include visual

(VT-3) and/or volumetric (RT/UT) examinations. Visual inspections will be performed only when

the components are drained/opened and the component surface of interest is accessible. If

degradation is identified through a visual inspection, additional NDE may be performed to

characterize the degradation and determine the extent of the condition. The applicant stated

that the NDE exams will be performed as a part of its One-Time Inspection Program and will be

conducted in accordance with the requirements of ASME Code Section Xl and 10 CFR Part 50,

Appendix B.

The staff reviewed the applicant's One-Time Inspection Program, Systems Monitoring Program,

and Water Chemistry Control Program and its evaluation is documented in SER

Sections 3.0.3.2.13, 3.0.3.3.2, and 3.0.3.2.20, respectively.

The staff found that, based on the programs identified above, the applicant has met the criteria

of SRP-LR Section 3.2.2.2.2 for further evaluation. For those line items that apply to LRA

Section 3.2.2.2.2, the staff found that the applicant is consistent with the GALL Report and has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained during the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.2.2.2.3 Local Loss of Material Due to Pitting and Crevice Corrosion

The staff reviewed LRA Section 3.2.2.2.3 against the criteria in SRP-LR Section 3.2.2.2.3.

In LRA Section 3.2.2.2.3.2, the applicant addressed local loss of material from pitting and

crevice corrosion. LRA Table 3.2.1, Item 3.2.1-05 and LRA Section 3.2.2.2.3.2 are also used

for managing general corrosion and MIC.

SRP-LR Section 3.2.2.2.3.1 states that the existing aging management program relies on

monitoring and control of primary water chemistry based on the guidelines presented in

EPRI TR-1 05714 for PWRs to mitigate degradation. However, control of coolant water

chemistry does not preclude loss of material due to crevice and pitting corrosion at locations of

stagnant flow conditions. Therefore, verification of the effectiveness of the Water Chemistry Control Program should be performed to ensure that corrosion is not occurring. The GALL

Report recommends further evaluation of programs to manage the loss of material due to

pitting and crevice corrosion to confirm the effectiveness of the Water Chemistry Control

Program. A one-time inspection of selected components at susceptible locations is an ,

acceptable method to determine whether an aging effect is not occurring or an aging effect is

progressing very slowly so that the component's intended function will be maintained during the

period of extended operation.

In LRA Section 3.2.2.2.3.1, the applicant stated that SRP-LR Section 3.2.22.!S.1 is applicable to

BWRs only.

SRP-LR Section 3.2.2.2.3.2 states that 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 external surface. The GALL Report

recommends further evaluation to ensure that the aging effect is adequately managed

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consistent with the acceptance criteria as described in Branch Technical Position RSLB 1

(NUREG-1800 Appendix A.1).

In LRA Table 3.2.1, Item 3.2.1-05, the applicant refers to LRA Section 3.2.2.2.3.2 for the

plant-specific further evaluation. In LRA Section 3.2.2.2.3.2, the applicant stated that the

refueling water storage tank (RWST) is located indoors, not buried, and not susceptible to a

wetted environment and, therefore, is not subject to this aging effect/mechanism. The applicant

also stated that pitting and crevice corrosion typically are managed by the Water Chemistry

Control Program and the One-Time Inspection Program. In LRA Section 3.2.2.2.3.2, the

applicant does not discuss or summarize the evaluation findings, nor does LRA

Section 3.2.2.2.3.1 make reference to the applicability of SRP-LR Section 3.2.2.2.3.1.

As documented in the audit and review report, the applicant stated that the evaluation of

whether the aging management programs specified adequately manage the effects of aging

identified in the Table 3.X.1 line item that require further evaluation was performed and is

described in LRA Appendix B and its supporting plant documents. The applicant stated that its

Water Chemistry Control Program conforms to the guidelines in EPRI TR-105714, Revision 4,

and EPRI TR-102134, Revision 5. The Water Chemistry Control Program mitigates aging

effects such as loss of material due to general, pitting, and crevice corrosion, and MIC, by

controlling the environment to which components and associated piping are exposed. This

aging effect is minimized by controlling the chemical species that cause the underlying

mechanisms that result in this aging effect. The program provides assurance that an elevated

level of contaminants and oxygen does not exist and, therefore, minimizes the occurrences of

this aging effect. The applicant stated that its Water Chemistry Control Program has been in

effect since initial plant operation and has been effective at maintaining the desired system

water chemistry and detecting abnormal conditions, which have been corrected in an expedient

manner.

The applicant further stated that because water chemistry alone will not preclude the loss of

material due to pitting and crevice corrosion, a one-time inspection of susceptible locations will

be performed to confirm the effectiveness of the Water Chemistry Control Program. For

general corrosion, the one-time inspections will monitor wall thickness and the examination

methods will include visual (VT-3) and/or volumetric (RT/UT). For pitting and crevice corrosion,

these one-time inspections will monitor wall thickness and the examination methods will include

visual (VT-1) and/or volumetric (RT/UT). Visual inspections will be performed only when the

components are drained or opened and the component surface of interest is accessible. If

degradation is identified through a visual inspection, additional NDE may be performed to

characterize the degradation and determine the extent of condition. The applicant stated that

the NDE exams will be performed as a part of the One-Time Inspection Program and will be

conducted in accordance with the requirements of ASME Code Section Xl and 10 CFR Part 50,

Appendix B.

The staff reviewed the applicant's Water Chemistry Control Program and One-Time Inspection

Program, and its evaluations are documented in SER Sections 3.0.3.2.20 and 3.0.3.2.13,

respectively.

The staff found that, based on the programs identified above, the applicant has met the criteria

of SRP-LR Section 3.2.2.2.3 for further evaluation. For those line items that apply to LRA

Section 3.2.2.2.3, the staff found that the applicant is consistent with the GALL Report and has

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demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained during the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.2.2.2.4 Local Loss of Material Due to Microbiologically Influenced Corrosion

The staff reviewed LRA Section 3.2.2.2.4 against the criteria in SRP-LR Section 3.2.2.2.4.

In the LRA Section 3.2.2.2.4, the applicant addresses local loss of material due to MIC.

SRP-LR Section 3.2.2.2.4 states that local loss of material due to MIC could occur in

containment isolation valves and associated piping in systems that are not addressed in other

chapters of the GALL Report. The GALL Report recommends further evaluation to ensure that

the aging effect is adequately managed.

In LRA Section 3.2.2.2.4, the applicant stated that although PBNP has components in the ESF

that are subject to MIC, this line item was not used. The applicant stated that this internal

environment is addressed in LRA Section 3.2.1, Item 3.2.1-05 for loss of material due to pitting

and crevice corrosion, because detection and prevention of these aging effects/mechanisms

would also detect and prevent MIC. In these cases, the LRA credited the Water Chemistry

Control Program and the One-Time Inspection Program.

In its letter, dated July 12, 2004, the applicant stated that for MIC one-time inspections, the

parameter monitored will be wall thickness and the examination methods will include visual

(VT-3) and/or volumetric (RT/UT). Visual inspections will be performed only when the

components are drained or opened and the component surface of interest is accessible. If

degradation is identified through a visual inspection, additional NDE may be performed to

characterize the degradation and determine the extent of condition.

The staff reviewed the applicant's Water Chemistry Control Program and One-Time Inspection

Program, and its evaluation is documented in SER Sections 3.0.3.2.20 and 3.0.3.2.13,

respectively.

The staff found that, based on the programs identified above, the applicant has met the criteria

of SRP-LR Section 3.2.2.2.4 for further evaluation. For those line items that apply to LRA

Section 3.2.2.2.4, the staff found that the applicant is consistent with the GALL Report and has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained during the period of extended operation, as required by

10 CFR 54.21(a)(3).

3.2.2.2.5 Changes in Material Properties Due to Elastomer Degradation

The staff reviewed LRA Section 3.2.2.2.5 against the criteria in SRP-LR Section 3.2.2.2.5.

In LRA Section 3.2.2.2.5, the applicant stated that this aging effect applies to BWRs only.

SRP-LR Section 3.2.2.2.5 states that the changes in properties due to elastomer degradation

could occur in seals associated with the standby gas treatment system ductwork and filters.

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SRP-LR Table 3.2-1 states that the further evaluation for this aging effect in the standby gas

treatment system seals is applicable to BWR plants only.

The staff found that this aging effect is not applicable to PBNP.

3.2.2.2.6 Local Loss of Material Due to Erosion

The staff reviewed LRA Section 3.2.2.2.6 against the criteria in SRP-LR Section 3.2.2.2.6.

In LRA Section 3.2.2.2.6, the applicant addressed local loss of material due to erosion that

could occur in the high-pressure safety injection pump miniflow orifice.

SRP-LR Section 3.2.2.2.6 states that local loss of material due to erosion could occur in the

high-pressure safety injection pump miniflow orifice. This aging mechanism and its effect

applies only to pumps that are normally used as charging pumps in the chemical and volume

control systems. The GALL Report recommends further evaluation to ensure that the aging

effect is adequately managed consistent with the acceptance criteria as described in Branch

Technical Position RSLB 1 (NUREG-1 800, Appendix A.1).

LRA Table 3.2.1, Item 3.2.1-08 stated that this further recommended evaluation is not

applicable at PBNP as safety injection pumps are not normally in use. Therefore, the applicant

stated, in LRA Section 3.2.2.2.6, that loss of material due to erosion of miniflow orifices is not

applicable to the facility.

As documented in the audit and review report, the applicant was asked to discuss its evaluation

of erosion susceptibility in the residual heat removal pump miniflow orifice lines that justify

either the absence of erosion or the aging management programs that will be relied on to

manage the aging mechanism. In its letter dated July 12, 2004, the applicant stated that a

review of the potential for loss of material due to cavitation has been completed and had

concluded that erosion-cavitation could not be ruled out. The applicant stated that, as part of

the 2005 annual LRA update, the downstream piping in the vicinity of the low head safety

injection (residual heat removal) pump mini-flow orifices will be examined under the One-Time

Inspection Program. The staff found that loss of material due to cavitation may not exist at

PBNP; however, the implementation of the One-Time Inspection Program will validate whether

the aging effect exists or not. The staff found this acceptable.

The staff found that, based on a review of the July 12, 2004 letter, the applicant has met the

criteria of SRP-LR Section 3.2.2.2.6 for further evaluation. For those line items that apply to

LRA Section 3.2.2.2.6, the staff found that the applicant is consistent with the GALL Report and

has demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained during the period of extended operation, as required by

10 CFR 54.21 (a)(3).

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3.2.2.2.7 Buildup of Deposits Due to Corrosion

The staff reviewed LRA Section 3.2.2.2.7 against the criteria in SRP-LR Section 3.2.2.2.7.

In LRA Section 3.2.2.2.7, the applicant stated that this aging effect applies to BWRs only.

SRP-LR Section 3.2.2.2.7 states that the plugging of components due to general corrosion

could occur in the spray nozzles and flow orifices of the drywell and suppression chamber spray

system of BWRs.

The staff found that this aging effect is not applicable.

3.2.2.2.8 Quality Assurance for Aging Management of Non-Safety-Related Components

SER Section 3.0.4 provides the staff's evaluation of the applicant's quality assurance program.

Conclusion. On the basis of its review, for component groups evaluated in the GALL Report for

which the applicant claimed consistency with the GALL Report, and for which the GALL Report

recommends further evaluation, the staff determined that (1) those attributes or features for

which the applicant claimed consistency with the GALL Report were indeed consistent and (2)

the applicant had adequately addressed the issues that were further evaluated. The staff found

that the applicant had demonstrated that the effects of aging will be adequately managed so

that the intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

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

Summary of Technical Information in the Application. In LRA Tables 3.2.2-1 through 3.2.2-4

the applicant provided additional details of the results of the AMRs for material, environment,

aging effects requiring management, and AMP combinations that are not consistent with the

GALL Report or are not addressed in the GALL Report.

As documented under RAI 2.1-1 in SER Section 2.1, by letter dated April 29, 2005, the

applicant changed the methodology used to determine the nonsafety-related SCs that are

within the scope of license renewal in accordance with the requirements of .10 CFR 54.4(a)(2).

As a result of the implementation of the scoping methodology changes, the applicant identified

changes to LRA Tables 3.2.2-1 and 3.2.2-2.

In LRA Tables 3.2.2-1 through 3.2.2-4, the applicant indicated, via Notes F through J, that

neither the identified component nor the material and environment combination is evaluated in

the GALL Report, and it provided information concerning how the aging -effect will be managed.

Staff Evaluation. For component type, material, and environment combinations that are not

evaluated in the GALL Report, the staff reviewed the applicant's evaluation to determine

whether the applicant had demonstrated that the effects of aging will be adequately managed

so that the intended function will be maintained consistent with the CLB during the period of

extended operation.

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3.2.2.3.1 Engineered Safety Features Components That Have No Aging Effect - Tables 3.2.2-1

through 3.2.2-4

The applicant stated that there are no aging effects identified for several of the line items in

LRA Table 3.2.2-1 through Table 3.2.2-4 for the following material and environment

combinations: (1) carbon steel, low-alloy steel, stainless steel, and cast stainless steel

component internal surfaces in contact with an air (defined as dehumidified atmospheric air,

dry/filtered instrument air) and gas environment; (2) stainless steel, glass, and cast stainless

steel component external surfaces exposed to an indoor air environment with no air

conditioning; and (3) stainless steel, and cast stainless steel component external surfaces

exposed to a containment air environment. The applicant described the above environment

groups in LRA Tables 3.0-1 and 3.0-2.

In LRA Table 3.0-1, the applicant stated that component internal surfaces in an air and gas

environment may be exposed to dehumidified atmospheric air, dry/filtered instrument air and

nitrogen, hydrogen, helium, or halon inert gases. The staff considers this air and gas

environment benign and that its contact with the carbon steel, low-alloy steel, stainless steel,

and cast stainless steel surfaces will not result in aging effects in those components identified in

LRA Table 3.2.2-1 through 3.2.2-4.

In LRA Table 3.0-2, the applicant described the indoor air environment with no air conditioning

as moist air at an average temperature of 85 IF and maximum relative humidity of 100 percent.

The external surfaces are not directly exposed to weather, and the environment may be

climate-controlled (heating and/or cooling), which may not prevent local condensation. The

staff found that the stainless steel and cast stainless steel surfaces in contact with this indoor

air environment will not result in aging effects in those components identified in LRA

Tables 3.2.2-1 through 3.2.2-4.

In LRA Table 3.0-2, the applicant also stated that the containment air temperature in generally

accessible areas is 50 OF to 105 OF and can be as high as 135 0F to 150 'F in some specific

locations. The maximum relative humidity could reach 100 percent. The applicant stated that

the nominal 40-year radiation dose is estimated to be 5.8E+7 rads. The staff found that, for

those components identified in LRA Tables 3.2.2-1 through 3.2.2-4, stainless steel, glass, and

cast stainless steel component external surfaces in contact with the containment environment

will not result in any significant aging effects. Because the stainless steel and cast stainless

steel components are not subjected to high fast neutron flux, irradiation embrittlement for these

components is not a concem. Ionization due to gamma rays or to beta and alpha particle

radiation has little effect on metals. Also, because the containment temperatures are low,

thermal aging embrittlement of cast stainless steel components is not applicable.

On the basis of its review of current industry research and operating experience, the staff found

that dry air on metal will not result in aging that will be of concern during the period of extended

operation. Stainless steel and nickel-based alloy components in air or an inert gas environment

are not susceptible to general corrosion that would affect their intended function. Therefore,

the staff concluded that there are no applicable aging effects requiring management for carbon

steel, stainless steel or stainless steel clad components exposed to air, or to an inert gas

environment.

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3.2.2.3.2 Safety Injection System - Aging Management Evaluation - Table 3.2.2-1

The staff reviewed LRA Table 3.2.2-1, as modified by letter dated April 29, 2005, which

summarizes the results of AMR evaluations for the safety injection system component groups.

The safety injection system experiences loss of material of carbon and low-alloy steel, cast iron,

stainless steel, and CASS for the following component types:

* level gauges * pump casings

* heat exchanger * restricting orifices

* instrument valve assemblies * tanks

* level elements * valve bodies

* piping and fittings * flow elements

For those components requiring staff review, the environments are listed below:

* borated water leaks (external)

* containment (extemal)

* treated water - borated (T<140 F)(internal)

* indoor - no air conditioning (external)

* treated water - other (stagnant)(intemal)

* treated water - borated (T>140 0F)(internal)

* air and gas (internal)

The applicant proposed to manage the safety injection system components loss of material

aging effects by using the Bolting Integrity Program, Boric Acid Corrosion Program,

Closed-Cycle Cooling Water System Surveillance Program, One-Time Inspection Program,

Systems Monitoring Program and Water Chemistry Control Program. The staff's evaluations of

these programs are documented in SER Sections 3.0.3.2.4, 3.0.3.2.6, 3.0.3.2.9, 3.0.3.2.13,

3.0.3.3.2, and 3.0.3.2.20, respectively.

The staff's review of LRA Section 3.2 identified areas in which additional information was

necessary to complete the review of the applicant's results. The applicant responded to the

staff's RAls as discussed below.

RAI 3.2-1. In LRA Tables 3.2.2-1, 3.2.2!2, and 3.2.2-3, stainless steel heat exchangers with

heat transfer as the intended function are identified with only internal environments and

associated aging effects. The external environment is listed as "not applicable." In RAI 3.2-1,

dated July 30, 2004, the staff requested the applicant to explain why no external environments

and associated aging effects are identified. The staff also requested the applicant to address

the similar issue for the stainless steel heat exchangers in LRA Tables 3.2.2-1 and 3.2.2-2,

which have pressure boundary as their intended function.

In its response, dated August 30, 2004, the applicant stated that, due to the way the license

renewal database was developed and used, tubing assets were identified as two separate

components (tubing ID and tubing OD). This allowed the user to designate an internal

environment for each (tubing ID and tubing OD), but since the database required each

component to have both an internal and external environment, the external environment would

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then be documented as "N/A." The applicant notes that in LRA Tables 3.2.2-1, 3.2.2-2, and

3.2.2-3, there is a heat exchanger material type with two different internal environments, which

is reflective of the environments for the ID and OD of the tubing. Because the tubing has a

pressure boundary intended function in addition to the heat transfer function, the same

information was duplicated for the pressure boundary intended function line items.

The applicant stated that the only components that have a heat transfer intended function are

the tubes. The heat exchanger shell has as its only intended function pressure boundary.

External environments (indoor - no air conditioning, outdoor, etc.) would, therefore, only apply

to the shell. Additionally, the shell is typically made of a different material than the tubes and,

therefore, would not be represented by the same line item as the tubing in the LRA.

The staff considers the applicant's response to be adequate in explaining the relationship

among components, material, and environments listed in the above tables. The staff's concern

described in RAI 3.2-1 is resolved and the response is, therefore, acceptable.

RAI 3.2-2. In LRA Tables 3.2.2-1 and 3.2.2-2, carbon/low-alloy steel tanks are identified with

only external environments and the associated aging effect. The internal environment is listed

as "not applicable." On the other hand, stainless steel tanks are identified with internal

environments and associated aging effects. In RAI 3.2-2, dated July 30, 2004, the staff

requested the applicant to explain what material of construction for the tank is used, and the

environments to which it is exposed, to support the information provided in the above tables.

In its response, dated August 30, 2004, the applicant stated that the issue was identified due to

having carbon/low-alloy steel tanks that are clad with stainless steel. Due to the design of the

license renewal database, each component can only have one material. However, there are

two separate assets to describe the tanks. One asset would be the carbon/low-alloy steel shell,

which is subject to an external environment, with internal environment being UN/A." Similarly,

the stainless steel cladding has an internal environment, but the external environment is "N/A."

The staff considers the applicant's response to be adequate in explaining the relationship

between the materials of construction and the associated environments for the tanks. The

staff's concern described in RAI 3.2-2 is resolved and the response is, therefore, acceptable.

On the basis of its review of the applicant's plant-specific and industry operating experience,

and the above discussion, the staff found that loss of material of carbon and low-alloy steel,

cast iron, stainless steel, and CASS materials for component types in the safety injection

system are effectively managed using the Bolting Integrity Program, Boric Acid Corrosion

Program, Closed-Cycle Cooling Water System Surveillance Program, One-Time Inspection

Program, Systems Monitoring Program and Water Chemistry Control Program. On this basis,

the staff found that management of loss of material in the safety injection system components

using these programs is acceptable.

The applicant proposed to manage loss of heat transfer due to fouling of stainless steel in heat

exchangers exposed to treated water - borated (T<140 OF)(intemal), and treated water - other

(stagnant)(intemal) using the Closed-Cycle Cooling Water System Surveillance Program,

One-Time Inspection Program, and Water Chemistry Control Program.

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The staff reviewed the applicant's Closed-Cycle Cooling Water System Surveillance Program,

One-Time Inspection Program, and Water Chemistry Control Program. The staff's evaluations

of these programs are documented in SER Sections 3.0.3.2.9, 3.0.3.2.13, and 3.0.3.2.20,

respectively.

On the basis of its review of the applicant's plant-specific and industry operating experience, the

staff found that loss of heat transfer of stainless steel material for component types in the safety

injection system is effectively managed using the Closed-Cycle Cooling Water System

Surveillance Program, One-Time Inspection Program, and Water Chemistry Control Program.

Therefore, the staff found that management of loss of heat transfer in the safety injection

system components using these programs is acceptable.

3.2.2.3.3 Containment Spray - Aging Management Evaluation - Table 3.2.2-2

The staff reviewed LRA Table 3.2.2-2, as modified by letter dated April 29, 2005, which

summarized the results of AMR evaluations for the containment spray system component

groups.

The containment spray system experiences loss of material of carbon and low-alloy steel,

stainless steel, cast iron and CASS materials for the following component types:

* eductor * pump casings

* flow elements * restricting orifices

* heat exchangers * tanks

* instrument valve assemblies * valve bodies

* piping and fittings * level gauges

For those components requiring staff review, the environments are listed below:

* treated water - borated (T<140 F)(internal)

* indoor - no air conditioning (external)

* treated water - other (stagnant)(intemal)

* containment (extemal)

* borated water leaks (external)

The applicant proposed to manage the containment spray system components' loss of material

aging effects by using the Bolting Integrity Program, Boric Acid Corrosion Program,

Closed-Cycle Cooling Water System Surveillance Program, One-Time Inspection Program,

Systems Monitoring Program and Water Chemistry Control Program. The staff's evaluations of

these programs are documented in SER Sections 3.0.3.2.4, 3.0.3.2.6, 3.0,3.2.9,3.0.3.2.13,

3.0.3.3.2, and 3.0.3.2.20, respectively. :'i

On the basis of its review of the applicant's plant-specific and Industry oporating expriehce, ;the

staff found that loss of material of carbon and low-alloy steel, stainless steel, cast Iron and :

CASS materials for component types in the containment spray syrtem components are

effectively managed using the Bolting Integrity Program, Boric A6id Corrosion Program,

Closed-Cycle Cooling Water System Surveillance Program, One-Time Inspection Program,

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Systems Monitoring Program and Water Chemistry Control Program. Therefore, the staff

found that management of loss of material in the containment spray system components using

these programs is acceptable.

The applicant proposed to manage loss of heat transfer due to fouling of stainless steel

material for heat exchangers in the containment spray system exposed to treated water -

borated (T<1 40 0F)(intemal) and stagnant treated water using the Closed-Cycle Cooling Water

System Surveillance Program, One-Time Inspection Program, and the Water Chemistry Control

Program.

The staff reviewed the applicant's Closed-Cycle Cooling Water System Surveillance Program,

One-time Inspection Program and Water Chemistry Control Program. The staff's evaluations of

these programs is documented in SER Sections 3.0.3.2.9, 3.0.3.2.13, and 3.0.3.2.20,

respectively.

On the basis of its review of the applicant's plant-specific and industry operating experience, the

staff found that loss of heat transfer of stainless steel for component types in the containment

spray system components is effectively managed using the Closed-Cycle Cooling Water

System Surveillance Program, One-Time Inspection Program and Water Chemistry Control

Program. Therefore, the staff found that management of heat transfer in the containment spray

system components using these programs is acceptable.

3.2.2.3.4 Residual Heat Removal - Aging Management Evaluation - Table 3.2.2-3

The staff reviewed LRA Table 3.2.2-3, which summarized the results of AMR evaluations for the

residual heat removal system component groups.

The residual heat removal system experiences loss of material of carbon and low-alloy steel,

stainless steel, cast iron, and CASS for the following component types:

* filters and strainers * restricting orifices

* flow elements * sump screens

* heat exchangers * tanks

* instrument valve assemblies * thermowells

* piping and fittings * valve bodies

* pump casings * valve operator

For those components requiring staff review, the environments are listed below:

* borated water leaks (external)

* containment (external)

* treated water - borated (T<1 40 0F)(internal)

* indoor - no air conditioning (external)

* treated water - other (stagnant)(intemal)

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* treated water - borated (T>1 40 OF)

* air and gas - wetted (T<1 40 OF)(intemal)

* oil and fuel oil (internal)

The applicant proposed to manage the residual heat removal system components' loss of

material aging effects by using the Bolting Integrity Program, Boric Acid Corrosion Program,

One-Time Inspection Program, Periodic Surveillance and Preventive Maintenance Program,

Systems Monitoring Program, Closed-Cycle Cooling Water System Surveillance Program, and

Water Chemistry Control Program. The staff's evaluations of these programs are documented

in SER Sections 3.0.3.2.4, 3.0.3.2.6, 3.0.3.2.13, 3.0.3.3.1, 3.0.3.3.2, 3.0.3.2.9, and 3.0.3.2.20,

respectively.

On the basis of its review of the applicant's plant-specific and industry operating experience, the

staff found that loss of material of carbon and low-alloy steel, stainless steel, cast iron, and

CASS for component types in the residual heat removal system is effectively managed using

the Bolting Integrity Program, Boric Acid Corrosion Program, One-Time Inspection Program,

Periodic Surveillance and Preventive Maintenance Program, Systems Monitoring Program,

Closed-Cycle Cooling Water System Surveillance Program, and Water Chemistry Control

Program. Therefore, the staff found that management of loss of material in the residual heat

removal system components using these programs is acceptable.

The applicant proposed to manage loss of heat transfer due to fouling of stainless steel

material for heat exchangers in the residual heat removal system exposed to borated treated

(T<140 F)(intemal) and stagnant treated water using the Closed-Cycle Cooling Water System

Surveillance Program, One-Time Inspection Program, and Water Chemistry Control Program.

Also, the applicant proposed to manage cracking in stainless steel component types of piping

and fittings by using the One-Time Inspection Program and Water Chemistry Control Program.

The staff reviewed the applicant's Closed-Cycle Cooling Water System Surveillance Program,

One-Time Inspection Program and Water Chemistry Control Program. The staff's evaluations

of these programs are addressed in SER Sections 3.0.3.2.9, 3.0.3.2.13, and 3.0.3.2.20,

respectively.

On the basis of its review of the applicant's plant-specific and industry operating experience, the

staff found that loss of heat transfer and cracking of stainless steel for component types in the

residual heat removal system components are effectively managed using the Closed-Cycle

Cooling Water System Surveillance Program, One-Time Inspection Program and Water

Chemistry Control Program. Therefore, the staff found that management of heat transfer in the

residual heat removal system components using these programs is acceptable.

3.2.2.3.5 Containment Isolation Components System - Aging Management Evaluation -

Table 3.2.2-4

The staff reviewed LRA Table 3.2.2-4, which summarized the results of AMR evaluations for the

containment isolation components system.

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The containment isolation components system experiences loss of material of carbon and

low-alloy steel, stainless steel, and CASS for the following component types:

* CS components

* fasteners and bolting

* piping and fittings

* valve bodies

For those components requiring staff review, the environments are listed below:

* borated water leaks (external)

* containment (external)

* indoor - no air conditioning (external)

* treated water - other (stagnant)(intemal)

The applicant proposed to manage containment isolation components system components

aging effects by using the Bolting Integrity Program, Boric Acid Corrosion Program, One-Time

Inspection Program, Systems Monitoring Program and Water Chemistry Control Program. The

staff's evaluation of these programs is documented in SER Sections 3.0.3.2.4, 3.0.3.2.6,

3.0.3.2.13, 3.0.3.3.2, and 3.0.3.2.20, respectively.

On the basis of its review of the applicant's plant-specific and industry operating experience, the

staff found that loss of material of carbon and low-alloy steel, stainless steel, and CASS

materials for component types in the containment isolation components system is effectively

managed using the Bolting Integrity Program, Boric Acid Corrosion Program, One-Time

Inspection Program, Systems Monitoring Program and Water Chemistry Control Program.

Therefore, the staff found that management of loss of material in the containment isolation

components system using these programs is acceptable.

All AMRs in LRA Tables 3.2.2-1 through 3.2.2-4 were evaluated. The staff found them to be

acceptable.

Conclusion. On the basis of its review, the staff found that the applicant had appropriately

evaluated AMR results involving material, environment, aging effect requiring management, and

AMP combinations that are not evaluated in the GALL Report. The staff found that the

applicant had demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.2.3 Conclusion

On the basis of its review, the staff concluded that the applicant has demonstrated that the

aging effects associated with the engineered safety features components will be adequately

managed so that the intended functions will be maintained for the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

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The staff also reviewed the applicable FSAR supplement program summaries and concluded

that they adequately describe the AMPs credited for managing aging of the ESF as required by

10 CFR 54.21(d).

3.3 Aging Management of Auxiliary Systems

This section of the SER documents the staff's review of the applicant's AMR results for the

auxiliary systems components and component groups associated with the following systems:

* chemical and volume control system * essential ventilation system

* component cooling water system * treated water system

* spent fuel cooling system * circulating water system

* waste disposal system * fuel handling system

* service water system * plant sampling system

* fire protection system * plant air system

* heating steam system * containment hydrogen detectors and

* emergency power system recombiner system

* containment ventilation system

3.3.1 Summary of Technical Information In the Application

In LRA Section 3.3, the applicant provided AMR results for auxiliary systems components and

component groups. In LRA Table 3.3.1, "Summary of Aging Management Evaluations in

Chapter Vil of NUREG-1801 for Auxiliary Systems," the applicant provided a summary

comparison of its AMRs with the AMRs evaluated in the GALL Report for the auxiliary systems

components and component groups.

The applicant's AMRs incorporated applicable operating experience in the determination of

AERM. 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 AERM. The applicant's review of industry operating

experience included a review of the GALL Report and operating experience issues identified

since the issuance of the GALL Report.

3.3.2 Staff Evaluation

The staff reviewed LRA Section 3.3 to determine if the applicant had provided sufficient

information to demonstrate that the effects of aging for the auxiliary system components that

are within the scope of license renewal and subject to an AMR will be'ad quately managed so

that the intended functions will be maintained consistent with the CL te period f extended

operation, as required by 10 CFR 54.21 (a)(3).,

Also, the staff performed an onsite audit to confirm the applicant's claim that certain Identified

AMRs are consistent with the GALL Report. ,he ,staff did not re l;ewsiofthe matters

described in the GALL Report. However, the staff did verify that the Iaterial jresnted in the

LRA was applicable and that the applicant had identified the appropriate CALL AMPs' The

staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff's

3-195
audit evaluations are documented in the staff's PBNP audit and review report and summarized

in SER Section 3.3.2.1.

The staff also performed an onsite audit of those AMRs that are consistent with the GALL

Report and for which further evaluation is recommended. The staff verified that the applicant's

further evaluations were consistent with the acceptance criteria in NUREG-1 800

Section 3.3.2.2, "Standard Review Plan for Review of License Renewal Applications for Nuclear

Power Plants," dated July 2001. The staff's audit evaluations are documented in the staff's

PBNP audit and review report and summarized in SER Section 3.3.2.2.

The staff performed an onsite audit and conducted a technical review of the remaining AMRs

that were not consistent with or not addressed in the GALL Report. The audit and technical

review included evaluating whether all plausible aging effects had been identified and whether

the aging effects listed were appropriate for the combination of materials and environments

specified. The staff's audit evaluations are documented in the staff's PBNP audit and review

report and summarized in SER Section 3.3.2.3. The staff's evaluation of its technical review is

also documented in SER Section 3.3.2.3.

Finally, the staff reviewed the AMP summary descriptions in the FSAR supplement to ensure

that they provide an adequate description of the programs credited with managing or monitoring

aging for the auxiliary system components.

Table 3.3-1 below provides a summary of the staff's evaluation of components, aging

effects/mechanisms, and AMPs listed in LRA Section 3.3 that are addressed in the GALL

Report.

Table 3.3-1 Staff Evaluation for Auxiliary System Components In the GALL Report

-Component Group Aging Effectl AMPIn. GALLe. AMP fin LR. Sitaf Evlatio - Mecis Aept ___-_E______-__

Components in Loss of material Water chemistry Water Chemistry Consistent with

spent fuel pool due to general, and one-time Control Program; GALL, which

cooling and cleanup pitting, and crevice inspection One-Time Inspection recommends further

(Item Number corrosion Program evaluation. (See 3.3.1-01) Section 3.322.1)

Unings in spent fuel Hardening, cracking Plant-specific Periodic Surveillance Consistent with

pool cooling and and loss of strength and Preventive GALL, which

cleanup system; due to elastomer Maintenance recommends further

seals and collars in degradation; loss of Program evaluation. (See ventilation systems material due to Section 3.3.2.2.2) (Item Number wear

3.3.1-02)

Components in load Cumulative fatigue TLAA, evaluated TLAA This TLAA Is

handling, chemical damage in accordance with evaluated in

and volume control 10 CFR 54.21(c) Section 4.3, Metal

system Fatigue (See (Item Number Section 3-3.2.2.3)

3.3.1-03)

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CopoentGrup Aging'AMeP MP n GALL PInLRA I Staff Evaluation:

M echanism ieot _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

High-pressure Crack initiation and Plant-specific Water Chemistry Consistent with

pumps in chemical growth due to SCC Control Program; GALL, which

and volume control or cracking One-Time Inspection recommends further

system Program evaluation. (See

(Item Number Section 3.3.2.2.4)

3.3.1-04)

Components In Loss of material Plant-specific Periodic Surveillance Consistent with

ventilation system, due to general, and Preventive GALL, which

diesel fuel oil pitting, and crevice Maintenance recommends further

system, and corrosion, and MIC Program; evaluation. (See

emergency diesel Open-Cycle Cooling Section 3.3.2.2.5)

generator systems; (Service) Water

external surfaces of System Surveillance

carbon steel Program; One-Time

components Inspection Program;

(Item Number Fire Protection

3.3.1-05) Program; Tank

Internal Inspection

Program; Systems

Monitoring Program

Components in Loss of material One-time One-Time Inspection Consistent with

reactor coolant due to galvanic, inspection Program GALL, which

pump oil collection general, pitting, and recommends further

system of fire crevice corrosion evaluation. (See

protection Section 3.3.2.2.6)

(Item Number

3.3.1-06)

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 One-Time Inspection recommends further

emergency diesel corrosion, MIC, and Program evaluation. (See

generator system blofouling Section 3.3.2.2.7)

(Item Number

3.3.1-07) -

Heat exchangers In Crack initiation and Water chemistry Water Chemistry Consistent with

chemical and growth due to SCC and a Control Program; GALL, which

volume control and cyclic loading plant-specific Closed Cycle Cooling recommends further

system verification Water System evaluation. (See

(Item Number program Surveillance Section 3.3.2.2.9)

3.3.1-09) 'Program; One-Time

Inspection Program

Neutron-absorbing Reduction of Plant-specific Not Applicable I Not Applicable (See

sheets In spent fuel neutron absorbing Section 3.3.2.2.10)

storage racks capacity and loss of

(Item Number material due to

3.3.1-10) general corrosion

(Boral, boron steel)

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Component Gru Agilng~ ffect/! ~,,~~ AJVIPMn GALL: AMP]In LRA~ ~ S~~taff Evaluation'

l M echanism Report - ___l___________ _____E_________

New fuel rack Loss of material Structures Structures Monitoring Consistent with

assembly due to general, monitoring Program GALL, which

(Item Number pitting, and crevice recommends no

3.3.1-11) corrosion further evaluation.

(See

Section 3.3.2.1)

Neutron-absorbing Reduction of Boraflex Boraflex Monitoring Consistent with

sheets in spent fuel neutron absorbing monitoring Program GALL, which

storage racks capacity due to recommends no

(Item Number Boraflex further evaluation.

3.3.1-12) degradation (See

Section 3.3.2.1)

Spent fuel storage Crack initiation and Water chemistry Water Chemistry Consistent with

racks and valves in growth due to stress Control Program; GALL, which

spent fuel pool corrosion cracking One-Time Inspection recommends no

cooling and cleanup Program further evaluation.

(Item Number (See

3.3.1-13) Section 3.3.2.1)

Closure bolting and Loss of material Boric acid Boric Acid Corrosion Consistent with

external surfaces of due to boric acid corrosion Program GALL, which

carbon steel and corrosion recommends no

low-alloy steel further evaluation.

components (See

(Item Number Section 3.3.2.1)

3.3.1-14)

Components in or Loss of material Closed-cycle Closed-Cycle Cooling Consistent with

serviced by closed due to general, cooling water Water System GALL, which

cycle cooling waster pitting, and crevice system Surveillance recommends no

system corrosion, and MIC Program; One-Time further evaluation.

(Item Number Inspection Program (See

3.3.1-15) Section 3.3.2.1)

Cranes including Loss of material Overhead heavy Structures Monitoring Consistent with

bridge and trolleys due to general load and light load Program; TLAA GALL, which

and rail system in corrosion and wear handling systems recommends no

load-handling further evaluation.

system (See (Item Number Section 3.3.2.1) 3.3.1-16)

Components in or Loss of material Open-cycle Open-Cycle Cooling Consistent with

serviced by open due to general, cooling water (Service) Water GALL, which

cycle cooling water pitting, crevice, and system System Surveillance recommends no

systems galvanic corrosion, Program; Periodic further evaluation.

(Item Number MIC, and biofouling; Surveillance and (See 3.3.1-17) buildup of deposit Preventive Section 3.3.2.1)

due to biofouling Maintenance

Program; One-Time

Inspection Program; Closed-Cycle Cooling Water System

Surveillance Program

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ponlent Group Aging Effect! AMlP:In GALL AMPILn LA1 ,staffoEaluation

Mechanism EitReport __ ________________

Buried piping and Loss of material Buried piping and Buried Services Consistent with

fittings due to general, tanks surveillance Monitoring Program GALL, which

(Item Number pitting, and crevice or Buried piping recommends further

3.3.1-18) corrosion, and MIC and tanks evaluation. (See

inspection Section 3.3.2.2.11)

Components in Loss of material Compressed air Periodic Surveillance Consistent with

compressed air due to general and monitoring and Preventive GALL, which

system pitting corrosion Maintenance recommends no

(Item Number Program further evaluation.

3.3.1-19) (See

Section 3.3.2.1)

Components (doors Loss of material Fire protection Fire Protection Consistent with

and barrier due to wear; Program GALL, which

penetration seals) hardening and recommends no

and concrete - shrinkage due to further evaluation.

structures in fire weathering (See

protection Section 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 GALL, which

protection pitting, crevice, and recommends no

(Item Number galvanic corrosion, further evaluation.

3.3.1-21) MIC, and biofouling (See

Section 3.3.2.1)

Components In Loss of material Fire protection Fuel Oil Chemistry Consistent with

diesel fire system due to galvanic, and fuel oil Control Program; Fire GALL, which

(Item Number general, pitting, and chemistry Protection Program recommends no

3.3.1-22) crevice corrosion further evaluation.

(See

e_ Section 3.3.2.1)

Tanks in diesel fuel Loss of material Above-ground Systems Monitoring Consistent with

oil system due to general, carbon steel tanks Program GALL, which

(Item Number pitting, and crevice recommends no

3.3.1-23) corrosion further evaluation.

(See.

Section 3.3.2.1)

Closure bolting Loss of material Bolting integrity Bolting Integrity Consistent with

(Item Number due to general Program GALL, which

3.3.1-24) corrosion; crack recommends no

initiation and growth further evaluation.

due to cyclic (See

loading and SCC Section 3.3.2.1)

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mPnent oup Aging Ee/ APin GALL 0X;AMP In j -t.RA Staff Evaluation

_____________._A: S _~ f M echanism •R> E port _____ ____ ____ . _____ 

Components Loss of material Selective leaching Open-Cycle Cooling Consistent with

(aluminum bronze, due to selective of materials (Service) Water GALL, which

brass, cast iron, leaching System Surveillance recommends no

cast steel) in open Program; further evaluation.

cycle cooling water Closed-Cycle Cooling (See

and closed cycle Water System Section 3.3.2.1)

cooling water Surveillance

systems, and Program; One-Time

ultimate heat sink Inspection Program;

(Item Number Buried Services

3.3.1-29) Monitoring Program

Fire barriers, walls, Concrete cracking Fire protection Fire Protection Consistent with

ceilings, and floors and spalling due to and structures Program; Structures GALL, which

in fire protection freeze-thaw, monitoring Monitoring Program recommends no

(Item Number aggressive further evaluation.

3.3.1-30) chemical attack, (See

and reaction with Section 3.3.2.1)

aggregates; loss of

material due to

corrosion of

embedded steel

The staff's review of the PBNP auxiliary systems and associated components followed one of

several approaches. One approach, documented in SER Section 3.3.2.1, involves the staff's

review of the AMR results for components in the auxiliary systems that the applicant indicated

are consistent with the GALL Report and do not require further evaluation. Another approach,

documented in SER Section 3.3.2.2, involves the staff's review of the AMR results for

components in the auxiliary systems that the applicant indicated are consistent with the GALL

Report and for which further evaluation is recommended. A third approach, documented in

SER Section 3.3.2.3, involves the staff's review of the AMR results for components in the

auxiliary systems that the applicant indicated are not consistent with the GALL Report or are not

addressed in the GALL Report. The staff's review of AMPs that are credited to manage or

monitor aging effects of the auxiliary systems components is documented in SER Section 3.0.3.

3.3.2.1 AMR Results That Are Consistent with the GALL Report, for Which Further

Evaluation Is Not Recommended

Summary of Technical Information in the Apolication. In LRA Section 3.3.2.1 the applicant

identified the materials, environments, and aging effects requiring management. The applicant

identified the following programs that manage the aging effects related to the auxiliary systems

components:

0

0

S

0

0

Bolting Integrity Program

Boric Acid Corrosion Program

Closed-Cycle Cooling Water System Surveillance Program

One-Time Inspection Program

Systems Monitoring Program

Water Chemistry Control Program

Open-Cycle Cooling (Service) Water System Surveillance Program

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* Periodic Surveillance and Preventive Maintenance Program

* Buried Services Monitoring Program

* Fire Protection Program

* Fuel Oil Chemistry Control Program

* -Tank Internal Inspection Program

Staff Evaluation. In LRA Tables 3.3.2-1 through 3.3.2-16, the applicant provided a summary of

AMRs for chemical and volume control system, component cooling water system, spent fuel

cooling system, waste disposal system, service water system, fire protection system, heating

steam system, emergency power system, containment ventilation system, essential ventilation

system, treated water system, circulating water system, fuel handling system, plant sampling

system, plant air system, and containment hydrogen detectors and recombiner system, 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 plant-specific

components contained in these GALL Report component groups were bounded by the GALL

Report evaluation.

The applicant provided a note for each AMR line item. The notes described how the

information in the tables aligns with the information in the GALL Report. The staff's audit of

those AMRs with Notes A through E, indicated the AMR was consistent with the GALL Report.

Note A indicated that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the AMP

identified in the GALL Report. The staff audited these line items to verify consistency with the

GALL Report and the validity of the AMR for the site-specific conditions.

Note B indicated that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. -In addition, the AMP takes some exceptions to the

AMP identified in the GALL Report. The staff audited these line items to verify consistency with

the GALL Report. The staff verified that the identified exceptions to the GALL AMPs had been

reviewed and accepted by the staff. The staff also determined whether the AMP identified by the applicant was consistent with the AMP identified in the GALL Report and whether the AMR

was valid for the site-specific conditions.

Note C indicated that the component for the AMR line item, although different, is consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent

with the AMP identified by the GALL Report. This note indicates that the applicant was unable

to find a listing of some system components in the GALL Report. However, the applicant

identified a different component in the GALL Report that had the same material, environment,

aging effect, and AMP as the component that was under review. The staff audited these line

items to verify consistency with the GALL Report. The staff also determined whether the AMR

line item of the different component was applicable to the component under review and whether

the AMR was valid for the site-specific conditions.

Note D indicated that the component for the AMR line item, although different, is consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP takes some

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exceptions to the AMP identified in the GALL Report. The staff audited these line items to

verify consistency with the GALL Report. The staff verified whether the AMR line item of the

different component was applicable to the component under review. The staff verified whether

the identified exceptions to the GALL AMPs had been reviewed and accepted by the staff. The

staff also determined whether the AMP identified by the applicant was consistent with the AMP

identified in the GALL Report and whether the AMR was valid for the site-specific conditions.

Note E indicated that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but a different AMP is credited. The staff audited these line

items to verify consistency with the GALL Report. The staff also determined whether the

identified AMP would manage the aging effect consistent with the AMP identified by the GALL

Report and whether the AMR was valid for the site-specific conditions.

The staff conducted an audit and review of the information provided in the LRA, as documented

in its PBNP audit and review report. The staff did not repeat its review of the matters described

in the GALL Report. However, the staff did verify that the material presented in the LRA was

applicable and that the applicant identified the appropriate GALL Report AMRs.

The staff reviewed the LRA to confirm that the applicant had (1) provided a brief description of

the system, components, materials, and environment; (2) stated that the applicable aging

effects had been reviewed and are evaluated in the GALL Report; and (3) identified those aging

effects for the auxiliary systems components that are subject to an AMR. On the basis of its

audit and review, the staff determined that for AMRs not requiring further evaluation, as

identified in LRA Table 3.3.1 (Table 1), the applicant's references to the GALL Report are

acceptable and no further staff review is required.

Conclusion. The staff verified the applicant's claim of consistency with the GALL Report. The -

staff also reviewed information pertaining to the applicants consideration of recent operating

experience and proposals for managing associated aging effects. On the basis of its review,

the staff found that the AMR results that the applicant claimed to be consistent with the GALL

Report are consistent with the AMRs in the GALL Report. Therefore, the staff found that the

applicant had demonstrated that the effects of aging for these components will be adequately

managed so that their intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

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

Evaluation is Recommended

Summary of Technical Information in the Aoplication. In LRA Section 3.3.2.2, the applicant

provides 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

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* crack initiation and growth due to cracking or stress corrosion cracking

* loss of material due to general, microbiologically influenced, pitting, and crevice

corrosion

* loss of material due to general, galvanic, pitting, and crevice corrosion

* loss of material due to general, pitting, crevice, and microbiologically influenced

corrosion and biofouling

* -crack initiation and growth due to stress corrosion cracking and cyclic loading

* reduction of neutron-absorbing capacity and loss of material due to general corrosion

* loss of material due to general, pitting, crevice, and microbiologically influenced

corrosion.

Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant

claimed consistency with the GALL Report, and for which the GALL Report recommends further

evaluation, the staff reviewed the applicant's evaluation to determine whether it adequately

addressed the issues that were further evaluated. In addition, the staff reviewed the applicant's

further evaluations against the criteria in SRP-LR Section 3.3.3.2. Details of the staff's audit

and review are documented in the staff's PBNP audit and review report. The staff's evaluation

is discussed below.

3.3.2.2.1 Loss of Material due to General, Pitting, and Crevice Corrosion

The staff reviewed LRA Section 3.3.2.2.1 against the criteria in SRP-LR 3.3.2.2.1.

In LRA Section 3.3.2.2.1, the applicant addressed loss of material in components of the spent

fuel pool system.

SRP-LR Section 3.3.2.2.1 states that loss of material due to general, pitting, and crevice

corrosion could occur in the channel head and access cover, tubes, and tube sheets of the heat

exchanger in the spent fuel pool cooling and cleanup system. For these components, made of

carbon steel with elastomer lining, the GALL Report Table VII.A3 recommends managing the

aging effects with a combination of the GALL AMP XI.M2, "Water Chemistry," and GALL

AMP XI.M32, "One-Time Inspection."

The applicant stated that NUREG-1 801, Volume 2, items identified in Item 3.3.1-01 (A3.2-a,

A3.3-a, and A3.5-a) relate to carbon steel components with elastomer linings. The applicant's

spent fuel cooling system does not contain any carbon steel components with elastomer linings.

All of the components in the spent fuel cooling system are stainless steel. The applicant further

stated that, due to the absence of this material/environment combination in the auxiliary

systems section, the applicant used LRA Table 3.2.1, Item 3.2.1-15 (ESFS) toaddress aging

effects of these components. The Water Chemistry Control Programi is qredited with managing

these aging effects. The One-Time Inspection Program is also used to verify the effectiveness

of water chemistry control. .,, S .. S ' : i, -; 1.11411

The staff confirmed that these components are made of stainless steel and found that the

applicant need not implement the further evaluation as defined in SRO-LR Section 3.3.2.2.1.

The staff reviewed the applicant's Water Chemistry Control Program and One-time Inspection

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Program and its evaluation is documented in SER Sections 3.0.3.2.20 and 3.0.3.2.13,

respectively. Therefore, the staff found that the use of the Water Chemistry Control Program

and One-Time Inspection Program are appropriate programs to manage the loss of material

due to general, pitting, and crevice corrosion in the channel head and access cover, tubes, and

tube sheets of the heat exchanger in the spent fuel pool cooling and cleanup system.

The staff found that, based on the programs identified above, the applicant had appropriately

addressed the SRP-LR Section 3.3.2.2.1 further evaluation. For those line items that apply to

LRA Section 3.3.2.2.1, the staff found that the applicant is consistent with the GALL Report and

has demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained during the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.2.2 Hardening and Cracking or Loss of Strength due to Elastomer Degradation or Loss of

Material due to Wear

The staff reviewed LRA Section 3.3.2.2.2 against the criteria in SRP-LR Section 3.3.2.2.2.

In LRA Section 3.3.2.2.2, the applicant addressed the potential for degradation of elastomers in

collars and seals in spent fuel cooling systems and ventilation systems.

SRP-LR Section 3.3.2.2.2 states that hardening and cracking due to elastomer degradation

could occur in elastomer linings of the filter, valve, and ion exchangers in spent fuel pool cooling

and cleanup systems. Hardening and loss of strength due to elastomer degradation could

occur in the collars and seals of the duct and in the elastomer seals of the filters in the control

room area, auxiliary and radwaste area, and primary containment heating ventilation systems,

as well as 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.

The applicant stated that the spent fuel cooling system contains no components that are

elastomer lined; however, the elastomer seals for the spent fuel pool gates are included in the

LRA. The Periodic Surveillance and Preventive Maintenance Program is credited for managing

the hardening and cracking. For ventilation systems, the applicant also credited the Periodic

Surveillance and Preventive Maintenance Program for managing the hardening and cracking or

loss of strength aging effects, where applicable. In many cases, the temperature, radiation,

and ultraviolet exposure do not support these aging effects; therefore, no aging management is

required.

The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program

and its evaluation is documented in SER 3.0.3.3.1. On the basis of its review discussed in that

section, the staff found that this program is appropriate to manage the hardening and cracking

or loss of strength aging effects.

During the audit, the staff was concerned that many of the identified elastomer or nonmetallic

components, as stated in LRA Note 16, are in areas where the temperatures in the identified

environment may exceed the 95 OF threshold established by industry. In addition, the staff

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questioned the possibility of aging to occur to those neoprene components exposed to a raw

water environment, which is not addressed in NUREG-1801.

The applicant stated that no aging effects exist for this material in these environments and that

this is substantiated by plant-specific operating experience. LRA Note 16, for a particular

component, stated that elastomer components are indoors and not subject to ultraviolet light or

ozone, and they are not in locations that are subject to radiation exposure. These locations

also are not subject to temperatures greater than 95 OF where change in material properties or

cracking could occur; therefore, no aging management is required. Although LRA Table 3.0-2

stated that the indoor air, with no air conditioning, environment may achieve temperature

variations between 70 OF to 120 OF with 100 percent humidity, this is provided as a generic

environment, whereas LRA Note 16 is a specific environment for this material at a set location.

These components were evaluated individually for both an internal raw water and external plant

indoor, with no air conditioning, environment with regard to these criteria and, as a result, either

were managed due to the potential for applicable effects/mechanisms for these environments

or noted as not applicable where these criteria did not apply.

The staff reviewed the information provided by the applicant, as documented in its PBNP audit

and review report, the staff found that the applicant had completed an individual assessment for

each of the elastomer/nonmetallic components. All of these components in the auxiliary

systems are in environments where aging is not expected to occur; therefore, the staff agreed

that no AMP is required.

The staff found that, based on the program identified above, the applicant met the criteria of

SRP-LR Section 3.3.2.2.2 for further evaluation. For those line items that apply to LRA

Section 3.3.2.2.2, the staff found that the applicant is consistent with the GALL Report and has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained during the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.2.3 Cumulative Fatigue Damage

In LRA Section 3.3.2.2.3, the applicant stated that fatigue is a TLAA, as defined in

10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21 (c)(1). SER

Section 4.3 documents the staff's review of the applicant's evaluation of this TLAA.

3.3.2.2.4 Crack Initiation and Growth due to Cracking or Stress Corrosion Cracking

The staff reviewed LRA Section 3.3.2.2.4 against the criteria in SRP-LR Section 3.3.2.2.4.

In LRA Section 3.3.2.2.4, the applicant addressed the potential for cracking In the high-pressure

pumps of the chemical and volume control system.

SRP-LR Section 3.3.2.2.4 addresses crack initiation and growth due to cracking in the high

pressure pump for the chemical and volume control system. The GALL Report recommends

further evaluation to ensure that these aging effects are adequately managed.

The applicant stated that, although the GALL Report references a threshold temperature gate

of less than 90 OC (200 OF) and a single aging effect, materials science supports: (1) a

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threshold temperature gate of greater than 1400F for cracking due to SCC and (2) loss of

material due to pitting and crevice corrosion for all temperatures. The applicant further stated

that although the aging effect identified for temperatures less than 140 OF differs from that of the

GALL Report, the Water Chemistry Control Program, which is credited for managing the aging

effects for all temperatures, will preclude the possibility of cracking due to SCC. A One-Time

Inspection Program is also credited to confirm the adequacy of water chemistry control.

The staff reviewed the applicant's Water Chemistry Control Program and One-Time Inspection

Program and its evaluation is documented in SER Sections 3.0.3.2.20 and Section 3.0.3.2.13,

respectively. The staff found the applicant's use of the Water Chemistry Control Program,

which is credited for managing the aging effect of crack initiation and growth due to cracking or

stress corrosion cracking, to be consistent with the GALL Report. The staff also found that the

applicant's use of the One-Time Inspection Program to supplement the Water Chemistry

Control Program is an additional measure to the GALL Report that will ensure identification of

aging, should it occur in all areas, including those subject to stagnant flow conditions.

The staff found that, based on the programs identified above, the applicant has met the criteria

of SRP-LR Section 3.3.2.2.4 for further evaluation. For those line items that apply to LRA

Section 3.3.2.2.4, the staff found that the applicant is consistent with the GALL Report and has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained during the period of extended operation, as required by

1 0 CFR 54.21a)(3).

3.3.2.2.5 Loss of Material Due to General, Microbiologically Influenced, Pitting, and Crevice

Corrosion

The staff reviewed LRA Section 3.3.2.2.5 against the criteria in SRP-LR Section 3.3.2.2.5.

In LRA Section 3.3.2.2.5, the applicant addressed the loss of material due to general,

microbiologically influenced, pitting, and crevice corrosion.

SRP-LR Section 3.3.2.2.5 states that loss of material due to general, pitting, and crevice

corrosion could occur in the piping and filter housing and supports in the control room area, the

auxiliary and radwaste area, the primary containment heating and ventilation systems, in the

piping of the diesel generator building ventilation system, in the above-ground piping and

fittings, valves, and pumps in the diesel fuel oil system and in the diesel engine starting air,

combustion air intake, and combustion air exhaust subsystems in the emergency diesel

generator system. Loss of material due to general, pitting, crevice, and MIC could occur in the

duct fittings, access doors, and closure bolts, equipment frames and housing of the duct. Loss

of material due to pitting and crevice corrosion could occur in the heating/cooling coils of the air

handler heating/cooling, and due to general corrosion could occur on the external surfaces of

all carbon steel SCs, 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.

The applicant stated that (1) for the internal environments of applicable auxiliary systems, the

Periodic Surveillance and Preventive Maintenance Program, Open-Cycle Cooling (Service)

Water System Surveillance Program, One-Time Inspection Program, Fire Protection Program,

and Tank Internal Inspection Program are credited for managing these aging effects; and (2)

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for the external surfaces of all carbon steel components in auxiliary systems, the Systems

Monitoring Program or Bolting Integrity Program are credited for managing the aging effect of

loss of material. Also, in some cases, the applicant credited the Open-Cycle Cooling (Service)

Water System Surveillance Program or Fire Protection Program to augment the Systems

Monitoring Program for managing external aging effects. Closure bolting associated with these

components is addressed in LRA Table 3.3-1, Item 3.3.1-24.

As documented in the audit and review report, the applicant stated that this LRA section deals

with the management of loss of material due to general, pitting, and crevice corrosion, and MIC

for internal surfaces within ventilation and emergency power systems and for external surfaces

of carbon steel component in auxiliary systems. The internal environments associated with this

line item are those in which the internal surfaces are subject to normal atmospheric air and are

also prone to wetting or condensation. The Periodic Surveillance and Preventive Maintenance

Program provides for inspections of these wetted internal surfaces, which will look for and be

able to detect this aging effect. The Tank Internal Inspection Program also provides for the

inspection of selected tank internals, which will look for and be able to detect this aging effect;

therefore, application of the Periodic Surveillance and Preventive Maintenance Program or the

Tank Internal Inspection Program provides adequate assurance that this aging effect will be

managed throughout the period of extended operation.

The Systems Monitoring Program provides for visual inspections and monitoring of external

surfaces of piping, tanks, and other components and equipment, for leakage and evidence of

material degradation. These inspections and monitoring identify the aging effect of concern

(loss of material) on external surfaces prior to a loss of intended function of these components.

The Open-Cycle Cooling (Service) Water System Surveillance Program and the Fire Protection

Program provide for wall thickness assessments to be performed. These wall thickness

assessments are typically performed from the outside of the components and, therefore, are

capable of detecting any external surface degradation. On this basis, these two programs

augment the Systems Monitoring Program for managing loss of material on the external

surfaces of components within the service water system and the fire protection system.,.

The Bolting Integrity Program provides for visual inspection and monitoring of fasteners and

bolting for loss of material. These inspections and monitoring identify loss of material on the

external surfaces of these items prior to a loss of intended function of these items. Therefore,

the Systems Monitoring Program, augmented in selected cases by the Open-Cycle Cooling

(Service) Water System Surveillance Program, the Fire Protection Program, or the Bolting

Integrity Program, provides adequate assurance that loss of material on the external surfaces

of components will be managed for the period of extended operation.

The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program,

Open-Cycle Cooling (Service) Water System Surveillance Program, One-Time Inspection

Program, Fire Protection Program, Bolting Integrity Program, and Tank Internal Inspection

Program. The staff's evaluations of these programs are documented in SER

Sections 3.0.3.3.1, 3.0.3.2.14, 3.0.3.2.13, 3.0.3.2.10, 3.0.3.2.4, and 3.0.3.3.3, respectively.

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The staff found that, based on the programs identified above, the applicant met the criteria of

SRP-LR Section 3.3.2.2.5 for further evaluation. For those line items that apply to LRA

Section 3.3.2.2.5, the staff found that the applicant is consistent with the GALL Report and has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained during the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.2.6 Loss of Material Due to General, Galvanic, Pitting, and Crevice Corrosion

The staff reviewed LRA Section 3.3.2.2.6 against the criteria in SRP-LR Section 3.3.2.2.6.

In Section 3.3.2.2.6, the applicant addressed further evaluation of programs to manage loss of

material in the reactor coolant pump oil collection system by crediting the One-Time Inspection

Program.

SRP-LR Section 3.3.2.2.6 states that loss of material due to general, galvanic, pitting, and

crevice corrosion could occur in tanks, piping, valve bodies, and tubing in the reactor coolant

pump oil collection system in fire protection. The Fire Protection Program relies on a

combination of visual and volumetric examinations in accordance with the guidelines of

10 CFR 50, Appendix R, and Branch Technical Position 9.5 1 to manage loss of material from

corrosion. However, corrosion may occur at locations where water from washdowns may

accumulate. Therefore, verification of the effectiveness of the program should be performed to

ensure that corrosion is not occurring. The GALL Report recommends further evaluation of

programs to manage loss of material due to general, galvanic, pitting, and crevice corrosion to

confirm the effectiveness of the program. A one-time inspection of the bottom half of the

interior surface of the tank of the reactor coolant pump oil collection system is an acceptable

method to ensure that corrosion is not occurring and that the component's intended function will

be maintained during the period of extended operation.

The applicant stated that it credited the One-Time Inspection Program for managing the aging

effects of components within the reactor coolant pump oil collection subsystem.

As documented in the audit and review report, the staff held technical discussions with the

applicant. The applicant stated that loss of material due to general, galvanic, pitting, and

crevice corrosion could occur in the reactor coolant pump oil collection subsystem. The

One-Time Inspection Program, which is credited to manage this aging effect, addressed the

potentially long incubation period for this aging effect and provides a means of confirming that

this aging effect is either not occurring or progressing so slowly as to have negligible effect on

the intended function(s) of the reactor coolant pump oil collection subsystem.

The staff reviewed the applicant's One-Time Inspection Program and its evaluation is

documented in SER Section 3.0.3.2.13. On the basis of its review, the staff found that the

One-Time Inspection Program adequately manages the aging effects of components within the

reactor coolant pump oil collection subsystem.

The staff found that, based on the program identified above, the applicant met the criteria of

SRP-LR Section 3.3.2.2.6 for further evaluation. For those line items that apply to LRA

Section 3.3.2.2.6, the staff found that the applicant is consistent with the GALL Report and has

demonstrated that the effects of aging will be adequately managed so that the intended

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functions will be maintained during the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.2.7 Loss of Material Due to General, Pitting, Crevice, and Microbiologically Influenced

Corrosion and Biofouling

The staff reviewed LRA Section 3.3.2.2.7 against the criteria in SRP-LR Section 3.3.2.2.7.

In LRA Section 3.3.2.2.7, the applicant addressed further evaluation of programs to manage

loss of material in the diesel fuel oil system to confirm the effectiveness of the diesel fuel oil

program.

SRP-LR Section 3.3.2.2.7 states that loss of material due to general, pitting, and crevice

corrosion, microbiologically induced corrosion (MIC), and biofouling could occur in the internal

surface of tanks in the diesel fuel oil system in the emergency diesel generator 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, D1 796, D2709,

and D2276 to manage loss of material due to corrosion or biofouling. Corrosion or biofouling

may occur at locations where contaminants accumulate. Verification of the effectiveness of the

Fuel Oil Chemistry Control Program should be performed to ensure that corrosion is not

occurring. The GALL Report recommends further evaluation of programs to manage

corrosion/biofouling to confirm the effectiveness of the program. A one-time inspection of

selected components at susceptible locations is an acceptable method to ensure that corrosion

is not occurring and that the component's intended function will be maintained during the period

of extended operation.

The AMPs recommended by the GALL Report are GALL AMP XI.M30, "Fuel Oil Chemistry,"

and GALL AMP XL.M32, "One-Time Inspection," for management of this aging effect.

The applicant stated that the Fuel Oil Chemistry Control Program is credited with managing the

applicable aging effects in the fuel oil systems. The applicant further stated that the One-Time

Inspection Program is also used to verify the adequacy of the Fuel Oil Chemistry Program in

managing these aging effects.

During the audit, the staff held technical discussion with the applicant. The applicant stated that

loss of material due to general, pitting and crevice corrosion, MIC, and biofouling could occur on

the internal surfaces of fuel oil tanks. The Fuel Oil Chemistry Control Program mitigates and

manages these aging effects on the internal surfaces of fuel oil storage tanks and associated

components in systems that contain fuel oil. The program includes: (1) surveillance and

monitoring procedures for maintaining fuel oil quality by controlling contaminants in accordance

with applicable ASTM standards, (2) periodic draining of water from fuel oil tanks, (3) periodic or

conditional visual inspections of internal surfaces or wall thickness measurements from external

surfaces of fuel oil tanks, and (4) one-time inspections of a representative sample of

components in systems that contain fuel oil.

The objective of the Fuel Oil Chemistry Control Program is to minimize the introduction and

presence of contaminants in the plant's fuel oil system that could cause degradation of

components in systems that contain fuel oil. A representative sample of components in

systems that contain fuel oil will be inspected via the One-Time Inspection Program. The

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One-Time Inspection Program addresses the potentially long incubation periods for these aging

effects and provides a means of confirming that these aging effects are either not occurring or

progressing so slowly as to have negligible effect on the intended function(s) of these

components; therefore, a combination of the Fuel Oil Chemistry Control Program and

One-Time Inspection Program is used to manage these aging effects.

The staff reviewed the applicant's Fuel Oil Chemistry Control Program and One-Time

Inspection Program and its evaluations of these programs are documented in SER

Sections 3.0.3.2.12 and 3.0.3.2.13, respectively. On the basis of its review, the staff found that

these programs adequately manage the applicable aging effects in the fuel oil system.

The staff found that, based on the programs identified above, the applicant met the criteria of

SRP-LR Section 3.3.2.2.7 for further evaluation. For those line items that apply to LRA

Section 3.3.2.2.7, the staff found that the applicant is consistent with the GALL Report and has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained during the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.2.8 Quality Assurance for Aging Management of Non-Safety-Related Components

SER Section 3.0.4 provides the staff's evaluation of the applicant's quality assurance

program.

3.3.2.2.9 Crack Initiation and Growth Due to Stress Corrosion Cracking and Cyclic Loading

The staff reviewed LRA Section 3.3.2.2.9 against the criteria in SRP-LR Section 3.3.2.2.9.

In LRA Section 3.3.2.2.9, the applicant addresses further evaluation of programs to manage

cracking in the chemical and volume control system to confirm the effectiveness of the Water

Chemistry Control Program.

SRP-LR Section 3.3.2.2.9 states that crack initiation and growth due to SCC and cyclic loading

could occur in the channel head and access cover, tube sheet, tubes, shell and access cover,

and closure bolting of the regenerative heat exchanger and in the channel head and access

cover, tube sheet, 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-1 05714 for primary water chemistry to manage

the effects of crack initiation and growth due to SCC and cyclic loading. Verification of the

effectiveness of the Water Chemistry Control Program should be performed 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 confirm

the effectiveness of the Water Chemistry Control Program. A one-time inspection of select

components and susceptible locations is an acceptable method to ensure that 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 stated, in the LRA, that although the GALL Report references a temperature gate

of less than 90 0C (200 OF) and a single aging effect, materials science supports:

(1) a temperature gate greater than 140 'F for cracking due to SCC and (2) loss of material due

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to pitting and crevice corrosion for all temperatures. Although the aging effect identified for

temperatures less than 140 OF differs from that of the GALL Report's Water Chemistry Control

Program, which is credited for managing the aging effects for all temperatures, it will preclude

the possibility of cracking due to SCC. In some cases the Closed-Cycle Cooling Water System

Surveillance Program is credited, which includes water chemistry controls for closed-cycle

cooling water. In all cases the One-Time Inspection Program is also credited to confirm the

adequacy of water chemistry control.

The staff reviewed the applicant's Water Chemistry Control Program, Closed-Cycle Cooling

Water System Surveillance Program, and One-Time Inspection Program and its evaluations of

these programs are documented in SER Sections 3.0.3.2.20, 3.0.3.2.9, and 3.0.3.2.13,

respectively. The staff found the applicant's use of the Water Chemistry Control Program,

which is applicable to all temperature ranges, for managing the aging effect crack initiation and

growth due to SCC and cyclic loading, to be consistent with the GALL Report. The staff found

that the applicant's use of the One-Time Inspection Program to supplement the Water

Chemistry Control Program is consistent with the GALL Report to ensure identification of aging,

should it occur in all areas including those that might be subject to stagnant or low-flow

conditions. The staff found that the applicant's use of the Closed-Cycle Cooling Water System

Surveillance Program, which includes water chemistry controls for closed-cycle cooling water, is

an additional measure that supplements the criteria of the GALL Report and is an acceptable

addition to ensure management of aging effects in the closed-cycle cooling water system.

The staff found that, based on the programs identified above, the applicant met the criteria of

SRP-LR Section 3.3.2.2.9 for further evaluation. For those line items that apply to LRA

Section 3.3.2.2.9, the staff found that the applicant is consistent with the GALL Report and has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained during the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.2.10 Reduction of Neutron-Absorbing Capacity and Loss of Material Due to General

Corrosion

The staff reviewed LRA Section 3.3.2.2.10 against the criteria in SRP-LR Section 3.3.2.2.1 0.

SRP-LR Section 3.3.2.2.10 states that reduction of neutron-absorbing capacity and loss of

material due to general corrosion could occur in the neutron-absorbing sheets of the spent fuel

storage rack in the spent fuel storage pool. The GALL Report recommends further evaluation

to ensure that these aging effects are adequately managed.

In LRA Section 3.3.2.2.10, the applicant stated that this specific material, Boral, is not used in

the spent fuel pool for neutron absortion; therefore, an AMP is not required. However, line

Item 3.3.1-12, dealing with Boraflex, is applicable. The staff's evaluations of the Boraflex

Monitoring Program and the spent fuel storage rack boraflex TLAA are evaluated in SER

Sections 3.0.3.2.5, and 4.6, respectively.

On the basis that this component is not part of the PBNP design, the staff found that this aging

effect is not applicable.

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

Corrosion

The staff reviewed LRA Section 3.3.2.2.11 against the criteria in SRP-LR Section 3.3.2.2.11.

SRP-LR Section 3.3.2.2.11 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 (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. The effectiveness of the Buried Piping and Tanks Inspection Program

should be verified to evaluate an applicant's inspection frequency and operating experience

with buried components, ensuring that loss of material is not occurring.

The AMP recommended by the GALL Report is GALL AMP XI.M34, 'Buried Piping and Tanks

Inspection."

The applicant stated that the Buried Services Monitoring Program is credited for managing

these aging effects for buried components. The applicant also stated that external surfaces of

buried components are visually examined during maintenance activities (inspections of

opportunity). No evidence of age-related degradation has been detected from inspections

performed to date.

In RAI B2.1.7-1, discussed in SER Section 3.0.3.2.7, the staff requested the applicant to

explain how it ensures that all buried components are coated. In its letter, dated

March 15, 2005, the applicant stated that its Buried Services Monitoring Program includes

visual inspections of the external surfaces of buried carbon steel, cast iron, and low-alloy steel

components that are within the scope of license renewal in the service water, fuel oil, and fire

protection systems.

The applicant also stated that inspections of the service water, fuel oil, and fire protection

systems will be performed based on plant operating experience and opportunities for

inspection. In addition, a susceptible location in the fire protection system (i.e., uncoated

unwrapped piping) will be scheduled to be inspected once prior to the period of extended

operation and at least every 10 years during the period of extended operation. The intent of

these scheduled inspections is to ensure that buried components within the fire protection

system are periodically inspected. Therefore, if an opportunity for inspection occurs prior to the

scheduled inspection, such inspection can be credited for satisfying the scheduled inspection.

The applicant also stated that groundwater/lake water is analyzed periodically, and that

analyses performed to date confirm that the water is non-aggressive.

The staff reviewed the applicant's Buried Services Monitoring Program and its evaluation is

documented in SER Section 3.0.3.2.7. The staff found that the facility's operating history

confirms that the Buried Services Monitoring Program is adequately managing the aging effects

associated with loss of material due to general, pitting, and crevice corrosion and MIC that

could occur in the underground piping and fittings in the service water system, in the fire

protection system, and in the diesel fuel oil system. The staff also found that the applicant has

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measures currently in place that will adequately identify any degradation to components due to

these aging effects.

The staff found that, based on the program identified above, the applicant met the criteria of

SRP-LR Section 3.3.2.2.11 for further evaluation. For those line items that apply to LRA

Section 3.3.2.2.11, the staff found that the applicant is consistent with the GALL Report and has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained during the period of extended operation, as required by

10 CFR 54.21 (a)(3).

Conclusion. On the basis of its review, for component groups evaluated in the GALL Report for

which the applicant claimed consistency with the GALL Report, and for which the GALL Report

recommends further evaluation, the staff determined that (1) those attributes or features for

which the applicant claimed consistency with the GALL Report were indeed consistent and (2)

the applicant had adequately addressed the issues that were further evaluated. The staff found

that the applicant had demonstrated that the effects of aging will be adequately managed so

that the intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

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

Summary of Technical Information in the AnDlication. In LRA Tables 3.3.2-1 through 3.3.2-16,

the staff reviewed additional details of the results of the AMRs for material, environment,

AERM, and AMP combinations that are not consistent with the GALL Report or are not

addressed in the GALL Report.

As documented under RAI 2.1-1 in SER Section 2.1, by letter dated April 29, 2005, the

applicant changed the methodology used to determine the nonsafety-related SCs that are

within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(2).

As a result of the implementation of the scoping methodology changes, the applicant identified

changes to LRA Tables 3.3.3.2-1, 3.3.2-2, 3.3.2-3, 3.3.2-4, 3.3.2-10, and 3.3.2-14.

In Tables 3.3.2-1 through 3.3.2-16, the applicant indicated, via Notes F through J, that neither

the identified component nor the materiaVenvironment combination is evaluated in the GALL

Report and provided information concerning how the AERM will be managed.

Staff Evaluation. For component type materiaVenvironment combinations not evaluated in the

GALL Report, the staff reviewed the applicant's evaluation to determine whether the applicant

had demonstrated that the effects of aging will be adequately managed so that the intended

function will be maintained consistent with the CLB during the period of extended operation.

The staff's review of LRA Section 3.3 identified areas in which additional information was

necessary to complete the review of the applicant's results. The applicant responded to the

staff's general RAls as discussed below.

RAI 3.3-1. In LRA Tables 3.3.2-3, 3.3.2-7, and 3.3.2-9, heat exchangers and heater/coolers

with heat transfer as the intended function are identified with only internal environments and

associated aging effects. The external environment is listed as "N/A." In RAI 3.3-1, dated

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November 18, 2004, the staff requested the applicant to explain why the external environment

and associated aging effects were not be identified for these components. The applicant was

also requested to address the similar question for the heat exchangers and heater/coolers in

LRA Tables 3.3.2-2, 3.3.2-3, 3.3.2-4, 3.3.2-5, 3.3.2-7, and 3.3.2-9 which have pressure

boundary as their intended function.

In its response, dated January 7, 2005, the applicant stated:

Due to the way our database was developed and used, tubing assets were identified as

two separate components (tubing ID and tubing OD). This allowed us to select an

internal environment for each (ID and OD), but since the database required each

component to have both an internal and external environment, we would then document

the external environment as N/A. This was done to keep internal and external

environments somewhat standard (see PBNP LRA Table 3.0-1, Internal Service

Environments and Table 3.0-2, External Service Environments). Note that in

Tables 3.3.2-3, 3.2-7, and 3.3.2-9, you will find a Heat Exchanger (HX) material type

with two different internal environments, which is reflective of the environments for the

ID and OD of the tubing. ;

The only components that have a 'heat transfer' intended function are the tubes.

External environments (indoor - no air conditioning, outdoor, etc.) would only apply to

the shell of the HX, and since the shell only has a pressure boundary function, it (the

shell) and its external environment are not identified under the 'heat transfer' intended

function. Additionally, the shell is typically made of a different material than the tubes

and, therefore, would not be represented by the same line item as the tubing in the LRA.

This same methodology was used for heat exchangers and heater/coolers that have

'pressure boundary' intended functions, which produces similar results in Tables

3.3.2-2, 3.3.2-3, 3.3.2-4, 3.3.2-5, 3.3.2-7, and 3.3.2-9.

The staff found the applicant's response acceptable. The applicant provided a satisfactory

explanation for identifying the external environment and the associated aging effects for the

various components requested. The staff's concern described in RAI 3.3-1 is resolved.

RAI 3.3-2. LRA Table 3.3.2-7 identifies no aging effects for neoprene expansion joints with an

internal environment of air and wetted gas less than 140 OF. Also, LRA Table 3.3.2-13 identifies

the aging effects change in material properties and cracking for neoprene expansion joints with

an external environment of indoor with no air conditioning; however, no aging management is

performed for these components. For similar neoprene components in warm, moist

environments, the GALL Report identifies two aging effects: hardening and loss of strength,

and recommends a plant-specific AMP to manage these aging effects. In RAI 3.3-2, dated

November 18, 2004, the staff requested the applicant to provide justification as to why no aging

effects were identified for the internals of the expansion joints in LRA Table 3.3.2-7 and why no

aging management is identified for the expansion joints in LRA Table 3.3.2-13.

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In its response, dated January 7, 2005, the applicant stated:

In accordance with the EPRI report 1002950, Aging Effects for Structures and Structural

Components (Structural Tools), Revision 1, August 2003, no aging effects exist for this

material in these environments and this is substantiated by PBNP plant-specific

Operating Experience (OE). We attempted to explain this using Note 16 in

Table 3.3.2.7. Note 16 states that elastomer (neoprene, rubber, etc.) components are

indoors and not subject to Ultraviolet (UV) or ozone, nor are they in locations that are

subject to radiation exposure. These locations are also not subject to temperatures

where change in material properties or cracking could occur (i.e., greater than 95 QF).

Although the environment definition implies that temperatures may reach 140 QF, the

actual individual environments for these specific components were reviewed, and they

do not exceed the 95 OF threshold temperature. As a result, it was determined that

these criteria are not exceeded in these instances and, therefore, no aging management

is required.

The staff found the applicant's response acceptable. The applicant explained why no aging

effects were identified for certain expansion joints and no AMPs were provided for certain other

expansion joints. The staff's concern described in RAI 3.3-2 is resolved.

RAI 3.3-5. LRA Tables 3.3.2-7 and 3.3.2-9 identify the Periodic Surveillance and Preventive

Maintenance Program to manage loss of heat transfer due to fouling for heat exchangers in oil

and fuel oil (internal), outdoor (external), and air and gas within wetted environments. The

"monitoring and trending" program element states that inspections, examination, testing, and

component replacement activities are performed on a specified frequency based on operating

experience or other requirements. The applicant stated that the results of these surveillance

and preventive maintenance activities are documented, and subject to review and approval.

NUREG-1 800 Section A.1.2.3.5 recommends that monitoring and trending activities be

described, and they should provide predictability of the extent of degradation and thus effect

timely corrective actions. Plant-specific and/or industry operating experience may be

considered in evaluating the appropriateness of the technique and frequency. In RAI 3.3-5,

dated November 18, 2004, the staff requested the applicant to describe the inspection

technique and frequency. The inspection frequency should be justified by plant operating

experience and should be adequate to detect the aging effects such that the intended function

will be maintained during the period of extended operation.

In its response, dated January 7, 2005, the applicant stated:

By letter dated February 25, 2004 (NRC 2004-0016), Nuclear Management Company

(NMC), LLC, submitted the Point Beach Nuclear Plant (PBNP) Units 1 and 2 License

Renewal Application (LRA). During the weeks of April 26 and June 7,2004, the NRC

performed an on-site audit of the PBNP aging management programs and aging

management reviews. As a result of this audit and subsequent conversations between

NMC and the NRC staff, the NRC staff requested various clarifications to the LRA. By

letter dated July 12, 2004 (NRC 2004-0071), NMC submitted these LRA clarifications to

the NRC staff. Several of these clarifications involved the Periodic Surveillance and

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Preventive Maintenance Program (LRA Section B2.1.15), including the responses to

Audit items 69, 148 and 196 in the enclosure to this letter.

The response to Audit item 196 provides a table that links the aging effects/

mechanisms managed by the Periodic Surveillance and Preventive Maintenance

Program with the parameters monitored/inspected and the measurement methodology.

The inspection method identified for loss of heat transfer due to fouling is General or

Remote Visual. Where the material is in an oil or fuel oil environment, an oil sample will

be taken and analyzed for evidence of MIC, corrosion products, and/or other

contaminants in lieu of these inspection. General or remote visual examinations will be

performed in accordance with the requirements of ASME Section V and 10 CFR 50,

Appendix B. This inspection methodology is capable of measuring the parameter

monitored (i.e., tube fouling) and providing data that is adequate to conclude the aging

effect is managed consistent with the current licensing basis. If a different inspection

method is used, the basis for the revised inspection method will be documented. If

degradation is identified through a visual inspection, additional non-destructive

examination (NDE) may be performed to characterize the degradation and determine

the extent of condition. The inspection frequency for the Periodic Surveillance and

Preventive Maintenance Program activities credited for those line items in LRA

Tables 3.3.2-7 and 3.3.2-9 will be justified by plant-specific operating experience during

implementation of the program. This process will ensure that the activities will be

adequate to detect aging effects such that the intended function will be maintained

during the period of extended operation.

The staff found the applicant's response reasonable and acceptable. The applicant provided a

satisfactory explanation of how the inspection technique and frequency would remain adequate

to detect the aging effects. The staff's concern described in RAI 3.3-5 is resolved.

RAI 3.3-6. The loss of preload is an aging effect for closure bolting in high temperature or high

pressure systems. GALL AMP XI.M1 8, uBolting Integrity" program provides aging management

inspections for this aging effect. LRA Section 3.3 for the auxiliary systems does not identify

loss of preload as an aging effect for closure bolting. In RAI 3.3-6, dated November 18, 2004,

the staff requested the applicant to discuss why the loss of preload was not identified as an

aging effect for auxiliary systems closure bolting and the inspections in GALL AMP XI.M18 were

not credited for managing this aging effect.

In its response, dated January 7, 2005, the applicant stated the following:

... NMC considered loss of preload for closure bolting to be a design driven effect, not

an applicable aging effect for the Engineered Safety Features (ESF), Auxiliary Systems,

and Steam and Power Conversion System (SPCS) system groupings. Operating

temperatures in these three system groupings are below the threshold temperature

where creep of the bolting material could occur. Additionally, a properly designed and

installed bolted joint will not be affected by loss of preload. Leakage at joints is typically

associated with improper joint installation (eg., proper cleanliness, gasketing, and

preload) or inadequate joint design, not relaxation of the bolting materials. Although

PBNP does not consider loss of preload an aging effect, normal maintenance practices

intended to preclude loss of preload are applied to pressure-retaining bolted

connections when they are assembled. These maintenance practices are

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proceduralized and include proper torque selection, torque pattems, thread engagement

criteria, and inspection of bolting materials including gaskets. These procedures for

joint installation incorporate industry bolting guidance, which also provide for the use of

proper lubricants and sound bolt torquing practices. PBNP's plant-specific operating

experience shows that bolted joint failures due to loss of preload are not occurring within

these system groupings. Therefore, the loss of preload due to stress relaxation for

closure bolting in the Auxiliary Systems, ESF, and SPCS system groupings does not

require aging management based on system operating temperatures and industry

bolting practices.

During a meeting on February 15, 2005, the staff indicated and the applicant agreed, that this

response requires further clarification. The staff requested the applicant to provide technical

justification for not managing loss of preload for all safety-related bolting or confirm that the

Bolting Integrity Program applies good bolting practices to manage loss of mechanical closure

integrity caused by loss of preload for all bolting within the scope of license renewal.

In its response, a clarification letter dated March 15, 2005, the applicant stated that the Bolting

Integrity Program will manage loss of preload for bolted connections subject to vibration or high

temperatures in the engineered safety features, auxiliary systems, and steam and power

conversion systems.

The staff finds the applicant's response reasonable and acceptable. The applicant explained

that loss of preload for applicable bolts will be managed by the Bolting Integrity Program. The

staff's concern described in RAI 3.3-6 is resolved.

3.3.2.3.1 Auxiliary System Components That Have No Aging Effects - Tables 3.3.2-1 through

3.3.2-16

In LRA Tables 3.3.2-1 through 3.3.2-16, the applicant identified line items where no aging

effects were identified as a result of the aging review process. Specifically, instances in which

the applicant stated that no aging effects were identified occurred when components fabricated

from carbon steel, copper alloy, stainless steel or stainless steel clad material, CASS and glass

were exposed to air or to an inert gas. The applicant defined an air environment as

dehumidified atmospheric air, dry/filtered instrument air. Neither air nor inert gas is identified in

the GALL Report as an-environment for these components and materials. No aging effects are

considered to be applicable to carbon steel, copper alloy, stainless steel or stainless steel clad,

CASS and glass components exposed to air, or to an inert gas environment.

On the basis of its review of current industry research and operating experience, the staff found

that dry air on metal will not result in aging that will be of concern during the period of extended

operation. Stainless steel and nickel-based alloy components in air or an inert gas environment

are not susceptible to general corrosion that would affect their intended function. Therefore,

the staff concluded that there are no applicable aging effects requiring management for carbon

steel, copper alloy, stainless steel or stainless steel clad, CASS and glass components exposed

to air, or to an inert gas environment.

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3.3.2.3.2 Chemical and Volume Control System - Aging Management Evaluation -

Table 3.3.2-1

The staff reviewed LRA Table 3.3.2-1, as modified by letter dated April 29, 2005, which

summarizes the results of AMR evaluations for the chemical volume and control system

component groups.

The chemical and volume control system experiences loss of material of carbon and low-alloy

steel, stainless steel and CASS for the following component types:

* CS components * instrument valve assemblies

* fasteners and bolting * piping and fittings

* filters and strainers * pump casings

* flow elements * tanks

* heat exchangers * thermowells

* level gauges * valve bodies

For those components requiring staff review, the environments are listed below:

* borated water leaks (external)

* containment (external)

* treated water - borated (T1 40 0F)(internal)

* treated water - borated (T<1400F)(intemal)

* treated water - primary (T<1 40 0F)(intemal)

* treated water - primary (1400F< T<4800F)(intemal)

* treated water - other (internal)

* treated water - other (stagnant)(internal)

* indoor - no air conditioning (external)

The staff evaluation with respect to component environments listed as "not applicable" and loss

of preload for closure bolting are discussed under the general RAls in SER Section 3.3.2.3.

The applicant proposed to manage the chemical volume and control system loss of material

aging effects by using the Boric Acid Corrosion Program, Bolting Integrity Program, One-Time

Inspection Program, Water Chemistry Control Program, Systems Monitoring Program, and

Closed-Cycle Cooling Water System Surveillance Program. The staff's evaluations of these

programs are documented in SER Sections 3.0.3.2.6, 3.0.32.4, 3.0.3.2.13, 3.0.3.2.20,

3.0.3.3.2, and 3.0.3.2.9, respectively.

The applicant proposed to manage cracking due to SCC of stainless steel material for

component types of heat exchanger, valve bodies, piping, and fitting, exposed to borated water

and treated water with temperatures between 140 OF and 480 OF environment using the

One-Time Inspection Program, and Water Chemistry Control Program.

The staff reviewed the applicant's One-Time Inspection Program and Water Chemistry Control

Program. The staff's evaluations of these programs are documented in SER

Sections 3.0.3.2.13 and 3.0.3.2.20, respectively. On the basis of its review of the applicant's

plant-specific and industry operating experience, the staff found that cracking due to SCC of

stainless steel material for component types in the chemical and volume control system is

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effectively managed using the OneTime Inspection Program and Water Chemistry Control

Program. Therefore, the staff found that management of cracking due to SCC in the chemical

and volume control system using these programs is acceptable.

3.3.2.3.3 Component Cooling Water System - Aging Management Evaluation - Table 3.3.2-2

The staff reviewed LRA Table 3.3.2-2, as modified by letter dated April 29, 2005, which

summarizes the results of AMR evaluations for the component cooling water system

component groups.

The component cooling water system experiences loss of material of carbon and low-alloy

steel, stainless steel, cast iron, copper alloy, (Zn<l 5%) and copper alloy (Zn>15%) for the

following component types:

* CS components * piping and fittings

* fasteners and bolting * pump casings

* flow elements * tanks

* heat exchangers * thermowells

* radiation monitor * valve bodies

* instrument valve assemblies

For those components requiring staff review, the environments are listed below:

* borated water leaks (external)

* treated water - other (velocity)(intemal)

* raw water (velocity)(internal)

* treated water - primary (T>480 OF)(internal)

* treated water - primary (1 400FcT<480 OF)(internal)

* treated water - secondary (T>1 20 OF)(internal)

* treated water - other (stagnant)(intemal)

* air and gas - wetted (T<1400F)(internal)

* containment (external)

* - indoor - no air conditioning (external)

The staff evaluation with respect to component environments listed as "not applicable" and loss

of preload for closure bolting are discussed under the general RAls in SER Section 3.3.2.3.

The applicant proposed to manage the component cooling water system loss of material aging

effects by using the Boric Acid Corrosion Program, Bolting Integrity Program, One-Tirmes

Inspection Program, Water Chemistry Control Program, Systems Monitoring Program;,'

Open-Cycle Cooling (Service) Water System Surveillance Program, and Closed-Cycle Cooling'

Water System Surveillance Program. The staff's evaluations of these programs are

documented in SER Sections 3.0.3.2.6, 3.0.3.2.4, 3.0.3.2.13, 3.0.3.2.20, 3.0.3.3.2, 3.0.3.2j14,'

and 3.0.3.2.9, respectively. ,

On the basis of its review, the staff found the aging effects of the above component cooIng

water system components are consistent with industry experience for these combinations of

materials and environments. The staff found that the applicant identified the appropriate aging

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effects for the materials and environments associated with the above components in the

component cooling water system.

The applicant proposed to manage loss of heat transfer due to fouling of stainless steel

material for component type of heat exchanger exposed to treated water - other (velocity), and

raw water (velocity) environment using the Open-Cycle Cooling (Service) Water System

Surveillance Program and Closed-Cycle Cooling Water System Surveillance Program.

The staff reviewed the applicant's Open-Cycle Cooling (Service) Water System Surveillance

Program and Closed-Cycle Cooling Water System Surveillance Program. The staff's

evaluations are documented in SER Sections 3.0.3.2.14 and 3.0.3.2.9, respectively. On the

basis of its review of the applicant's plant-specific and industry operating experience, the staff

found that loss of heat transfer due to fouling for component types in the component cooling

water system are effectively managed using the Open-Cycle Cooling (Service) Water System

Surveillance Program and Closed-Cycle Cooling Water System Surveillance Program.

Therefore, the staff found that management of loss of heat transfer due to fouling in the

component cooling water system using these programs is acceptable.

The applicant proposed to manage cracking due to SCC, IGA, and IGSCC of stainless steel

materials for component type of heat exchanger pressure boundaries exposed to primary

treated water with temperature greater than 480 OF, with temperature between 140 OF and

480 OF, and secondary treated water with temperature greater than 120 OF environments using

Water Chemistry Control Program and the One-Time Inspection Program.

The staff reviewed the applicant's Water Chemistry Control Program and One-Time Inspection

Program and its evaluations are documented in SER Sections 3.0.3.2.20 and 3.0.3.2.13,

respectively. On the basis of its review of the applicant's plant-specific and industry operating

experience, the staff found that cracking due to SCC for component types in the component

cooling water system is effectively managed using the Water Chemistry Control Program and

One-Time Inspection Program. On this basis, the staff found that management of cracking due

to SCC in the component cooling water system is acceptable.

The staff's review of LRA Table 3.3.2-2 identified an area in which additional information was

necessary to complete the review of the applicant's program elements. The applicant

responded to the staff's RAI as discussed below.

RAI 3.3-7. In LRA Table 3.3.2-2, the applicant proposed to manage cracking due to

IGA/IGSCC of stainless steel material for heat exchanger components exposed to primary

treated water with temperature greater than 480 OF using the Water Chemistry Control Program.

This line item cites Note 35, which states: uComponent/materiaVenvironment is not addressed

in the corresponding NUREG-1 801 Chapter, but the componenttmateriaVenvironment is

addressed in another NUREG-1801 Chapter." This line Item references AMR line

item 3.1.1-36, which provides the following discussion:

Crack initiation growth due to SCC and flaw growth are identified as aging effects

requiring management for the reactor vessel nozzle safe ends, CRD housing, and RCS

components. Aging management programs credited for managing these effects are the

Water Chemistry Control Program and ASME Section Xl, Subsections IWB, IWC, and

IWD Inservice Inspection Program.

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The note implies that ASME Section Xl, Subsections IWB, IWC, and IWD Inservice Inspection

Program should have also been applied to LRA Table 3.3.2-2. In RAI 3.3-7, dated

March 31, 2005, the staff requested the applicant to explain this discrepancy or make a

commitment to review the line Item in LRA Table 3.3.2-2 to include the Inservice Inspection

Program. This was identified as open item (01) 3.3-7.

In its response to 01 3.3-7, by letter dated April 29, 2005, the applicant addressed the staff's

concern. Subsequently, by letter dated June 10, 2005, the applicant committed to use the

One-Time Inspection Program in conjunction with the Water Chemistry Control Program to

manage IGANIGSCC aging mechanisms. The staff found the applicant's response to RAI 3.3-7

and the addition of the One-Time Inspection Program is an acceptable approach to manage the

aging effects. The staff's concern is resolved and, therefore, 01 3.3-7 is closed.

The staff reviewed the applicant's Water Chemistry Control Program and its evaluation is

documented in SER Section 3.0.3.2.20. On the basis of its review of the applicant's

plant-specific and industry operating experience, the staff found that cracking due to

IGA/IGSCC for component types in the component cooling water system is effectively managed

using the Water Chemistry Control Program. Therefore, the staff found that management of

cracking due to IGA/IGSCC in the component cooling water system using these programs is

acceptable.

3.3.2.3.4 Spent Fuel Cooling System Aging Management Evaluation - Table 3.3.2-3

The staff reviewed LRA Table 3.3.2-3, as modified by letter dated April 29, 2005, which

summarizes the results of AMR evaluations for the spent fuel cooling system component

groups.

The spent fuel cooling system experiences loss of material of carbon low-alloy steel, stainless

steel, and CASS for the following component types:

* CS components * instrument valve assemblies

* fasteners and bolting * piping and fittings

* flow elements * pump casings

* heat exchangers * valve bodies

* filters and strainers * tanks

For those components requiring staff review, the environments are listed below:

* borated water leaks (external)

* treated water - borated (T<140OF)(internal)

* raw water (internal)

* indoor - no air conditioning (external)

The staff evaluation with respect to component environments listed as "not applicable" and loss

of preload for closure bolting are discussed under the general RAls in SER Section 3.3.2.3.

The applicant proposed to manage the spent fuel cooling system loss of material aging effects

by using the Boric Acid Corrosion Program, Bolting Integrity Program, One-Time Inspection

Program, Water Chemistry Control Program, Systems Monitoring Program, and Open-Cycle

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Cooling (Service) Water System Surveillance Program. The staff's evaluations of these

programs are documented in SER Sections 3.0.3.2.6, 3.0.3.2.4, 3.0.3.2.13, 3.0.3.2.20,

3.0.3.3.2, and 3.0.3.2.14, respectively.

On the basis of its review, the staff found the aging effects of the above spent fuel cooling

system component types are consistent with industry experience for these combinations of

materials and environments. The staff found that the applicant identified the appropriate aging

effects for the material and environment associated with the above components in the spent

fuel cooling system.

The applicant proposed to manage loss of heat transfer due to fouling of stainless steel

material for component type of heat exchanger exposed to raw water environment using

Open-Cycle Cooling (Service) Water System Surveillance Program. The applicant stated that

One-Time Inspection Program and Water Chemistry Control Program are used for components

exposed to an environment of treated borated water with temperature less than 140 "F.

The staff reviewed the applicant's Open-Cycle Cooling (Service) Water System Surveillance

Program, One-Time Inspection Program, and Water Chemistry Control Program and its

evaluation of these programs is documented in SER Sections 3.0.3.2.14, 3.0.3.2.13, and

3.0.3.2.20, respectively.

On the basis of its review of the applicant's plant-specific and industry operating experience, the

staff found that loss of heat transfer due to fouling for component types in the spent fuel cooling

system are effectively managed using Open-Cycle Cooling (Service) Water System

Surveillance Program, One-Time Inspection Program, and Water Chemistry Control Program.

Therefore, the staff found that management of loss of heat transfer due to fouling in the spent

fuel cooling system using these programs is acceptable.

3.3.2.3.5 Waste Disposal System - Aging Management Evaluation - Table 3.3.2-4

The staff reviewed LRA Table 3.3.2-4, as modified by letter dated April 29, 2005, which

summarizes the results of AMR evaluations for the waste disposal system component groups.

The waste disposal system experiences loss of material of carbon and low-alloy steel, stainless

steel, copper alloy (Zn>1 5%), copper alloy (Zn<1 5%), cast iron, and CASS for the following

component types:

* CS components * level gauges

* fasteners and bolting * piping and fittings

* flow indicators * radiation monitors

* heat exchangers * restricting orifices

* drain trap * sight glass

* compressor casing * tanks

* filters and strainers * valve bodies

* instrumentation

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For those components requiring staff review, the environments are listed below:

* borated water leaks (external) * treated water - other (internal)

* treated water - borated (T<140 1F)(internal)

* air and gas - wetted (T<1 40 OF)(intemal)

* raw water drainage (internal)

* indoor - no air conditioning (external)

The staff evaluation with respect to component environments listed as "not applicable" and loss

of preload for closure bolting are discussed under the general RAls in SER Section 3.3.2.3.

The applicant proposed to manage the waste disposal system aging effects by using the Boric

Acid Corrosion Program, Bolting Integrity Program, One-Time Inspection Program, Water

Chemistry Control Program, Systems Monitoring Program, Periodic Surveillance and Preventive

Maintenance Program, and Closed-Cycle Cooling Water System Surveillance Program. The

staff's evaluations of these programs are documented in SER Sections 3.0.3.2.6, 3.0.3.2.4,

3.0.3.2.13, 3.0.3.2.20, 3.0.3.3.2, 3.0.3.3.1, and 3.0.3.2.9, respectively.

On the basis of its review, the staff found the aging effects of the above waste disposal system

component types are consistent with industry experience for these combinations of materials

and environments. The staff found that the applicant had identified the appropriate aging

effects for the materials and environments associated with the above components in the waste

disposal system.

On the basis of its review of the applicant's plant-specific and industry operating experience, the

staff found that loss of material for component types in the waste disposal system is effectively

managed using the Boric Acid Corrosion Program, Bolting Integrity Program, One-Time

Inspection Program, Water Chemistry Control Program, Systems Monitoring Program, Periodic

Surveillance and Preventive Maintenance Program, and Closed-Cycle Cooling Water System

Surveillance Program. Therefore, the staff found that management of loss of materials in the

waste disposal system using these programs is acceptable.

3.3.2.3.6 Service Water System - Aging Management Evaluation - Table 3.3.2-5

The staff reviewed LRA Table 3.3.2-5, which summarizes the results of AMR evaluations for the

service water system component groups.

The service water system experiences loss of material of carbon and low-alloy steel, stainless

steel, cast iron, copper alloy (Zn<l 5%), CASS, and copper alloy (Zn>1 5%) for the following

component types:

* CS components * heaters and coolers

* expansion joints * hose reel

* filters and strainers * restricting orifices

* fasteners and bolting * sight glass

* flow elements * radiation monitor

* flow indicators * instrument valve assemblies

* heat exchangers * piping and fittings

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* pump casings * valve bodies

* thermowells

For those components requiring staff review, the environments are listed below:

* borated water leaks (external) * indoor - wetted (external)

* raw water (velocity)(internal) * buried (external) * raw water - submerged (external) * containment (external)

* raw water (internal) * indoor - no air conditioning (external)

* raw water - stagnant (internal)

The staff evaluation with respect to component environments listed as "not applicable" and loss

of preload for closure bolting are discussed under the general RAls in SER Section 3.3.2.3.

The applicant proposed to manage the service water system loss of material aging effect by

using the Boric Acid Corrosion Program, Fire Protection Program, Buried Services Monitoring

Program, Periodic Surveillance and Preventive Maintenance Program, Systems Monitoring

Program, Bolting Integrity Program, and Open-Cycle Cooling (Service) Water System Surveillance Program. The staff's evaluations of these programs are documented in

Sections 3.0.3.2.6, 3.0.3.2.10, 3.0.3.2.7, 3.0.3.3.1, 3.0.3.3.2, 3.0.3.2.4, and 3.0.3.2.14,

respectively.

During the audit, the staff noted that the applicant used Note B for loss of material of copper

alloy (Zn<155%) and copper alloy (Zn>15%) for the valve bodies line item. Note B indicates that

the component, material, environment, aging effect, and program are consistent with

NUREG-1 801 with minor exceptions. However, the GALL Report reference does not include

copper alloys. The applicant was asked to provide clarification. The applicant stated that

although NUREG-1 801 Volume 2, reference VIl.C1.2-a cited materials that include bronze and

aluminum bronze, it does not specifically cite copper alloy. The applicant stated that Note F,

which indicates material not in NUREG-1 801 for this component, should be used. In its letter,

dated July 12, 2004, the applicant stated that it will change the note from B to F,5 in the 2005

LRA update. On this basis, the staff found this change acceptable.

During the audit, the staff noted that the applicant lists numerous line items that define

components in an indoor with no air conditioning or external containment environment, and

credited the Open-Cycle Cooling (Service) Water System Surveillance Program, for managing the loss of material aging effect. The Open-Cycle Cooling (Service) Water System Surveillance

Program description indicates the program is intended to manage loss of material on the

internal surfaces of these components. The applicant was requested to explain how the

Open-Cycle Cooling (Service) Water System Surveillance Program manages the loss of

material of external surfaces of carbon steel thermowells in these external environments.

By letter, dated July 12, 2004, the applicant stated that for external surfaces the Systems

Monitoring Program provides for visual inspections and monitoring of external surfaces of

piping, tanks, and other components and equipment, for leakage and evidence of material

degradation. These inspections and monitoring are able to identify the aging effect of concern

(loss of material) on external surfaces, prior to a loss of intended function of these components.

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Furthermore, the applicant stated that the Open-Cycle Cooling (Service) Water System

Surveillance Program and the Fire Protection Program both provide for wall thickness

assessments (looking for this loss of material) to be performed. These wall thickness

assessments are typically performed from the outside of the components and, therefore, are

able to detect any external surface degradation. For that reason, these two programs augment

the Systems Monitoring Program for managing loss of material on the external surfaces of

components within the service water system and the fire protection system.

Therefore, the Systems Monitoring Program, augmented in selected cases by the Open-Cycle

Cooling (Service) Water System Surveillance Program, or the Fire Protection Program,

provides adequate assurance that loss of material on the external surfaces of components will

be managed for the period of extended operation. The staff found this acceptable because the

implementation of these programs is expected to ensure management of aging effects on

external surfaces on these components.

During the audit, the staff also noted that GALL AMP XL.M33, "Selective Leaching of Materials,"

indicates the susceptibility of cast iron to the aging effect of selective leaching when exposed to

a raw water environment. The Open-Cycle Cooling (Service) Water System Surveillance

Program is credited with managing the loss of material, but selective leaching is not defined as

an aging effect of cast iron pump casing or valve bodies in a submerged raw water

environment. The applicant was requested to clarify why this aging effect is not Identified for

this material, environment, and aging management program combination. The applicant stated

that selective leaching was identified as a potential aging effect. The Open-Cycle Cooling

(Service) Water System Surveillance Program will be revised to credit the One-Time Inspection

Program to identify selective leaching for these components. In its letter dated

October 15, 2004, the applicant committed to include, under the One-Time Inspection Program,

visual inspections and hardness measurements to identify selective leaching of susceptible

components.

On the basis of its review of the applicant's programs, and plant-specific and industry operating

experience, the staff found that loss of material for component types in the service water

system are effectively managed using the Boric Acid Corrosion Program, Fire Protection

Program, Buried Services Monitoring Program, Periodic Surveillance and Preventive

Maintenance Program, Systems Monitoring Program, Bolting Integrity Program, and

Open-Cycle Cooling (Service) Water System Surveillance Program. Therefore, the staff found

that management of loss of materials in the service water system using these programs is

acceptable.

The applicant proposed to manage loss of heat transfer due to fouling of copper alloy (Zn<15%)

for component type of heater/coolers exposed to indoor - wetted (external) and raw water

(velocity) environments using the Open-Cycle Cooling (Service) Water System Surveillance

Program and Periodic Surveillance and Preventive Maintenance Program.

The staff reviewed the applicant's Open-Cycle Cooling (Service) Water System Surveillance

Program and Periodic Surveillance and Preventive Maintenance Program and its evaluations

are documented in SER Sections 3.0.3.2.14 and 3.0.3.3.1, respectively. On the basis of its

review of the applicant's programs, and plant-specific and industry operating experience, the

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staff found that loss of heat transfer due to fouling for component types in the service water

system is effectively managed using the Open-Cycle Cooling (Service) Water System

Surveillance Program and Periodic Surveillance and Preventive Maintenance Program.

Therefore, the staff found that management of loss of heat transfer due to fouling in the service

water system using these programs is acceptable.

In LRA Table 3.3.2-5 the applicant stated that change in material properties is identified by the

GALL Report as a potential aging effect for neoprene expansion joints pressure boundaries

exposed to indoor with no air conditioning environment. The applicant's evaluation of plant

locations with neoprene expansion joint pressure boundaries demonstrated that these neoprene

components operate at temperatures less than the 95 OF threshold above which a change in

material properties could occur. Therefore, the applicant concluded that no aging effects are

expected and no aging management programs are required.

The staff agreed with the applicant that operating conditions experienced by these neoprene

expansion joint pressure boundaries are not expected to exceed 95 OF. In addition, the staff

agreed that 95 'F is an appropriate threshold for a maximum operating temperature at which no

material property changes will occur to neoprene seals.

Based on the operating temperature and threshold limit the staff agreed that the neoprene

expansion joint pressure boundaries are not expected to experience material property changes

and, therefore, do not require an AMP.

3.3.2.3.7 Fire Protection System - Aging Management Evaluation - Table 3.3.2-6

The staff reviewed LRA Table 3.3.2-6, which summarizes the results of AMR evaluations for the

fire protection system component groups.

The fire protection system experiences loss of material of carbon and low-alloy steel, cast iron,

copper alloy (Zn<1 5%), copper alloy (Zn>1 5%), stainless steel and CASS for the following

component types:

* accumulators * hose reel

* cylinders * RCP oil collection

* compressor casing * spray nozzles

* CS components * sprinkler heads

* fasteners and bolting * instrument valve assemblies

* filters and strainers * piping and fittings

* fire hydrant * pump casings

* flame arrestors * tanks

* heat exchangers * valve bodies

For those components requiring staff review, the environments are listed below:

* air and gas - wetted * oil and fuel oil (intemal)

(T<1 40 0F)(internal) * treated water - other (stagnant)

* borated water leaks (extemal) (internal)

* oil and fuel oil - pooling (internal) * buried (external)

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* raw water (stagnant)(intemal) * containment (external)

* outdoor (external) * indoor - 'no air conditioning (external)

The staff evaluation with respect to component environments listed as "not applicable," heat

exchanger inspection frequency for the aging effect of loss of heat transfer due to fouling and

aging effects for neoprene expansion joints are discussed under the general RAls in SER

Section 3.3.2.3.

The applicant proposed to manage the fire protection system loss of material aging effects by

using the Fire Protection Program, Boric Acid Corrosion Program, Bolting Integrity Program,

One-Time Inspection Program, Buried Services Monitoring Program, Fuel Oil Chemistry Control

Program and Systems Monitoring Program. The staff's evaluations of these programs are

documented in SER Sections 3.0.3.2.10,3.0.3.2.6, 3.0.3.2.4, 3.0.3.2.13, 3.0.3.2.7,3.0.3.2.12,

and 3.0.3.3.2, respectively.

The staff's review of LRA Table 3.3.2-6 identified areas in which additional information was

necessary to complete the review of the applicant's results. The applicant responded to the

staff's RAls as discussed below.

RAI 3.3.2.1.6-1. LRA Table 3.3.2-6 refers to Notes J and 5 which describe the AMPs for certain

fire protection component types as listed in the table. In RAI 3.3.2.1.6-1, dated

September 10, 2004, the staff requested the applicant to provide justification for the conclusion

specified in Note 5 that "the aging management program(s) referenced are appropriate for the

aging effects identified and provides assurance that the aging effects are effectively managed

through the period of extended operation."

In its response, dated October 8, 2004, the applicant stated that Note J was used whenever a

line item could not be matched to any corresponding NUREG-1801, Generic Aging Lessons

Learned Report line item. Note 5 simply indicates that, in the applicant's judgment, the

program identified would adequately manage the referenced aging effect through the period of

extended operation. The justification that the individual identified programs are capable of

adequately managing the aging effect is contained in the applicable program descriptions found

in LRA Appendix B.

The staff found the applicant's response to RAI 3.3.2.1.6-1 unacceptable. The applicant's

response indicates, based on its judgment, that because the AMP for fire protection system

components corresponds to Note 5 in LRA Table 3.3.2-6 it is capable of Adequately managing

the aging effect. The staff concluded that the applicant should address the applicable program

for fire protection system components that corresponds to Notes J and 5 in LRA Table 3.3.2-6

to adequately manage the aging effect.

During a meeting, on February 15, 2005, the staff indicated and the applicant agreed that this

response required further clarification. The staff indicated that it is unclear where in the LRA

the AMPs of certain fire protection components are evaluated. The applicant explained that

LRA Section B2.1.10 identified the appropriate AMP to manage loss of material to the fire

protection system components exposed to the environment.

In its response to RAI B2.1.7-1, a clarification letter, dated March 15, 2005, the applicant

provided new commitments regarding the fire protection system's piping inspection and the

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Buried Services Monitoring Program. The applicant stated that a susceptible location in the fire

protection system (i.e., uncoated/unwrapped piping) will be scheduled to be inspected once

prior to the period of extended operation and at least every 10 years during the period of

extended operation. Based upon findings from these fire protection systems inspections,

additional inspection locations could include coated and/or uncoated buried piping in the fire

protection system, service water system, and fuel oil system. The staff believes that the

applicant's response to RAI B2.1.7-1 addressed the concern described in RAI 3.3.2.1.6-1.

Furthermore, the Region IlIl staff found, as documented in its inspection report dated

May 2, 2005, that the Buried Services Monitoring Program will provide reasonable assurance

that the aging effects will be managed so that the buried service water, fuel oil, and fire

protection system components will continue to perform their intended function consistent with

the CLB during the period of extended operation.

In addition, the staff reviewed LRA Section B2.1.10 and found that the AMP is consistent with

GALL Chapter XL.M26, "Fire Protection," Chapter XL.M27 "Fire Water System," with certain

enhancements and exceptions. The enhancements include revision to various existing

implementing documents to add specific inspections, monitoring and trending requirements,

and/or frequency adjustment based on operating experience. Additionally, the applicant

committed to create new implementing documents for inspections of selected components and

portions of fire suppression piping. The staff considered these types of enhancements as

administrative, and not requiring staff review.

The staff reviewed the exceptions and its justifications associated with GALL Chapter XI.M26,

Chapter XL.M27, and ISG-04 to evaluate whether the AMPs remain adequate to manage the

aging effects for the fire protection system components. The staff noted that ISG-04 did not

affect fire protection AMP elements and the applicant conservatively applied the exceptions to

its Fire Protection Program.

Based on its review and the above discussion, the staff found the applicant's AMP for fire

protection with certain enhancements and exceptions with GALL Chapter XL.M26, Chapter

XL.M27, and ISG-04 is adequate to manage the aging effects for the period of extended

operation as required by 10 CFR 54.21 (a)(3). Therefore, the staff's concern described in

RAI 3.3.2.1.6-1 is resolved.

On the basis of its review of the applicant's plant-specific and industry operating experience, the

staff found that loss of material for component types in the fire protection system are effectively

managed using the Fire Protection Program, Boric Acid Corrosion Program, Bolting Integrity

Program, One-Time Inspection Program, Buried Services Monitoring Program, Fuel Oil

Chemistry Control Program and Systems Monitoring Program. Therefore, the staff found that

management of loss of materials in the fire protection system using these programs is

acceptable.

In LRA Table 3.3.2-6, the applicant stated that change in material properties is identified by the

GALL Report as a potential aging effect to neoprene expansion joint pressure boundaries

exposed to an indoor with no air conditioning environment. The applicant stated that it has

performed a plant temperature survey and demonstrated that the areas where these neoprene

seals exist do not reach temperatures above the 95 OF threshold at which neoprene could

exhibit aging effects. Therefore, the applicant concluded in its LRA that no aging effects are

expected and that no aging management programs are required.

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The staff agreed with the applicant that operating conditions experienced by these neoprene

expansion joint pressure boundaries do not exceed 95OF. In addition, the staff agreed that

95 OF, according to industry practice, is an appropriate threshold for a maximum operating

temperature at which no material property changes will occur to neoprene seals.

Based on the operating temperature and threshold limit, the staff agreed that the neoprene

expansion joint pressure boundaries are not expected to experience material property changes

and, therefore, do not require an aging management program. Additional discussion regarding

the aging effects of neoprene expansion joints is documented under general RAls in SER

Section 3.3.2.3.

The applicant proposed to manage loss of heat transfer due to fouling of copper alloy (Zn<1 5%)

material for component type the heater exchangers exposed to treated water - other (stagnant)

and raw water (stagnant) environment using the Fire Protection Program.

The staff reviewed the applicant's Fire Protection Program and its evaluation is documented in

SER Section 3.0.3.2.10. On the basis of its review of the applicant's plant-specific and industry

operating experience, the staff found that loss of heat transfer due to fouling for component

types in the fire protection system is effectively managed using the Fire Protection Program.

On this basis, the staff found that management of loss of heat transfer due to fouling in the fire

protection system is acceptable.

In LRA Table 3.3.2-6, the applicant stated that cracking due to SCC is identified by the GALL

Report as a potential aging effect of CASS material for the component type valve bodies

pressure boundaries exposed to oil and fuel oil - pooling environment. The applicant stated that

its operating experience has shown no aging effects are expected and no management

programs are required. The plant-specific note associated with this AMR line item stated that

SCC is not a concern for this material/environment group, due to temperatures being less than

140 OF. This is the threshold for SCC that the staff uses in the GALL Report for CASS.

The staff reviewed the information provided in the LRA, assessed the plant operating

experience, and reviewed the 140OF threshold suggested by the applicant. The staff agreed

that the threshold limit of 140OF is an acceptable threshold below which SCC in CASS will not

occur. Furthermore, the PBNP operating experience supports that SCC is not occurring in

these CASS components. On these bases, the staff found the applicant's conclusion

acceptable.

During the audit, the staff noted that the LRA identified cast iron components in the fire

protection system as being monitored by the Fire Protection Program and Systems Monitoring

Program. Neither of these programs monitors for selective leaching of cast iron.

The applicant stated under the One-Time Inspection Program that another metal that is

susceptible to selective leaching is gray cast iron, which can display this type of aging

mechanism even in relatively mild environments. Therefore, this program includes a one-time

visual inspection of selected components that may be susceptible to selective leaching. The

inspection may include hardness measurements. The one-time inspections will determine

whether loss of material due to selective leaching is occurring, and whether the process will

affect the ability of the components to perform their intended function(s) for the period of

extended operation. A sample of the components (such as piping, valve bodies and bonnets,

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pump casings, and heat exchanger components), whose materials of construction may include

cast iron, brass, bronze, or aluminum bronze, that are exposed to raw water, treated water, or

groundwater environment that may lead to selective leaching will be selected for inspection.

RAI B2.1.13-1. In RAI B2.1.13-1, dated September 16, 2004, the staff requested the applicant

to provide justification of why a hardness test one-time inspection for selective cast iron

components in the fire protection system should not be performed. In its response, dated

October 15, 2004, the applicant committed as follows:

As part of LRA Section B2.1.13, One-Time Inspection Program, a one-time

visual inspection and hardness measurement will be performed on accessible

locations of a set of components of each material type (ie., cast iron and brass)

to determine whether selective leaching has occurred and whether the resulting

loss of strength and/or material will affect the intended functions of these

components during the period of extended operation.

The Fire Protection Program and the Systems Monitoring Program will be revised to credit the

One-Time Inspection Program to identify selective leaching for these components. The

One-Time Inspection Program includes a visual inspection and hardness measurement to

identify selective leaching of susceptible components. On the basis of its review and the above

discussion, the staff found that the aging management of the fire protection system using these

programs is acceptable. The staff concern described in RAI B2.1.13-1 is resolved.

During the audit, the staff noted that the LRA Table 3.3.2-6 stated that, for fire system heat

exchangers, the heat transfer function for copper alloy has no external environment or aging

effect. Typically there is a raw water environment (service water) or treated water environment

(CCW) coolant medium on the shell side of the heat exchanger, which promotes scaling. Significant scaling would prevent the heat transfer function. The heat transfer function is used

to monitor the aging effect of scaling. The applicant was requested to identify the environment

for the external portion of the heat exchanger tubes. The applicant stated that this, as well as

several other similar items in the LRA, is an anomaly associated with how the LRA database

identifies environments. Because the "extemal" environment of the heat exchanger tubes is

also the uinternar environment of the heat exchanger, the applicant chose to identify the

environment only once (e.g., internal environment of the heat exchanger).

On the basis of its review, the staff found this approach acceptable because the applicant had

appropriately identified the environment. Additional discussion regarding the aging effects of

loss of heat transfer due to fouling is documented under general RAls in SER Section 3.3.2.3.

3.3.2.3.8 Emergency Power System - Aging Management Evaluation - Table 3.3.2-7

The staff reviewed LRA Table 3.3.2-7, which summarizes the results of AMR evaluations for the

emergency power system component groups.

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The emergency power system experiences loss of material of carbon and low-alloy steel,

stainless steel, aluminum, cast iron, copper alloy (Zn<15%), CASS, and copper alloy (Zn>15%)

for the following component types:

0

0

a

0

S

0

0

air motor

drain trap

fan and blower housing

flame arrestors

instrumentation

silencer

tanks

turbine casing

turbo-charger

expansion joints filters and strainers

fasteners and bolting

* flow elements

* flow indicators

* heat exchangers

* heaters

* coolers

* restricting orifices

* sight glass

* instrument valve assemblies

* piping and fittings

* pump casings

* valve bodies

For those components requiring staff review, the environments are listed below:

* air and gas - wetted

(Tc1 40 1F)(internal)

* oil and fuel oil - pooling (intemal)

* treated water - other (stagnant)

(intemal)

* outdoor (external)

* oil and fuel oil (internal)

* raw water (intemal)

* buried (external)

* indoor - no air conditioning (external)

The staff evaluation with respect to component environments listed as "not applicable," loss of

preload for closure bolting, aging effects for neoprene expansion joints, and heat exchanger

inspection frequency for the aging effect loss of heat transfer due to fouling, are discussed

under the general RAls in SER Section 3.3.2.3.

The applicant proposed to manage the emergency power system loss of material aging effects

by using the Buried Services Monitoring Program, Periodic Surveillance and Preventive

Maintenance Program, Systems Monitoring Program, One-Time Inspection Program, Fuel Oil

Chemistry Control Program, Bolting Integrity Program, Open-Cycle Cooling (Service) Water

System Surveillance Program, Tank Internal Inspection Program, and Closed-Cycle Cooling

Water System Surveillance Program. The staff's evaluations of these programs are

documented in SER Sections 3.0.3.2.7, 3.0.3.3.1, 3.0.3.3.2, 3.0.3.2.13, 3.0.3.2.12, 3.0.3.2.4,

3.0.3.2.14, 3.0.3.3.3, and 3.0.3.2.9, respectively.

The staff's review of LRA Table 3.3.2-6 identified an area in which additional information was

necessary to complete the review of the applicant's results. The applicant responded to the

staff's RAI as discussed below. - - s

RAI 3.3-4. LRA Table 3.3.2-7 identifies no aging effects for carbon/low-alloy stee tanks in a

concrete external environment. The staff noted that concrete has a high pH, whioh it a natural

inhibitor for steel; however, concrete contaminated with chlorides or concrete in cqntact with

acidic water will be subject to loss of material due to general, pitting, and crevice corrosion. In

RAI 3.3-4, dated November 18, 2004, the staff requested the applicant to state the specific

tanks, location and external environment. The staff also requested the applicant to describe

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how the concrete interfaces with the tanks and to discuss if chlorides or acidic water can be

present in this environment.

In its response, dated January 7, 2005, the applicant stated:

The tanks referenced in Table 3.3.2-7 are fuel oil storage tanks, T-1 75A & B, reference

drawings LR-M-219 Sheet 2 and Sheet 3. These tanks were installed via a modification

to add two additional diesel generators in 1995. The 35,000 gallon carbon steel tanks

were installed in a below-grade vault that was backfilled with concrete and are part of

the diesel building structure. The concrete filled vault is not expected to see any ground

water infiltration. The ground and lake water has been analyzed for pH, chlorides, and

sulfates and has been determined to be non-aggressive. The tanks are provided with a

secondary containment, leak detection system. The tanks were covered with a high

density polyethylene (HDPE) membrane system (40 mil thickness) manufactured by

Gundle Lining Systems Inc., Houston, Texas. The membrane was applied to the tank

before the tank was set in place and the placement of the concrete fill. Because of the

membrane/liner the concrete is not in direct contact with the steel and therefore, chloride

contamination is not possible. Associated with the membrane/liner is a collection box

and piping routed to the building's collection/leakage detection system as shown on

drawing LR-M-21 9, Sheet 2. The tank membrane/liner is monitored weekly for oil and/or

water effluent to the building sump. The carbon steel tanks are not subject to chlorides

or acidic water and therefore, have no aging effects requiring aging management.

The staff found the applicant's response acceptable because the applicant provided satisfactory

explanation of why the carbon steel tanks would not be subject to chlorides or acidic water and

would not require aging management. The staff's concern described in RAI 3.3-4 is resolved.

On the basis of its review and RAI response, the staff found the aging effects of the above

emergency power system component types are consistent with industry experience for these

combinations of materials and environments. The applicant provided a satisfactory explanation

of why the carbon steel tanks would not be subject to chlorides or acidic water and would not

require aging management. The staff found that the applicant identified the appropriate aging

effects for the materials and environments associated with the above components in the

emergency power system.

The applicant proposed to manage loss of heat transfer due to fouling for copper alloy

(Zn<15%), stainless steel, and copper alloy (Zn>15%) materials for component type of heat

exchangers and heater/coolers exposed to indoor with no air conditioning, raw water, wetted air

and gas with temperature less than 140 'F, oil and fuel, outdoor, and stagnant treated water

environment using the One-Time inspection Program, Closed-Cycle Cooling Water System

Surveillance Program, Open-Cycle Cooling (Service) Water System Surveillance Program, and

Periodic Surveillance and Preventive Maintenance Program.

During the audit, the staff noted that LRA Table 3.3.2-7 identified heat exchangers in the

emergency power system that experience the aging effect of loss of heat transfer due to fouling

when exposed to an internal environment of wetted air and gas with temperatures less than

140 "F. The applicant credited the Periodic Surveillance and Preventive Maintenance Program

for managing the identified aging effects.

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The staff also noted that the applicant's Periodic Surveillance and Preventive Maintenance -

Program stated that "the condition of selected structures and components is monitored through

inspection, examination, or testing for evidence of age-related degradation on a specified

frequency based on operating experience or other requirements (e.g., Technical Specification

or ASME Code requirements). Certain components are also replaced on a given frequency

based on operating experience."

As documented in the audit and review report, the applicant was requested to provide the

technical basis for crediting the Periodic Surveillance and Preventive Maintenance Program for

maintaining the heat transfer function. The applicant stated that a functional test of the heat

exchanger to confirm proper heat transfer is not practical. The Periodic Surveillance and

Preventive Maintenance Program performs visual inspections of the heat exchanger to ensure

surfaces are clean of scaling on other deposits that would negatively impact the heat transfer

function. Other components (e.g., diesel generators managed by the Closed-Cycle Cooling

Water Surveillance Program) rely on functional tests of the component systems to ensure

adequate heat transfer. The applicant also stated that its operating experience also supports

this evaluation. On the basis of its review, the staff found this approach acceptable because

visual inspections and functional tests are expected to ensure to ensure proper aging

management of the heat transfer function of these components.

On the basis of its review of the applicant's plant-specific and industry operating experience, the

staff found that loss of heat transfer due to fouling for component types in the emergency power

system is effectively managed using the Closed-Cycle Cooling Water System Surveillance

Program, Open-Cycle Cooling (Service) Water System Surveillance Program, One-Time

Inspection Program, and Periodic Surveillance and Preventive Maintenance Program.

Therefore, the staff found that management of loss of heat transfer due to fouling in the

emergency power system using these programs is acceptable.

In LRA Table 3.3.2-7, the applicant stated that change in material properties due to elevated

temperatures, cracking due to ultraviolet radiation, and ozone are identified by the GALL Report

as potential aging effects to neoprene and elastomer expansion joint pressure boundaries

exposed to indoor with no air conditioning and air and gas with wetted with temperature less

than 140 *F environments. As stated in LRA Note 16, the applicant verified through specific

studies of plant locations that the PBNP components are indoors and not subject to UV or

ozone, nor are they in locations that are subject to radiation exposure. The plant-specific

studies also verified that the locations identified in the AMR line items are also not subject to

temperatures where change in material properties or cracking could occur (greater than 95 'F).-

The staff reviewed the plant-specific operating history and plant-specific studies conducted by

the applicant. On the basis of its review and the above discussion, the staff concluded that no

aging effects are expected and no management programs are required. Additional discussion

regarding aging effects of neoprene expansion joints is documented under general RAls in SER

Section 3.3.2.3.

In LRA Table 3.3.2-7, the applicant stated that cracking due to SCC is identified by the GALL

Report as a potential aging effect of stainless steel material for component type of flow element

pressure boundaries exposed to oil and fuel oil in a pooling environment. The applicant stated

that its operating experience has shown no aging effects are expected and no management

programs are required.

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As documented in the audit and review report, the applicant stated that it verified that the

operating temperature's conditions for the locations identified by the AMR line items are less

then 140 OF; therefore, SCC is not an aging concern for the emergency power system.

The staff reviewed the plant-specific operating history and studies conducted by the applicant.

On the basis of its review and the above discussion, the staff concluded that no aging effects

are expected and no management programs are required.

3.3.2.3.9 Containment Ventilation System - Aging Management Evaluation - Table 3.3.2-8

The staff reviewed LRA Table 3.3.2-8, which summarizes the results of AMR evaluations for the

containment ventilation system component groups.

The containment ventilation system experiences loss of material of carbon and low-alloy steel

and copper alloy (Zn<1 5%) for the following component types:

* accumulators and cylinders * heat exchangers

* CS components * heaters and coolers

* damper housing * piping and fittings

* ductwork * thermowells

* fan and blower housing * valve bodies

* fastener and bolting * filters and strainers

For those components requiring staff review, the environments are listed below:

* containment (external)

* borated water leaks (external)

* indoor - wetted (external)

* raw water (internal)

* indoor - no air conditioning (external)

The staff evaluation with respect to loss of preload for closure bolting is discussed under the

general RAls in SER Section 3.3.2.3.

The applicant proposed to manage the containment ventilation loss of material aging effects by

using the Boric Acid Corrosion Program, Systems Monitoring Program, Bolting Integrity

Program, and Open-Cycle Cooling (Service) Water System Surveillance Program. The staff's

evaluations of these programs are documented in SER Sections 3.0.3.2.6, 3.0.3.3.2, 3.0.3.2.4,

and 3.0.3.2.14, respectively.

The staff found that the applicant identified the appropriate AMPs for the materials and

environments associated with the above components in the containment ventilation system.

The applicant proposed to manage loss of heat transfer due to fouling on HX copper alloy

(Zn<1 5%) materials for component types of heat exchangers, heaters and coolers exposed to

containment and raw water environment using Open-Cycle Cooling (Service) Water System

Surveillance Program, and Periodic Surveillance and Preventive Maintenance Program.

In LRA Table 3.3.2-8, the applicant identified that heaters/coolers in the containment ventilation

system experience the aging effect of loss of heat transfer due to fouling when exposed to an

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internal environment of raw water and an external environment of containment. The applicant,

in the LRA, credited the Periodic Surveillance and Preventive Maintenance Program for

managing the identified aging effects.

During the review, the staff noted that the applicant's Periodic Surveillance and Preventive

Maintenance Program states that "the condition of selected structures and components is

monitored through inspection, examination, or testing for evidence of age-related degradation

on a specified frequency based on operating experience or other requirements (e.g., Technical

Specification or ASME Code requirements). Certain components are also replaced on a given

frequency based on operating experience." The applicant was asked to provide the technical

basis for crediting this program for maintaining the heat transfer function. The applicant stated

that a functional test of the coolers/heat exchangers/heaters to confirm proper heat transfer is

not practical. The Periodic Surveillance and Preventive Maintenance Program performs visual

inspections of the heat exchangers to ensure surfaces are clean of scaling or other deposits

that would negatively impact the heat transfer function. In addition, the applicant stated that its

operating experience also supports this evaluation. The staff found this approach and the use

of this program as a means of detecting aging effects is acceptable to ensure the proper aging

management of the heat transfer function of these components.

In LRA Table 3.3.2-8, the applicant stated that change in material properties due to elevated

temperatures, cracking due to elevated temperatures, cracking due to ultraviolet radiation, and

ozone are identified by the GALL Report as potential aging effects to elastomer material of

component type valve body exposed to indoor - no air conditioning, air and gas, and

containment environment. As stated in LRA Note 16, the applicant verified through specific

studies of plant locations that the components are indoors and not subject to UV or ozone, nor

are they in locations that are subject to radiation exposure. The plant-specific studies identified

that the locations in the AMR line items are not subject to temperatures where change in

material properties or cracking could occur (greater than 95 OF).

The staff reviewed the plant-specific operating history and plant-specific studies conducted by

the applicant. On the basis of its review, the staff concluded that no aging effects are expected

and no management programs are required.

3.3.2.3.10 Essential Ventilation System - Aging Management Evaluation - Table 3.3.2-9

The staff reviewed LRA Table 3.3.2-9, which summarizes the results of AMR evaluations for the

essential ventilation system component groups.

The essential ventilation system experiences loss of material of carbon and low-alloy steel,

stainless steel, cast iron, and copper alloy (Zn<15 %) for the following component types:

* damper housing * heat exchangers

* ductwork * heater and coolers

* fan and blower housing * piping and fittings

* fasteners and bolting * thermowells

* filters and strainers - pump casing

* flow element * tanks

* humidifiers * valve bodies

* instrument valve assemblies

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For those components requiring staff review, the environments are listed below:

* air and gas - wetted (T<1400F)(intemal)

* treated water - other (internal)

* raw water (velocity)(internal)

* raw water (internal)

* indoor - no air conditioning (external)

The staff evaluation with respect to component environments listed as "not applicable," loss of

preload for closure bolting, and heat exchanger inspection frequency for the aging effect loss of

heat transfer due to fouling are discussed under the general RAls in SER Section 3.3.2.3.

The applicant proposed to manage the essential ventilation loss of material aging effects by

using the One-Time Inspection Program, Periodic Surveillance and Preventive Maintenance

Program, Systems Monitoring Program, Bolting Integrity Program, Open-Cycle Cooling

(Service) Water System Surveillance Program, and Closed-Cycle Cooling Water System

Surveillance Program. The staff's evaluation of these programs are documented in SER

Sections 3.0.3.2.13, 3.0.3.3.1, 3.0.3.3.2, 3.0.3.2.4, 3.0.3.2.14, and 3.0.3.2.9, respectively.

On the basis of its review, the staff found the aging effects of the above essential ventilation

system component types are consistent with industry experience for these combinations of

materials and environments. The staff found that the applicant had identified the appropriate

aging effects for the materials and environments associated with the above components in the

essential ventilation system.

In LRA Table 3.3.2-9, the applicant stated that change in material properties due to elevated

temperatures, cracking due to elevated temperatures, cracking due to ultraviolet radiation, and

ozone are identified by the GALL Report as a potential aging effect of elastomer material for

component type ductwork pressure boundaries exposed to indoor with no air conditioning and

wetted air and gas, temperature less than 140 'F environments. As stated in LRA Note 16, the

applicant verified through specific studies of plant locations that the components are indoors

and not subject to UV or ozone, nor are they in locations that are subject to radiation exposure.

The plant-specific studies also verified that the locations identified in the AMR line items are

also not subject to temperatures where change in material properties or cracking could occur

(greater than 95 OF).

The staff reviewed the plant-specific operating history and plant-specific studies conducted by

the applicant. On the basis of its review, the staff concluded that no aging effects are expected

and no management programs are required.

The applicant proposed to manage loss of heat transfer due to fouling of stainless steel and

copper alloy (Zn<l 5%) materials for component type heat exchangers and heater coolers

exposed to treated water - other, wetted air and gas, temperature less than 140 OF, raw water -

velocity, and raw water environment using the Closed-Cycle Cooling Water System

Surveillance Program, Open-Cycle Cooling (Service) Water System Surveillance Program, and

Periodic Surveillance and Preventive Maintenance Program.

The staff reviewed the applicant's Closed-Cycle Cooling Water System Surveillance Program,

Open-Cycle Cooling (Service) Water System Surveillance Program, and Periodic Surveillance

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and Preventive Maintenance Program. The staff evaluations of these programs are

documented in SER Sections 3.0.3.2.9, 3.0.3.3.14, and 3.0.3.3.1, respectively.

On the basis of its review of the applicant's plant-specific and industry operating experience, the

staff found that loss of heat transfer due to fouling for component types in the essential

ventilation system are effectively managed using Closed-Cycle Cooling Water System

Surveillance Program, Open-Cycle Cooling (Service) Water System Surveillance Program, and

Periodic Surveillance and Preventive Maintenance Program. Therefore, the staff found that

management of loss of heat transfer due to fouling in the essential ventilation system using

these programs is acceptable.

3.3.2.3.11 Plant Sampling System - Aging Management Evaluation - Table 3.3.2-10

The staff reviewed LRA Table 3.3.2-1 0, as modified by letter dated April 29, 2005, which

summarizes the results of AMR evaluations for the plant sampling system component groups.

In the original LRA Table 3.3.2-10, the applicant stated that those few components from the

plant sampling system requiring aging management had been addressed under the reactor

coolant system, residual heat removal system, chemical volume and control system, and the

component cooling water system. The staff's evaluations of these systems are documented in

SER Sections 3.1.2.3.1, 3.2.2.3.4, 3.3.2.3.2, and 3.3.2.3.3, respectively.

As a result of the methodology changes, more components within the plant sampling system

are now considered within the scope of license renewal. The newly identified components

include the tubing runs and valves from containment isolation valves or various sample

locations to the primary sample room. The inclusion of these components resulted in the

creation of a new LRA Table 3.3.2-10. However, those items originally covered in other

interfacing systems were left in those other systems.

The plant sampling system experiences loss of material of stainless steel for the following

component types:

* filters and strainers * restricting orifices

* level gauges * tanks

* piping and fittings * valve bodies

For those components requiring staff review, the environments are listed:

* treated water - secondary (Tc1 20 0F)(internal)

* treated water - secondary (T>1200F)(internal)

* treated water - borated (T<140 °F)(internal)

* treated water - primary (140 F<T<480OF)(intemal)

The applicant proposed to manage the plant sampling system loss of material aging effects by

using the One-Time Inspection Program and Water Chemistry Control Program. The staff's

evaluations of these programs are documented In SER Section 3.0.3.2.13 and 3.0.3.2.20,

respectively.

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On the basis of its review, the staff found the aging effects of the above plant sampling system

component types consistent with industry experience for those combinations of materials and

environments. The staff found that the applicant had identified the appropriate aging effects for

the above materials and environments.

In the revised LRA Table 3.3.2-10, the applicant stated that cracking due to SCC is identified as

a potential aging effect for stainless steel material for component types of piping, fittings and

valve bodies exposed to primary treated water for temperatures between 140 OF and 480 OF

and secondary treated water for temperatures greater than 120 OF. The applicant also stated

that the One-Time Inspection Program and the Water Chemistry Control Program are used for

managing this aging effect.

The staff reviewed the One-Time Inspection Program and the Water Chemistry Control

Program and its evaluations are documented in SER Section 3.0.3.2.13 and 3.0.3.2.20,

respectively.

On the basis of its review of the applicant's plant-specific and industry operating experience, the

staff found that cracking due to SCC for component types in the plant sampling systems is

adequately managed by using the One-Time Inspection Program and the Water Chemistry

Control Program.

3.3.2.3.12 Plant Air System - Aging Management Evaluation - Table 3.3.2-11

The staff reviewed LRA Table 3.3.2-11, which summarizes the results of AMR evaluations for

the plant air system component groups.

The plant air system experiences loss of material of carbon and low-alloy steel, stainless steel,

cast iron, copper alloy (Zn>15%), and copper alloy (Zn<15%) for the following component

types:

* accumulators and cylinders * piping and fittings

* compressor casings * tanks

* CS components * valve bodies

* fasteners and bolting

For those components requiring staff review, the environments are listed below:

* containment (external)

* borated water leaks (external)

* air and gas - wetted (T<1 40 0F)(internal)

* indoor - no air conditioning (external)

The staff evaluation with respect to loss of preload for closure bolting is discussed under the

general RAls in SER Section 3.3.2.3.

The applicant proposed to manage the plant air system loss of material aging effects by using

the Boric Acid Corrosion Program, Periodic Surveillance and Preventive Maintenance Program,

Systems Monitoring Program, and Bolting Integrity Program. The staff's evaluations of these

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programs are documented in SER Sections 3.0.3.2.6, 3.0.3.3.1, 3.0.3.3.2, and 3.0.3.2.4,

respectively.

On the basis of its review, the staff found the aging effects of the above plant air system

component types are consistent with industry experience for these combinations of materials

and environments. The staff found that the applicant had identified the appropriate aging

effects for the materials and environments associated with the above components in the plant

air system.

During the review, the staff noted that the applicant also stated, in LRA Table 3.3.2-11, that a

cast iron compressor exposed to an air/gas internal environment experiences no aging effects

and no aging management program is required. The applicant was requested to provide the

technical basis for not considering any aging effect or aging management program for this

specific materiaVenvironment. The applicant stated that the component was the charging pump

speed controller backup compressor; and that although its plant-specific operating experience

supports no aging effects for this component, the applicant acknowledged that the component

is susceptible to general corrosion for cast iron in an air and gas (not dried) environment. The

applicant also stated that it will revise the aging management review results to identify the aging

effect loss of material (due to general corrosion) and identify Periodic Surveillance and

Preventive Maintenance Program as the applicable aging management program. In its letter

dated July 12, 2004, the applicant committed to revise the aging management review results for

the charging pump speed controller back-up air compressor to include loss of material due to

general corrosion that will be managed by the Periodic Surveillance and Preventive

Maintenance Program. The staff found this acceptable because with these changes, proposed

in its letter, the applicant ensures detection and management of loss of material.

Also, the staff noted that, in LRA Table 3.3.2-11, the applicant stated that copper alloy material

for component type valve bodies in an air and gas wetted internal environment experiences loss

of material and the Periodic Surveillance and Preventive Maintenance Program monitors this

aging effect. The notes for this line item indicated that this is consistent with NUREG-1 801 for

material, environment, and aging effect, but a different aging management program is credited.

The notes also stated that the material is not evaluated in NUREG-1801 for this component.

The applicant was requested to provide a justification as to why this is not a contradiction to the

term "consistent with NUREG-1 801." The applicant stated that the note is incorrect and will be

changed to delete Note F, for material not in NUREG-1 801 for this component. By letter dated

July 12, 2004, the applicant committed to correct the notes in the 2005 annual LRA update.

The staff found this acceptable.

3.3.2.3.13 Containment Hydrogen Detectors and Recombiner System - Aging Management

Evaluation - Table 3.3.2-12

The staff reviewed LRA Table 3.3.2-12, which summarizes the results of AMR evaluations for

the containment hydrogen detector and recombiner system component groups.

The containment hydrogen detectors and recombiner system experiences loss of material of

carbon and low-alloy steel for the following component types:

* CS components

* fasteners and bolting

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* piping and fittings

* valve bodies

For those components requiring staff review, the environments are listed below:

* borated water leaks (external)

* indoor - no air conditioning (external)

The staff evaluation with respect to component loss of preload for closure bolting is discussed

under the general RAls in SER Section 3.3.2.3.

The applicant proposed to manage the containment hydrogen detector and recombiner system

loss of material aging effects by using the Boric Acid Corrosion Program, Systems Monitoring

Program, and Bolting Integrity Program. The staff's evaluations of these programs are

documented in SER Sections 3.0.3.2.6, 3.0.3.3.2, and 3.0.3.2.4, respectively.

On the basis of its review, the staff found the aging effects of the above containment hydrogen

detector and recombiner system component types are consistent with industry experience for

these combinations of materials and environments. The staff found that the applicant identified

the appropriate aging effects for the materials and environments associated with the above

components in the containment hydrogen detector and recombiner system.

On the basis of its review of the applicant's plant-specific and industry operating experience, the

staff found that loss of material for component types in the containment hydrogen detector and

recombiner system is effectively managed using the Boric Acid Corrosion Program, Systems

Monitoring Program, and Bolting Integrity Program. Therefore, the staff found that

management of loss of material in the containment hydrogen detector and recombiner system

using these programs is acceptable.

3.3.2.3.14 Circulating Water System - Aging Management Evaluation - Table 3.3.2-13

The staff reviewed LRA Table 3.3.2-13, which summarizes the results of AMR evaluations for

the circulating water component groups.

The circulating water system experiences loss of material of carbon and low-alloy steel and cast

iron for the following component types:

* fasteners and bolting

* piping and fittings

* pump casing

* valve bodies

For those components requiring staff review, the environments are listed below:

* indoor - no air conditioning (external)

* raw water (internal)

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The staff evaluation with respect to component loss of preload for closure bolting and aging

effects for neoprene expansion joints is discussed under the general RAls in SER *

Section 3.3.2.3.

The applicant proposed to manage the circulating water system loss of material aging effects

by using the Systems Monitoring Program, Periodic Surveillance and Preventive Maintenance

Program, and Bolting Integrity Program. The staff's evaluations of these programs are

documented in SER Sections 3.0.3.3.2, 3.0.3.3.1 and 3.0.3.2.4, respectively.

On the basis of its review, the staff found the aging effects of the above circulating water

system component types are consistent with industry experience for these combinations of

materials and environments. The staff found that the applicant identified the appropriate aging

effects for the materials and environments associated with the above components in the

circulating water system.

On the basis of its review of the applicant's plant-specific and industry operating experience, the

staff found that loss of material for component types in the circulating water system are

effectively managed using the Systems Monitoring Program, Periodic Surveillance and

Preventive Maintenance Program, and Bolting Integrity Program. Therefore, the staff found

that management of loss of material in the circulating water system using these programs is

acceptable.

3.3.2.3.15 Treated Water System - Aging Management Evaluation - Table 3.3.2-14

The staff reviewed LRA Table 3.3.2-14, as modified by letter dated April 29, 2005, which.

summarizes the results of AMR evaluations for the treated water system component groups.

The treated water system experiences loss of material of carbon and low-alloy steel, copper

alloy (Zn<l 5%), stainless steel, and CASS for the following component types:

* CS components * heat exchangers

* fasteners and bolting * piping and fittings

* filters and strainers * valve bodies

For those components requiring staff review, the environments are listed below:

! borated water leaks (extemal)

! raw water drainage (internal)

* treated water - other (internal)

* indoor - no air conditioning (external)

The staff evaluation with respect to component loss of preload for closure bolting is discussed

under the general RAls in SER Section 3.3.2.3.

The applicant proposed to manage the treated water system loss of material aging effects by

using the Bolting Integrity Program, Boric Acid Corrosion Program, One-Time Inspection

Program, and Systems Monitoring Program. The staff's evaluations of these programs are

documented in SER Sections 3.0.3.2.4, 3.0.3.2.6, 3.0.3.2.13 and 3.0.3.3.2, respectively.

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The staff's review of LRA Table 3.3.2-14 identified an area in which additional information was

necessary to complete the review of the applicant's results. The applicant responded to the

staff's RAI as discussed below.

RAI 3.3-3. LRA Table 3.3.2-14 identifies loss of material as an aging effect of carbon steel

piping and fittings, and valve bodies in a raw water drainage (internal) environment. The

applicant identifies the One-Time Inspection Program, B2.1.13, to manage this aging effect.

The GALL Report, XL.M32 recommends one-time inspections where either an aging effect is

not expected to occur but there is insufficient data to completely rule it out, or an aging effect is

expected to progress very slowly. In cases where an aging effect is likely to occur, the GALL

Report recommends periodic inspections. In RAI 3.3-3, dated November 18, 2004, the staff

requested the applicant to justify the use of a One-Time Inspection Program to manage the loss

of material for carbon steel components in a raw water environment since aging effects are

expected to occur in this environment.

In its response, dated January 7, 2005, the applicant stated:

The components in question are drainage and sump pump discharge piping and valves

that are all shown on drawing LR-M-223 Sheet 3, location G-8. The internal

environment is referred to as "Raw Water - Drainage," but this will typically consist of

ground-water coming from the Facade Sumps. Groundwater at PBNP is a

non-aggressive environment (see LRA Table 3.5.0-1, responses to items 12 and 13).

As this is a non-aggressive environment, we would expect any aging effects to proceed

very slowly. Plant operating experience over 34 years of operation has not identified

any leakage from these lines. Based on the non-aggressive environment and our

plant-specific operating experience, the use of one-time inspections to manage this

aging effect was considered acceptable. A one-time inspection will provide ample

indication of the condition of these components prior to the period of extended

operation. Note that the One-Time Inspection Program provides for the option to

change to periodic inspections or provide for repairs based on the results of the

condition assessment after the one-time inspection.

The staff found the applicant's response acceptable. The applicant provided a satisfactory

justification for the use of a one-time inspection to manage loss of material for carbon steel

components in a raw water environment. The staff's concern described in RAI 3.3-3 is

resolved.

On the basis of its review of the applicant's plant-specific and industry operating experience, the

staff found that loss of material for component types in the treated water system are effectively

managed using the Bolting Integrity Program, Boric Acid Corrosion Program, One-Time

Inspection Program, and Systems Monitoring Program. Therefore, the staff found that

management of loss of material in the treated water system using these programs is

acceptable.

3.3.2.3.16 Heating Steam System - Aging Management Evaluation - Table 3.3.2-15

The staff reviewed LRA Table 3.3.2-15, which summarizes the results of AMR evaluations for

the heating steam system component groups. The heating steam system experiences loss of

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material of carbon and low-alloy steel, copper alloy (Zn<1 5%), stainless steel, and cast iron for

the following component types:

* CS components * pump casing

* fasteners and bolting * steam traps

* filters and strainers * tanks

* heaters and coolers * valve bodies

* -piping and fittings

For those components requiring staff review, the environments are listed below:

* borated water leaks (external)

* treated water - secondary (T>1 20 'F)(internal)

* indoor - no air conditioning (external)

The staff evaluation with respect to component loss of preload for closure bolting is discussed

under the general RAls in SER Section 3.3.2.3.

The applicant proposed to manage cracking due to SSC on stainless steel material on

component type of tanks by using the One-Time Inspection Program and Water Chemistry

Control Program.

The applicant proposed to manage the heating steam system loss of material aging effects by

using the Boric Acid Corrosion Program, Bolting Integrity Program, One-Time Inspection

Program, Water Chemistry Control Program, and Systems Monitoring Program. The staff's

evaluations of these programs are documented in SER Sections 3.0.3.2.6, 3.0.3.2.4, 3.0.3.2.13,

3.0.3.3.20, and 3.0.3.3.2, respectively.

On the basis of its review of the information provided in the LRA, the staff found the aging

effects of the above heating steam system component types are consistent with industry

experience for these combinations of materials and environments. The staff found that the

applicant identified the appropriate aging effects for the materials and environments associated

with the above components in the heating steam system.

On the basis of its review of the applicant's plant-specific and industry operating experience, the

staff found that loss of material for component types in the heating steam system are effectively

managed using the Boric Acid Corrosion Program, Bolting Integrity Program, One-Time

Inspection Program, Water Chemistry Control Program, and Systems Monitoring Program.

Therefore, the staff found that management of loss of material in the heating steam system

using these programs is acceptable.

3.3.2.3.17 Fuel Handling System - Aging Management Evaluation - Table 3.3.2-16

The staff reviewed LRA Table 3.3.2-16, which summarizes the results of AMRP evaluations for

the fuel handling system component groups.

In LRA Table 3.3.2-16, the applicant stated that aging management of the fuel handling system

component groups is addressed under the spent fuel cooling system, Units 1 and 2

containment building structure and the primary auxiliary building structure. The staff's

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evaluations of these systems are discussed in SER Sections 3.3.2.3.4, 3.5.2.3.2 and 3.5.2.3.7,

respectively.

3.3.3 Conclusion

On the basis of its review, the staff concluded that the applicant demonstrated that the aging

effects associated with the auxiliary systems components will be adequately managed so that

the intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

The staff also reviewed the applicable FSAR supplement program summaries and concluded

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 and auxiliary steam system

* feedwater and condensate system

* auxiliary feedwater system

3.4.1 Summary of Technical Information In the Application

In LRA Section 3.4, the applicant provided AMR results for steam and power conversion system

components and component groups. In LRA Table 3.4.1, "Summary of Aging Management

Evaluations in Chapter Vill of NUREG-1801 for Steam and Power Conversion System," the

applicant provided a summary comparison of its AMRs with the AMRs evaluated in the GALL

Report for the steam and power conversion system components and component groups.

The applicant's AMRs incorporated applicable operating experience in the determination of

AERM. 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 AERM. The applicant's review of industry operating

experience included a review of the GALL Report and operating experience issues identified

since the issuance of the GALL Report.

3.4.2 Staff Evaluation

The staff reviewed LRA Section 3.4 to determine if the applicant provided sufficient information

to demonstrate that the effects of aging for the steam and power conversion system

components that are within the scope of license renewal and subject to an AMR will be

adequately managed so that the intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

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Also, the staff performed an onsite audit of AMRs to confirm the applicants claim that certain

identified AMRs are consistent with the GALL Report. The staff did not repeat its review of the

matters described in the GALL Report. However, the staff did determine that the material

presented in the LRA was applicable and that the applicant had Identified the appropriate GALL

AMPs. The staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details of

the staff's audit evaluations are documented in the staff's PBNP audit and review report and

summarized in SER Section 3.4.2.1.

The staff also performed an onsite audit of those AMRs that are consistent with the GALL

Report and for which further evaluation is recommended. The staff verified that the applicant's

further evaluations were consistent with the acceptance criteria in NUREG-1 800,

Section 3.4.2.2, "Standard Review Plan for Review of License Renewal Applications for Nuclear

Power Plants,'. dated July 2001. The staff's audit evaluations are documented in the staff's

PBNP audit and review report and summarized in SER Section 3.4.2.2.

The staff performed an onsite audit and conducted a technical review of the remaining AMRs

that were not consistent with the GALL Report. The audit and technical review included

evaluating whether all plausible aging effects had been identified and the aging effects listed

were appropriate for the combination of materials and environments specified. The staff's audit

evaluations are documented in the staff's PBNP audit and review report and summarized in

Section SER 3.4.2.3. The staff's evaluation of its technical review is also documented in SER

Section 3.4.2.3.

Finally, the staff reviewed the AMP summary descriptions in the FSAR supplement to ensure

that they provided an adequate description of the programs credited with managing or

monitoring aging for the steam and power conversion system components.

Table 3.4-1 below provides a summary of the staff's evaluation of components, aging

effects/mechanisms, and AMPs listed in LRA Section 3.4 that are addressed in the GALL

Report.

Table 3.4-1 Staff Evaluation for Steam and Power Conversion System In the GALL Report

Components roup AgXing Effect~ A -tg GALL 0AMP n LRA -Staff Evalfution

-Mechanism RPopo -x

Piping and fittings in Cumulative fatigue TLAA, evaluated TLAA This TLAA is

main feedwater line, damage in accordance with evaluated in

steam line, and 10 CFR 54.21 (c) Section 4.3, Metal

AFW piping (PWR Fatigue (See only) Section 3.4.2.2.1) (Item Number

3.4.1-01)

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Component Group Aging EffectF AMP i LLn LRA ta vluation

____i___________ Mechanism epqt ';

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 One-Time Inspection recommends further

casings, tanks, pitting, and crevice Program, Periodic evaluation. (See

tubes, tubesheets, corrosion Surveillance and Section 3.4.2.2.2)

channel head and Preventive

shell (except main Maintenance

steam system) Program; Tank

(Item Number Interal Inspection

3.4.1-02) nte lInsectioProgram

AFW piping Loss of material Plant-specific Not Applicable Not Applicable (See

(Item Number due to general, Section 3.4.2.2.3)

3.4.1-03) pitting, and crevice :

corrosion, MIC, and

biofouling

Oil coolers in AFW Loss of material Plant-specific Periodic Surveillance Consistent with

system (lubricating due to general and Preventive GALL, which

oil side possibly (carbon steel only), Maintenance recommends further

contaminated with pitting, and crevice Program evaluation. (See

water) corrosion and MIC Section 3.4.2.2.5)

(Item Number

3.4.1-04)

Extemal surface of Loss of material Plant-specific Systems Monitoring Consistent with

carbon steel due to general Program GALL, which

components corrosion recommends further

(Item Number evaluation. (See

3.4.1-05) Section 3.4.2.2.4)

Carbon steel piping Wall thinning due to Flow-accelerated Flow-Accelerated Consistent with

and valve bodies flow-accelerated corrosion Corrosion Program, GALL, which

(Item Number corrosion Water Chemistry recommends no

3.4.1-06) Control Program 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 corrosion One-Time Inspection recommends no

(Item Number Program, Periodic further evaluation.

3.4.1-07) Surveillance and (See

Preventive Section 3A.2.1)

Maintenance

Program

Closure bolting in Loss of material Bolting integrity Bolting Integrity Consistent with

high-pressure or due to general Program GALL, which

high-temperature corrosion; crack recommends no

systems initiation and growth further evaluation.

(Item Number due to cyclic (See

3.4.1-08) loading and/or SCC Section 3.4.2.1)

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C Om Group upGALL Aging _fec0 AMP:In iRA AM'' i Staff E'aluat'io

M ec anism Report _ i;___l;i____t__ _ _ _ _ _ 

Heat exchangers Loss of material Open-cycle Open-Cycle Cooling Consistent with

and due to general cooling water (Service) Water GALL, which

coolers/condensers (carbon steel only), system System Surveillance recommends no

serviced by OCCW pitting, and crevice Program; One-Time further evaluation.

(Item Number corrosion, MIC, and Inspection Program (See 3.4.1-09) biofouling; buildup Section 3.4.2.1) of deposit due to

biofouling

Heat exchangers Loss of material Closed-cycle Not Applicable Not Applicable

and due to general cooling water

coolers/condensers (carbon steel only), system serviced by CCCW pitting, and crevice

(Item Number corrosion

3.4.1-10) . . . .-

External surface of Loss of material Above-ground Not Applicable Not Applicable above-ground CST due to general carbon steel tanks

(Item Number (carbon steel only), 3.4.1-11) pitting, and crevice

corrosion

External surface of Loss of material Buried piping and Not Applicable Not Applicable buried CST and due to general, tanks surveillance (See AFW piping pitting, and crevice or Buried piping Section 3.4.2.2.5) (Item Number corrosion and MIC and tanks

3.4.1-12) . inspection

External surface of Loss of material Boric acid Boric Acid Corrosion Consistent with

carbon steel due to boric acid corrosion Program GALL, which

components corrosion recommends no

(Item Number further evaluation.

3.4.1-13) (See ._ __ .__ _Section 3.4.2.1)

The staff's review of the PBNP steam and power conversion system and associated

components followed one of several approaches. One approach, documented in SER

Section 3.4.2.1, involves 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 SER Section 3.4.2.2,

involves the staff's review of the AMR results for components in the steam and power

conversion system that the applicant indicated are consistent with the GALL Report and for

which further evaluation is recommended. A third approach, documented in SER

Section 3.4.2.3, involves the staff's review of the AMR results for components in the steam and

power conversion system that the applicant indicated are not consistent with the GALL Report

or are not addressed in the GALL Report. The staff's review of AMPs that are credited to

manage or monitor aging effects of the steam and power conversion system components is

documented in SER Section 3.0.3.

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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 LRA Section 3.4.2.1, the applicant

identified the materials, environments, and aging effects requiring management. The applicant

identified the following programs that manage the aging effects related to the main steam, main

feedwater, and emergency feedwater system components:

* Bolting Integrity Program;

* Boric Acid Corrosion Program;

* Flow-Accelerated Corrosion Program;

* One-Time Inspection Program;

* Open-Cycle Cooling (Service) Water System Surveillance Program;

* Periodic Surveillance and Preventive Maintenance Program;

* Systems Monitoring Program;

* Tank Internal Inspection Program; and

* Water Chemistry Control Program.

Staff Evaluation. In LRA Tables 3.4.2-1 through 3.4.2-3, the applicant provided a summary of

AMRs for the main steam, auxiliary steam, main feedwater, auxiliary feedwater, and

condensate system components and identified which AMRs it considered to be consistent with

the GALL Report.

For component groups evaluated in the GALL Report for which the applicant 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 plant-specific

components contained in these GALL Report component groups were bounded by the GALL

Report evaluation.

The applicant provided a note for each AMR line item. The notes described how the

information in the tables aligns with the information in the GALL Report. The staff's audit of

those AMRs with Notes A through E, indicated the AMR was consistent with the GALL Report.

Note A indicated that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the AMP

identified in the GALL Report. The staff audited these line items to verify consistency with the

GALL Report and the validity of the AMR for the site-specific conditions.

Note B indicated that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

AMP identified in the GALL Report. The staff audited these line items to verify consistency with

the GALL Report. The staff verified that the identified exceptions to the GALL AMPs had been

reviewed and accepted by the staff. The staff also determined whether the AMP identified by

the applicant was consistent with the AMP identified in the GALL Report and whether the AMR

was valid for the site-specific conditions.

Note C indicated that the component for the AMR line item, although different, is consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent

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with the AMP identified by the GALL Report. This note indicates that the applicant was unable

to find a listing of some system components in the GALL Report. However, the applicant

identified a different component in the GALL Report that had the same material, environment,

aging effect, and AMP as the component that was under review. The staff audited these line

items to verify consistency with the GALL Report. The staff also determined whether the AMR

line item of the different component was applicable to the component under review and whether

the AMR was valid for the site-specific conditions.

Note D indicated that the component for the AMR line item, although different, is consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP takes some

exceptions to the AMP identified in the GALL Report. The staff audited these line items to

verify consistency with the GALL Report. The staff verified whether the AMR line item of the

different component was applicable to the component under review. The staff verified whether

the identified exceptions to the GALL AMPs had been reviewed and accepted by the staff. The

staff also determined whether the AMP identified by the applicant was consistent with the AMP

identified in the GALL Report and whether the AMR was valid for the site-specific conditions.

Note E indicated that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but a different aging management program is credited. The

staff audited these line items to verify consistency with the GALL Report. The staff also ,

determined whether the identified AMP would manage the aging effect consistent with the AMP

identified by the GALL Report and whether the AMR was valid for the site-specific conditions.

The staff conducted an audit and review of the information provided in the LRA, as documented

in its PBNP audit and review report. The staff did not repeat its review of the matters described

in the GALL Report. However, the staff did verify that the material presented in the LRA was

applicable and that the applicant had identified the appropriate GALL Report AMRs.

The staff reviewed the LRA to confirm that the applicant had (1) provided a brief description of

the system, components, materials, and environment; (2) stated that the applicable aging

effects have been reviewed and are evaluated in the GALL Report; and (3) identified those

aging effects for the steam and power conversion components that are subject to an AMR. On

the basis of its audit and review, the staff determined that for AMRs not requiring further

evaluation, as identified in LRA Table 3.4.1 (Table 1), the applicant's references to the GALL

Report are acceptable and no further staff review is required.

Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report.

The staff also reviewed information pertaining to the applicant's consideration of recent

operating experience and proposals for managing associated aging effects, On the basis of its

review, the staff found that the AMR results that the applicant claimed to be consistent with the

GALL Report are consistent with the AMRs In the GALL Report. Therefore, the staff found that

the applicant had demonstrated that the effects of aging for these components will be

adequately managed so that their intended function(s) will be maintained consistent with the

CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).

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

Evaluation Is Recommended

Summary of Technical Information in the ADplication. In LRA Section 3.4.2.2, the applicant

provides further evaluation of aging management as recommended by the GALL Report for

steam and power conversion system. 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 (MIC), and biofouling;

* general corrosion; and

* loss of material due to general, pitting, and crevice corrosion, and MIC.

Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant

claimed consistency with the GALL Report, and for which the GALL Report recommends further

evaluation, the staff reviewed the applicant's evaluation to determine whether it adequately

addressed the issues that were further evaluated. In addition, the staff audited the applicant's

further evaluations against the criteria in SRP-LR Section 3.4.2.2. Details of the staff's audit

review are documented in the staff's audit and review report. The staff's evaluation is

discussed below.

3.4.2.2.1 Cumulative Fatigue Damage

In LRA Section 3.4.2.2.1, the applicant stated that fatigue is a TLAA, as defined in

10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21 (c)(1). SER

Section 4.3 documents the staff's review of the applicant's evaluation of this TLAA.

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

The staff reviewed LRA Section 3.4.2.2.2 against the criteria in SRP-LR 3.4.2.2.2.

SRP-LR Section 3.4.2.2.2 states that management of loss of material due to general, pitting,

and crevice corrosion should be evaluated further for carbon steel piping and fittings, valve

bodies and bonnets, pump casings, pump suction and discharge lines, tanks, tubesheets,

channel heads, and shells except for main steam system components and for loss of material

due to pitting and crevice corrosion for stainless steel tanks and heat exchanger/cooler tubes.

The Water Chemistry Control Program relies on monitoring and control of water chemistry

based on the guidelines in EPRI guideline TR-1 02134 for secondary water chemistry to

manage the effects of loss of material due to general, pitting, or crevice corrosion. However,

corrosion may occur at locations of stagnant flow conditions. Therefore, the effectiveness of

the chemistry control program should be verified to ensure that corrosion is not occurring. The

GALL Report recommends further evaluation of programs to manage loss of material due to

general, pitting, and crevice corrosion to verify the effectiveness of the Water Chemistry Control

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Program. A one-time inspection of select components and susceptible locations is an

acceptable method to ensure that corrosion is not occurring and that the component's intended

function will be maintained during the period of extended operation.

The AMPs recommended by the GALL Report for management of this aging effect are GALL

AMP XI.M2, "Water Chemistry," and GALL AMP XI.M32, "One Time Inspection."

In LRA Section 3.4.2.2.2, the applicant stated that the loss of material due to general, pitting

and crevice corrosion, for the steam and power conversion components, are managed by the

Water Chemistry Control Program and the One-Time Inspection Program. Additionally, aging

effects for selected components are managed by the Periodic Surveillance and Preventive

Maintenance Program or the Tank Internal Inspection Program.

The applicant stated that for its steam and power conversion components, it credited the Water

Chemistry Control Program and the One-Time Inspection Program for managing these aging

effects/mechanisms. The applicant stated that in addition to these programs, the Periodic

Surveillance and Preventive Maintenance Program and Tank Internal Inspection Program are

also credited for managing a few selected components. Also, the applicant's existing Water

Chemistry Control Program relies on the guidelines of EPRI TR-102134 for secondary water

chemistry to manage the effects of loss of material due to general, pitting, or crevice corrosion.

The staff reviewed the applicant's Water Chemistry Control Program, One-Time Inspection

Program, Periodic Surveillance and Preventive Maintenance Program, and Tank Internal

Inspection Program. The staff's evaluation is documented in SER Sections 3.0.3.2.20,

3.0.3.2.13, 3.0.3.3.1, and 3.0.3.3.3, respectively. The staff found that the applicant's Water

Chemistry Control Program minimizes loss of material by providing a non-aggressive material

environment and the Periodic Surveillance and Preventive Maintenance Program supplement

water chemistry control for portions of the emergency feedwater system. In addition, the

Periodic Surveillance and Preventive Maintenance Program provides for the inspection of

systems when they are opened for maintenance, which achieves the same results as the

One-Time Inspection Program, which is recommended in the GALL Report.

The staff found that, based on the programs identified above, the applicant has met the criteria

of SRP-LR Section 3.4.2.2.2 for further evaluation. For those items that apply to LRA

Section 3.4.2.2.2, the staff found that the applicant is consistent with the GALL Report and has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained during the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.4.2.2.3 Loss of Material Due to General, Pitting, and Crevice Corrosion, Microbiologica ly

Influenced Corrosion, and Biofouling - -I

The staff reviewed LRA Section 3.4.2.2.3 against the criteria in SRP-LR 3.4.2.2.3. I

SRP-LR Section 3.4.2.2.3 states that loss of material due to general corrosion, pitting and

crevice corrosion, MIC, and bofouling could occur in carbon steel piping and fittings for

untreated water from the backup water supply in the PWR auxiliary feedwaTer system. The

GALL Report recommends further evaluation to ensure that these aging effects are adequately

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managed. Acceptance criteria are described in Branch Technical Position RLSB-1 (SRP-LR

Section A.1).

In LRA Table 3.4.1, Item 3.4.1-03, the applicant stated that this line item is not used. The

applicant stated that the components identified in this line item relate to the portion of the

auxiliary feedwater piping system that is exposed to the untreated water from the backup water

supply. These components are evaluated under the service water system in LRA

Section 3.3.2.1.5, which is addressed in NUREG-1 801, Chapter VII (Auxiliary Systems),

Section C1.

The aging management programs identified by the applicant constitute the equivalent

plant-specific aging management program discussed in SRP-LR Section 3.4.2.2.3. As stated

by the applicant, these components are not listed in LRA Section 3.4; hence, it is reasonable to

not explicitly use the further evaluation criteria discussed in SRP-LR Section 3.4.2.2.3.

However, the applicant does manage the aging effect for these components as part of the

service water system in LRA Section 3.3. Based on the programs identified and inspections

that will be performed, the applicant has met the criteria of SRP-LR Section 3.4.2.2.2 for further

evaluation.

The applicant stated that the aging effects of the lines from the service water system to the

emergency feedwater system that are exposed to untreated water are managed using the

Open-Cycle Cooling (Service) Water Surveillance Program.

The staff reviewed the applicant's Open-Cycle Cooling (Service) Water Surveillance Program

and its evaluation is documented in SER Section 3.0.3.3.2.14. The staff found that this

program includes scheduled walkdowns and selected high-susceptibility teardown and

inspection to detect loss or material degradation. Based on the content of this program, the

staff found use of this AMP acceptable.

For those items that apply to LRA Section 3.4.2.2.3, the staff found that the applicant is

consistent with the GALL Report and has demonstrated that the effects of aging will be

adequately managed so that the intended functions will be maintained during the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

3.4.2.2.4 General Corrosion

The staff reviewed LRA Section 3.4.2.2.4 against the criteria in SRP-LR 3.4.2.2.4.

SRP-LR Section 3.4.2.2.4 states that loss of material due to general corrosion could occur on

the external surfaces of all carbon steel SCs, including closure boltings, exposed to operating

temperature less than 212 OF. The GALL Report recommends further evaluation to ensure that

this aging effect is adequately managed.

The applicant stated that i credited the Systems Monitoring Program for managing aging

effects for normally accessible, external surfaces of piping, tanks, and other components and

equipment within the scope of license renewal. These aging effects are managed through

visual inspection and monitoring of external surfaces for leakage and evidence of material

degradation.

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The staff reviewed the applicant's Systems Monitoring Program and its evaluation is

documented in SER Section 3.0.3.3.2. On the basis of its review, the staff found that the

Systems Monitoring Program adequately manages the loss of material due to general corrosion

for the above components.

The staff found that, based on the programs identified above, the applicant has met the criteria

of SRP-LR Section 3.4.2.2.4 for further evaluation. For those items that apply to LRA

Section 3.4.2.2.4, the staff found that the applicant is consistent with the GALL Report and has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained during the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.4.2.2.5 Loss of Material Due to General, Pitting, and Crevice Corrosion, Microbiologically

Influenced Corrosion

The staff reviewed LRA Section 3.4.2.2.5 against the criteria in SRP-LR 3.4.2.2.5.

In LRA Section 3.4.2.2.5, the applicant addressed (1) the oil side of bearing oil coolers in the

auxiliary feedwater system, and (2) the line item related to buried components in the auxiliary

feedwater system.

SRP-LR Section 3.4.2.2.5 addresses loss of material due to general corrosion (carbon steel

only), as well as pitting and crevice corrosion and MIC, which could occur in stainless steel and

carbon steel shells, tubes, and tubesheets within the bearing oil coolers (for steam turbine

pumps) in the auxiliary feedwater system. The GALL Report recommends further evaluation to

ensure that these aging effects are adequately managed.

SRP-LR 3.4.2.2.5 also addresses loss of material due to general corrosion, pitting and crevice

corrosion, and MIC, which could occur in underground piping and fittings, the emergency

condensate storage tank in the auxiliary feedwater system, and the underground condensate

storage tank in the condensate system.

The applicant credited its plant-specific Periodic Surveillance and Preventive Maintenance

Program for managing the aging effects/mechanisms of part (1) of this line item. In addition,

the applicant stated that It does not have buried components in the steam and power

conversion systems and, therefore, part (2) of this line item is not applicable.

The staff reviewed the applicant's Periodic Surveillance and Preventive Maintenance Program

and its evaluation is documented in SER Section 3.0.3.3.1. On the basis of its review, the staff

found that the Periodic Surveillance and Preventive Maintenance Program adequately manages.

the effects of aging of loss of material for stainless and carbon steel components exposed to

lubricating oil (with water contamination). Also, the staff found that there are no buried

components in steam and power conversion systems at PBNP, as documented in the staff's

audit and review report.

The staff found that, based on the programs identified above, the applicant has met the criteria

of SRP-LR Section 3.4.2.2.5 for further evaluation. For those items that apply to LRA

Section 3.4.2.2.5, the staff found that the applicant is consistent with the GALL Report and has

demonstrated that the effects of aging will be adequately managed so that the intended

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functions will be maintained during the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.4.2.2.6 Quality Assurance for Aging Management of Non-Safety-Related Components

SER Section 3.0.4 provides the staff's evaluation of the applicant's quality assurance program.

Conclusion. On the basis of its review, for component groups evaluated in the GALL Report for

which the applicant claimed consistency with the GALL Report, and for which the GALL Report

recommends further evaluation, the staff determines that (1) those attributes or features for

which the applicant claimed consistency with the GALL Report were indeed consistent and (2)

the applicant had adequately addressed the issues that were further evaluated. The staff found

that the applicant had demonstrated that the effects of aging will be adequately managed so

that the intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

3.4.2.3 AMR Results That Are Not Consistent with or Not Addressed In the GALL Report

Summary of Technical Information in the Application. In LRA Tables 3.4.2-1 through 3.4.2-3,

the staff reviewed additional details of the results of the AMRs for material, environment, aging

effect requiring management, and AMP combinations that are not evaluated in the GALL

Report or are not addressed in the GALL Report.

As documented under RAI 2.1-1 in SER Section 2.1, by letter dated April 29,2005, the

applicant changed the methodology used to determine the nonsafety-related SCs that are

within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(2).

As a result of the implementation of the scoping methodology changes, the applicant identified

changes to LRA Tables 3.4.2-1 and 3.4.2-2.

In LRA Tables 3.4.2-1 through 3.4.2-3, the applicant indicated, via Notes F through J, that

neither the identified component nor the material and environment combination is evaluated in

the GALL Report and provided information concerning how the aging effect will be managed.

Staff Evaluation. For component type, material and environment combinations that are not

evaluated in the GALL Report, the staff reviewed the applicant's evaluation to determine

whether the applicant had demonstrated that the effects of aging will be adequately managed

so that the intended function(s) will be maintained consistent with the CLB during the period of

extended operation.

3.4.2.3.1 Steam and Power Conversion System Components That Have No Aging Effects -

Tables 3.4.2-1 through 3.4.2-3

In LRA Tables 3.4.2-1 through 3.4.2-3, the applicant identified line items where no aging effects

were identified as a result of the aging review process. Specifically, the applicant identified that

no aging effects occurred when components fabricated from carbon/alloy steel, stainless steel,

aluminum, copper alloy, or CASS were exposed to air or to an Inert gas (e.g., nitrogen). Neither

air nor inert gas is identified in the GALL Report as an environment for these components and

materials. No aging effects are considered to be applicable to carbon/alloy steel, stainless

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steel, aluminum, copper alloys, or CASS components in air (defined as dehumidified

atmospheric air, dry/filtered instrument air) or inert gas environments.

On the basis of its review of current industry research and operating experience, the staff found

that dry air on metal will not result in aging that will be of concern during the period of extended

operation. Stainless steel and nickel-based alloy components in air or an inert gas environment

are not susceptible to general corrosion that would affect their intended function. Therefore,

the staff concluded that there are no applicable aging effects requiring management for

carbon/alloy steel, stainless steel, aluminum, copper alloy, or CASS exposed to air, or to an

inert gas environment.

3.4.2.3.2 Main and Auxiliary Steam System - Aging Management Evaluation - Table 3.4.2-1

The staff reviewed LRA Table 3.4.2-1, as modified by letter dated April 29, 2005, which

summarizes the results of AMR evaluations for the main and auxiliary steam system component

groups.

The main and auxiliary steam system experiences loss of material of copper alloy (Zn<1 5%)

cast iron, carbon and low-alloy steels, and stainless steel for the following component types:

* CS components * piping and fittings

* drain trap * pump casing

* fasteners and bolting * restricting orifices

* filters and strainers * steam traps

* flow elements * tanks

* heat exchangers * valve bodies

* instrument valve assemblies * level gauges

For those main and auxiliary steam system components requiring staff review, the

environments are listed below:

* borated water leaks (external)

* indoor - no air conditioning (external)

* treated water - secondary (T<1 20 0F)(intemal)

* treated water - secondary (T>1200F)(intemal)

* containment (external)

* air and gas - wetted (T1 40 0F)(internal)

* outdoor (external)

The applicant proposed to manage the main and auxiliary steam system loss of material aging

effects by using the Bolting Integrity Program, Boric Acid Corrosion Program, Periodic

Surveillance and Preventive Maintenance Program, One-Time Inspection Program, Systems

Monitoring Program and Water Chemistry Control Program. The staff's evaluation of these

programs is documented in SER Sections 3.0.3.2.4, 3.0.3.2.6, 3.0.3.3.1, 3.0.3.2.13, 3.0.3.3.2,

and 3.0.3.2.20, respectively.

The applicant proposed to manage cracking due to SCC of stainless steel material for

component types of valve bodies, instrument valve assemblies, flow elements, heat

exchangers, piping/fittings, and restricting orifices exposed to treated water with temperatures

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greater than 120 OF environment using the Water Chemistry Control Program and One-Time

Inspection Program, to provide confirmation of effectiveness.

The staff reviewed the applicant's Water Chemistry Control Program and One-Time Inspection

Program and its evaluations are documented in SER Sections 3.0.3.2.20 and 3.0.3.2.13,

respectively.

On the basis of its review of the applicant's programs, and plant-specific and industry operating

experience, the staff found that loss of material and cracking due to SCC for components in the

main and auxiliary steam system are effectively managed. Therefore, the staff found that

management of loss of material and cracking due to SCC in the main and auxiliary steam

system using these programs is acceptable.

The applicant proposed to manage loss of material due to FAC/erosion - corrosion of carbon

and low-alloy steels materials for component type of flow elements, piping and fittings, steam

traps, heat exchangers, tanks, and valve bodies exposed to treated water - secondary

(T>1 20 0F)(internal) by using the Flow-Accelerated Corrosion Program and Water Chemistry

Control Program.

The staff reviewed the applicant's Flow-Accelerated Corrosion Program and Water Chemistry

Control Program. The staff's evaluations of these programs are documented in SER

Sections 3.0.3.2.11 and 3.0.3.2.20, respectively.

On the basis of its review of the applicant's programs, and plant-specific and industry operating

experience, the staff found that loss of material due to FAC/erosion-corrosion for components in

the main and auxiliary steam system are effectively managed using the Flow-Accelerated

Corrosion Program and Water Chemistry Control Program. Therefore, the staff found that

management of loss of material due to FAC in the main and auxiliary steam system using these

programs is acceptable.

3.4.2.3.3 Feedwater and Condensate System - Aging Management Evaluation - Table 3.4.2-2

The staff reviewed LRA Table 3.4.2-2, as modified by letter dated April 29, 2005, which

summarizes the results of AMR evaluations for the feedwater and condensate system

component groups.

The feedwater and condensate system experiences loss of material of cast iron, carbon and

low-alloy steel, stainless steel, and CASS for the following component types:

* CS components * piping and fittings

* fasteners and bolting * pump casing

* flow elements * steam traps

* instrument valve assemblies * tanks

* level gauges * valve bodies

3-256'
For those components requiring staff review, the environments are listed below:

* borated water leaks (external)

* treated water - secondary (T>1200F)(internal)

* treated water - secondary (T<1 20 OF)(internal)

* indoor - no air conditioning (external)

* containment (external) -

The applicant proposed to manage the feedwater and condensate system loss of material

aging effects by using the Bolting Integrity Program, Boric Acid Corrosion Program, Water

Chemistry Control Program, One-Time Inspection Program, and Systems Monitoring Program.

The staff's evaluation of these programs is documented in SER Sections 3.0.3.2.4, 3.0.3.2.6,

3.0.3.2.20, 3.0.3.2.13 and 3.0.3.3.2, respectively.

The applicant proposed to manage loss of material due to FAC/erosion - corrosion of carbon

and low-alloy steel material for component types of flow elements, valve bodies, and piping and

fittings, exposed to treated water - secondary (T,'120 0F)(internal), by using the Water

Chemistry Control Program and Flow-Accelerated Corrosion Program.

On the basis of its review of the applicant's plant-specific and industry operating experience, the

staff found that loss of material due to FAC/erosion - corrosion in the feedwater and condensate

system are effectively managed using the Water Chemistry Control Program and

Flow-Accelerated Corrosion Program. On this basis, the staff found that management of loss

of material due to FAC/erosion - corrosion in the feedwater and condensate system is

acceptable.

The applicant proposed to manage cracking due to SCC of stainless steel material for

component types of flow elements, instrument valve assemblies, piping and fittings, and valve

bodies, exposed to treated water - secondary (T>120OF)(internal) using the Water Chemistry

Control Program, and One-Time Inspection Program.

On the basis of its review of the applicant's programs, and plant-specific and industry operating

experience, the staff found that cracking due to SCC in the feedwater and condensate system

is effectively managed using the Water Chemistry Control Program and One-Time Inspection

Program. Therefore, the staff found that management of cracking due to SCC in the feedwater

and condensate system using these programs is acceptable.

3.4.2.3.4 Auxiliary Feedwater System AMR Results - Aging Management Evaluation -

Table 3.4.2-3

The staff reviewed LRA Table 3.4.2-3, which summarizes the results of AMR evaluations for the

auxiliary feedwater system component groups.

The auxiliary feedwater system experiences loss of material of carbon and low-alloy steel, cast

iron, CASS, copper alloy (Zn<1 5%), aluminum, and stainless steel for the following component

types:

* accumulators and cylinders * fasteners and bolting

* CS components * flow elements

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* heat exchanger * tanks

* instrument valve assemblies * turbine casing

* piping and fittings * valve bodies

* pump casing * valve operator

* restricting orifices

For those components requiring staff review, the environments are listed below:

* borated water leaks (external)

* treated water - secondary (T>1200F)(internal)

* treated water - secondary (T<120 F)(internal)

* indoor - no air conditioning (external)

* containment (extemal)

* raw water - stagnant (internal)

* oil and fuel oil (internal)

The applicant proposed to manage the auxiliary feedwater system loss of material aging effects

by using the Bolting Integrity Program, Boric Acid Corrosion Program, Water Chemistry Control

Program, One-Time Inspection Program, Systems Monitoring Program, Open-Cycle Cooling

(Service) Water System Surveillance Program, Tank Internal Inspection Program, and Periodic

Surveillance and Preventive Maintenance Program. The staff's evaluations of these programs

are documented in SER Sections 3.0.3.2.4, 3.0.3.2.6, 3.3.2.20, 3.0.3.2.13, 3.0.3.3.2, 3.0.3.2.14,

3.0.3.3.3, and 3.0.3.3.1, respectively.

The applicant proposed to manage loss of heat transfer due to fouling on stainless steel on

component type of heat exchangers by using the Periodic Surveillance and Preventive

Maintenance Program. In addition, it proposed to manage loss of material due to

FAC/erosion-corrosion on stainless steel and carbon and low-alloy steel in component type of

valve bodies, pipings and fittings by using the Flow-Accelerated Corrosion Program and Water

Chemistry Control Program. The staff's evaluation of these programs are evaluated in SER

Sections 3.0.3.2.11 and 3.0.3.2.20, respectively.

The staff's review of LRA Table 3.4.2-3 identified areas in which additional information was

necessary to complete the review of the applicant's results. The applicant responded to the

staff's RAls as discussed below.

RAI 3.4-1. In LRA Table 3.4.2-3, the stainless steel heat exchangers, with either heat transfer

or pressure boundary as the intended function, are identified with only internal environments

and associated aging effects. The external environment is listed as 'not applicable." In

RAI 3.4-1, dated July 30, 2004, the staff requested the applicant to explain why no external

environments and associated aging effects are identified for these components.

In its letter, dated August 30, 2004, the applicant stated that due to the way the license renewal

database was developed and used, tubing assets were identified as two separate components

(tubing ID and tubing OD). This allowed the user to designate an internal environment for each

(tubing ID and tubing OD), but since the database required each component to have both an

internal and external environment, the external environment would then be documented as "not

applicable." The applicant noted that in LRA Table 3.4.2-3, there is a heat exchanger material

type with two different internal environments, which is reflective of the environments for the ID

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and OD of the tubing. Because the tubing has a pressure boundary intended function in

addition to the heat transfer function, this same information was duplicated for the pressure

boundary intended function line items.

The applicant also stated that the only heat exchanger components that have a heat transfer

intended function are the tubes. External environments (indoor - no air conditioning, outdoor,

etc.) would only apply to the shell of the heat exchanger. The shell only has a pressure

boundary function; therefore, the shell and its external environment are not identified under the

heat transfer intended function. Additionally, the shell is typically made of a different material

than the tubes and, therefore, would not be represented by the same line item as the tubing in

the LRA. In LRA Table 3.4.2-3, the heat exchanger shell is cast iron and has an "indoor - no air

conditioning" external environment. The applicant stated that the System Monitoring Program

applies to the shell.

The staff considered the applicant's response to be adequate in explaining the relationship

among components, material, and environments listed in LRA Table 3.4.2-3. The staff's

concern described in RAI 3.4-1 is resolved.

RAI 3.4-2. In the first quarter of 2003, PBNP entered the Multiple/Repetitive Degraded

Cornerstone Column in the Action Matrix of NRC Inspection Manual Chapter 0305, "Operating

Reactor Assessment Program,' as a result of a high significance (Red) inspection finding

involving the potential for a common mode failure of the auxiliary feedwater system following a

loss of the instrument air system. A second inspection finding (Yellow for Unit 1 and Red for

Unit 2) was subsequently identified which involved the potential common mode failure of the

auxiliary feedwater pumps due to plugging of the recirculation line pressure reduction orifices.

In view of the aforementioned inspection findings and the subsequent corrective actions for the

two auxiliary feedwater issues, in RAI 3.4-2, dated July 30, 2004, the staff requested the

applicant to address the following questions in the context of the license renewal application:

(1) Clarify whether the instrument air system (or portions of the system) and the

recirculation line pressure reduction orifices are within the scope of license renewal, and

if appropriate AMPs have been Identified to manage the components. If not, the staff

requested the applicant to explain why they are out of scope.

(2) For aging management evaluation as summarized in LRA Table 3.4.2-3 for the auxiliary

feedwater system, discuss any impact on the scoping of mechanical components and

the AMR performed for the affected components, as a result of the recent physical

modifications made to resolve the auxiliary feedwater pump room Appendix R issues.

In its response, dated August 30, 2004, the applicant stated that portions of the instrument air

system, including cylinders, tanks, tubing, and valves associated with air side of the

recirculation valves on all auxiliary feedwater pumps are within the scope of license renewal. In

addition, all of the pressure reduction orifices (1 RO-4003, 2RO-4003, RO-4008, and RO-4015)

and their associated recirculation lines back to the condensate storage tanks are within the

scope of license renewal. The applicant stated that these components are represented in LRA

Table 3.4.2-3 under the following component types: accumulators/cylinders, pipes and fittings,-

restricting orifices, tanks, valve bodies, and valve operators. Also, as shown in LRA

Table 3.4.2-3, appropriate AMPs were selected based on aging effects identified for each

material/environment combination.

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The applicant further stated that recent physical modifications to the auxiliary feedwater pump

room are not represented in the LRA because they were not in place at the time their 'snapshot'

of component data was taken to perform license renewal activities. However, these

modifications will be included in its LRA annual update, and appropriate AMPs and activities

would then be identified for these new components. Based on the information provided by the

applicant, the staff determined that the affected modifications in the auxiliary feedwater pump

room will be managed through an established LRA annual update activity.

The staff found that the applicant's response provides assurance that the affected auxiliary

feedwater system components are within the scope of license renewal and being adequately

managed in the LRA. The staff's concerns described in RAI 3.4-2 are resolved.

The staff reviewed the LRA, industry operating experience, and RAI responses. The staff

concluded that the applicant adequately identified the aging effects, and the AMPs credited for

managing the aging effects, for the auxiliary feedwater. The staff concluded that there is

reasonable assurance 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).

3.4.3 Conclusion

On the basis of its review, the staff concluded that the applicant had demonstrated that the

aging effects associated with the steam and power conversion 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 concluded

that they adequately describe the AMPs credited for managing aging of the steam and power

conversion, as required by 10 CFR 54.21(d).

3.5 Aging Management of Containments, Structures, and Components 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:

* Units 1 and 2 containment building structure

* control building structure

* circulating water pumphouse structure

* diesel generator building structure

* Units 1 and 2 facade structure

* primary auxiliary building structure

* Units I and 2 turbine building structure

* yard structures

* cranes, hoists, and lifting devices

* component supports commodity group

* fire barrier commodity group

* 13.8 KV switchgear building structure

3-260
* fuel oil pumphouse structure

* gas turbine building structure

3.5.1 Summary of Technical Information In the Application

In LRA Section 3.5, the applicant provided AMR results for containment, structures and

component supports. In LRA Table 3.5.1, "Summary of Aging Management Evaluations in

Chapters II and IlIl of NUREG-1 801 for Structures and Component Supports," the applicant

provided a summary comparison of its AMRs with the AMRs evaluated in the GALL Report for

the containment, structures and component supports components and component groups.

The applicant's AMRs incorporated applicable operating experience in the determination of

AERMs. These reviews included evaluation of plant-specific and industry operating experience.

The plant-specific evaluation included reviews of condition reports and discussions with

appropriate site personnel to identify AERMs. The applicant's review of industry operating

experience included a review of the GALL Report and operating experience issues identified

since the issuance of the GALL Report.

3.5.2 Staff Evaluation

The staff reviewed LRA Section 3.5 to determine if the applicant had provided sufficient

information to demonstrate that the effects of aging for the containment, structures and

components supports 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).

Also, the staff performed an onsite audit of AMRs to confirm the applicant's claim that certain

identified AMRs are consistent with the GALL Report. The staff did not repeat its review of the

matters described in the GALL Report. However, the staff did verify that the material presented

in the LRA was applicable and that the applicant had identified the appropriate GALL AMPs.

The staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff's

audit evaluations are documented In the staff's PBNP audit and review report and summarized

in SER Section 3.5.2.1.

The staff also performed an onsite audit of those AMRs that are consistent with the GALL

Report and for which further evaluation Is recommended. The staff verified that the applicant's

further evaluations were consistent with the acceptance criteria in NUREG-1 800

Section 3.5.2.2, "Standard Review Plan for Review of License Renewal Applications for Nuclear

Power Plants," dated July 2001. The staff's audit evaluations are documented in the staff's

PBNP audit and review report and summarized in SER Section 3.5.2.2.

The staff performed an onsite audit and conducted a technical review of the remaining AMRs

that were not consistent with the GALL Report. The audit and technical review n luded

evaluating whether all plausible aging effects had been identified and the aging epfects listed

were appropriate for the combination of materials and environments speciTieh. Fe staff's audit

evaluations are documented in the staff's PBNP audit and review report and sLmrnarized in

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SER Section 3.5.2.3. The staff's evaluation of its technical review is also documented in SER

Section 3.5.2.3.

Finally, the staff reviewed the AMP summary descriptions in the FSAR supplement to ensure

that they provided an adequate description of the programs credited with managing or

monitoring aging for the containments, structures and component supports system

components.

Table 3.5-1 below provides a summary of the staff's evaluation of components, aging

effects/mechanisms, and AMPs listed in LRA Section 3.5 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

Component ' Efectf] Mi;P nA GALAgingL Af ta luation'X'

Group iMechanism Report j

PWR Containment

Penetration Cumulative fatigue TLAA evaluated in TLAA This TLAA is

sleeves, bellows, damage (CLB accordance with evaluated in

and dissimilar fatigue analysis 10 CFR 54.21(c) Section 4.3, Metal

metal welds exists) Fatigue (See

(Item Number Section 3.5.2.2.6)

3.5.1-01)

Penetration Cracking due to Containment ISI Not Applicable Not Applicable (See

sleeves, bellows, cyclic loading, or and containment Section 3.5.2.2.7) and dissimilar crack initiation and leak rate test

metal welds growth due to SCC

(Item Number

3.5.1-02)

Penetration Loss of material due Containment ISI Inservice Inspection Consistent with

sleeves, bellows, to corrosion and containment Program GALL, which

and dissimilar leak rate test recommends no

metal welds further evaluation.

(Item Number (See

3.5.1-03) ^ Section 3.5.2.1)

Personnel airlock Loss of material due Containment ISI Inservice Inspection Consistent with

and equipment to corrosion and containment Program GALL, which

hatch leak rate test recommends no

(Item Number further evaluation.

3.5.1-04) (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 GALL, which

hatch position due to technical recommends no

(Item Number mechanical wear of specifications further evaluation.

3.5.1-05) locks, hinges and (See

l closure mechanism Section 3.5.2.1)

3-262
Component Agiing ffectf AMPAIn GALL o .AMP in iA Staff Evaluaon GroUp i Mechanismrn s - i Report _ _ _ _ _ _____________

Seals, gaskets, Loss of sealant and Containment ISI Inservice Inspection Consistent with

and moisture leakage through and containment Program GALL, which

barriers containment due to leak rate test recommends no

(Item Number deterioration of joint further evaluation.

3.5.1-06) seals, gaskets, and . (See

moisture barriers Section 3.5.2.1)

PWR Concrete (Reinforced and Prestressed) and Steel Containment -

Concrete Aging of accessible Containment ISI Inservice Inspection Consistent with

elements: and inaccessible Program, Structures GALL, which

foundation, dome, concrete areas due Monitoring Program recommends further

and wall to leaching of evaluation. (See

(Item Number calcium hydroxdde, Section 3.5.2.2.1)

3.5.1-07) aggressive chemical

attack, and corrosion

of embedded steel

Concrete Cracks, distortion, Structures Structures Monitoring Consistent with

elements: and increases in monitoring Program GALL, which

foundation component stress recommends no

(Item Number level due to further evaluation.

3.5.1-08) settlement (See

Section 3.5.2.2.2)

Concrete Reduction in Structures Structures Monitoring Consistent with

elements: foundation strength monitoring Program GALL, which

foundation due to erosion of recommends no

(Item Number porous concrete further evaluation.

3.5.1-09) sub-foundation (See

Section 3.5.2.2.2)

Concrete Reduction of Plant-specific Inservice Inspection Consistent with

elements: strength and Program, Structures GALL, which

foundation, dome, modulus due to Monitoring Program recommends further

and wall elevated evaluation. (See

(Item Number temperature Section 3.5.2.2.3)

3.5.1-10)

Prestressed Loss of prestress TLAA evaluated in TLAA This TLAA is

containment: due to relaxation, accordance with evaluated in

tendons and shrinkage, creep, 10 CFR 54.21(c) .; . Section 4.5, Loss of

anchorage and elevated i Preload. (See

components temperature Section 3.5.2.2.5)

(Item Number I i

3.5.1-11) __ __'[_l___________! __ I

Steel elements: Loss of material due Containment ISI Inservice nspp P | Consistent With

liner plate, to corrosion in and containment Program, Bono Acid GALL, which

containment shell accessible and leak rate test Corrosion Proram re~commends fu rther

(Item Number inaccessible areas lj- -evaluation. (See

3.5.1-12) Section 3.5.2.2.4)

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Component Aging E tt AMPn GALL AM -- S Eviluation i 

:Group L ehaIs-m VRepont __'.,______

Steel elements: Loss of material due Protective coating Structures Monitoring Consistent with

protected by to corrosion in monitoring and Program, Inservice GALL, which

coating accessible areas maintenance Inspection Program recommends no

(Item Number only further evaluation.

3.5.1-14) (See

Section 3.5.2.1)

Prestressed Loss of material due Containment ISI Inservice Inspection Consistent with

containment: to corrosion of Program GALL, which

tendons and prestressing tendons recommends no

anchorage and anchorage further evaluation.

components components (See (Item Number Section 3.5.2.1)

3.5.1-15)

Concrete Scaling, cracking, Containment ISI Inservice Inspection Consistent with

elements: and spalling due to Program GALL, which

foundation, dome, freeze-thaw; recommends no

and wall expansion and further evaluation.

(Item Number cracking due to (See 3.5.1-16) reaction with Section 3.5.2.1)

aggregate

Class I Structures

All groups except All types of aging Structures Structures Monitoring Consistent with

Group 6: effects monitoring Program, Boric Acid GALL, which

accessible Corrosion Program recommends no

interior/exterior further evaluation.

concrete and steel (See

components Section 3.5.2.2.8) (Item Number

3.5.1-20)

Groups 1-3, 5, and Aging of Plant-specific Structures Monitoring Consistent with

7-9: inaccessible inaccessible Program GALL, which

concrete concrete areas due recommends further

components, such to aggressive evaluation. (See

as exterior walls chemical attack, and Section 3.5.2.2.9)

below grade and corrosion of

foundation embedded steel

(Item Number

3.5.1-21)

Group 6: all All types of aging Inspection of Structures Monitoring Consistent with

accessible/ effects, including water-control Program GALL, which

inaccessible loss of material due structures or recommends no

concrete, steel, to abrasion, FERC/US Army further evaluation.

and earthen cavitation, and Corps of (See

components corrosion Engineers dam Section 3.52.1)

(Item Number inspections and

3.5.1-22) maintenance

3-264
Iomponenm A Effct ' A' nP A StaffEVA ion -

Group e a nis m ,,_ ep, , , , ,_it_, _ . _ , , _. _ . _.

Group 5: liners Crack initiation and Water Chemistry Water Chemistry Consistent with

(Item Number growth from SCC Control Program Control Program GALL, which

3.5.1-23) and loss of material and monitoring of recommends no

due to crevice spent fuel pool further evaluation.

corrosion water level (See

Section 3.5.2.1)

Groups 1-3, 5, and Cracking due to Masonry wall Structures Monitoring Consistent with

6: all masonry restraint, shrinkage, Program GALL, which

block walls creep, and 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 Structures Monitoring Consistent with

7-9: foundation and increases in monitoring Program GALL, which

(Item Number component stress recommends no

3.5.1-25) level due to further evaluation.

settlement (See

Section 3.5.22.2)

Groups 1-3 and Reduction In Structures Structures Monitoring Consistent with

5-9: foundation foundation strength monitoring Program GALL, which

(Item Number due to erosion of recommends no

3.5.1-26) porous concrete further evaluation.

sub-foundation (See

Section 3.5.2.2.2)

Groups 1-5: Reduction of Plant-specific Inservice Inspection Consistent with

concrete strength and Program, Structures GALL, which

(Item Number modulus due to Monitoring Program recommends further

3.5.1-27) elevated evaluation. (See

temperature Section 3.5.2.2.3)

Groups 7 and 8: Crack Initiation and Plant-specific Not Applicable Not Applicable

liners growth due to SCC;

(Item Number Loss of material due

3.5.1-28) to crevice corrosion

Component Supports

All groups support Aging of component Structures StructuresMonitoring Consistent with

members: anchor supports monitoring Program GALL, which

bolts, concrete recommends no

surrounding further evaluation.

anchor bolts, '(See

welds, grout pads, Section 3.6.2.1 0) bolted . I

connections, etc. i 1

(Item Number

3.5.1-29) , 2 __ __' _ I __ _| _ ___

Il I.;ij ' ' !.'i i ,|

3-265
Cti. orrponent Aging ect! AP inGA0 LL -AMPInLRA S a

-Group Mechanism Report _ _ _,, ______________'

Groups B.1, B1.2, Cumulative fatigue TLAA evaluated in TLAA This TLAA is

and B1.3 support damage (CLB accordance with evaluated in

members: anchor fatigue analysis 10 CFR 54.21(c) Section 4.3, Metal

bolts and welds exists) Fatigue (See

(Item Number section 3.5.2.2.1 1)

3.5.1-30)

All groups support Loss of material due Boric acid Boric Acid Corrosion Consistent with

members: anchor to boric acid corrosion Program GALL, which

bolts and welds corrosion recommends no

(Item Number further evaluation.

3.5.1-31) (See

Section 3.5.2.1)

Groups B1.1, B1.2, Loss of material due ISI Inservice Inspection Consistent with

and B1.3 support to environmental Program, Structures GALL, which

members: anchor corrosion; loss of Monitoring Program recommends no

bolts, welds, spring mechanical function further evaluation.

hangers, guides, due to corrosion, (See

stops, and distortion, dirt, Section 3.5.2.1)

vibration isolators overload, etc.

(Item Number

3.5.1-32)

Group B1.1: high- Crack initiation and Bolting integrity Bolting Integrity Consistent with

strength, low-alloy growth due to SCC Program GALL, which

bolts recommends no

(Item Number further evaluation.

3.5.1-33) (See

Section 3.5.2.1)

The staff's review of the PBNP Containments, Structures, and Components Supports and

associated components followed one of several approaches. One approach, documented in

SER Section 3.5.2.1, involves the staff's review of the AMR results for components in the

Containments, Structures, and Components Supports that the applicant indicated are

consistent with the GALL Report and do not require further evaluation. Another approach,

documented in SER Section 3.5.2.2, involves the staff's review of the AMR results for

components in the Containments, Structures, and Components Supports that the applicant

indicated are consistent with the GALL Report and for which further evaluation is

recommended. A third approach, documented in SER Section 3.5.2.3, involves the staff's

review of the AMR results for components in the Containments, Structures, and Components

Supports that the applicant indicated are not consistent with the GALL Report or are not

addressed in the GALL Report. The staff's review of AMPs that are credited to manage or

monitor aging effects of the Containments, Structures, and Components Supports components

is documented in SER Section 3.0.3.

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 the Application. In LRA Section 3.5.2.1, the applicant

identified the materials, environments, and aging effects requiring management The applicant

identified the following programs that manage the aging effects related to Units 1 and 2

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containment building structure, control building structure, circulating water pumphouse

structure, diesel generator building structure, Units I and 2 facade structure, primary auxiliary

building structure, Units 1 and 2 turbine building structure, yard structures, cranes, hoists, and

lifting devices, component supports commodity group, fire barrier commodity group, 13.8 KV

switchgear building structure, fuel oil pumphouse structure, and gas turbine building structure:

* ASME Section XI, Subsections IWE and IWL Inservice Inspection Program

* ASME Section Xl, Subsection IWF Inservice Inspection Program

* Boraflex Monitoring Program

* Boric Acid Corrosion Program

* Fire Protection Program

* Periodic Surveillance and Preventive Maintenance Program

* Structures Monitoring Program

* Water Chemistry Control Program

Staff Evaluation. In LRA Tables 3.5.2-1 through 3.5.2-14, the applicant provided a summary of

AMRs for the Units 1 and 2 containment building structure, control building structure, circulating

water pumphouse structure, diesel generator building structure, Units 1 and 2 facade structure,

primary auxiliary building structure, Units 1 and 2 turbine building structure, yard structures,

cranes, hoists, and lifting devices, component supports commodity group, fire barrier

commodity group, 13.8 KV switchgear building structure, fuel oil pumphouse structure, and gas

turbine building structure components and identified which AMRs it considered to be consistent

with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed

consistency with the GALL Report, and for which the GALL Report does not recommend further

evaluation, the staff performed an audit and review to determine whether the plant-specific

components contained in these GALL Report component groups were bounded by the GALL

Report evaluation.

The applicant provided a note for each AMR line item. The notes described how the

information in the tables aligns with the information in the GALL Report. The staff's audit of

those AMRs with Notes A through E, indicated the AMR was consistent with the GALL Report.

Note A indicated that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the AMP

identified in the GALL Report. The staff audited these line items to verify consistency with the

GALL Report and the validity of the AMR for the site-specific conditions.

Note B indicated that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

AMP Identified in the GALL Report. The staff audited these line items to verify consistency with

the GALL Report. The staff verified that the identified exceptions to the GALL AMPs had been

reviewed and accepted by the staff. The staff also determined whether the AMP identified by

the applicant was consistent with the AMP identified in the GALL Report and whether the AMR

was valid for the site-specific conditions.

Note C indicated that the component for the AMR line item, although different, is consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent

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with the AMP identified by the GALL Report. This note indicates that the applicant was unable

to find a listing of some system components in the GALL Report. However, the applicant

identified a different component in the GALL Report that had the same material, environment,

aging effect, and AMP as the component that was under review. The staff audited these line

items to verify consistency with the GALL Report. The staff also determined whether the AMR

line item of the different component was applicable to the component under review and whether

the AMR was valid for the site-specific conditions.

Note D indicated that the component for the AMR line item, although different, is consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP takes some

exceptions to the AMP identified in the GALL Report. The staff audited these line items to

verify consistency with the GALL Report. The staff verified whether the AMR line item of the

different component was applicable to the component under review. The staff verified whether

the identified exceptions to the GALL AMPs had been reviewed and accepted by the staff. The

staff also determined whether the AMP identified by the applicant was consistent with the AMP

identified in the GALL Report and whether the AMR was valid for the site-specific conditions.

Note E indicated that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but a different aging management program is credited. The

staff audited these line items to verify consistency with the GALL Report. The staff also

determined whether the identified AMP would manage the aging effect consistent with the AMP

identified by the GALL Report and whether the AMR was valid for the site-specific conditions.

The staff conducted an audit and review of the information provided in the LRA, as documented

in its PBNP audit and review report. The staff did not repeat its review of the matters described

in the GALL Report. However, the staff did verify that the material presented in the LRA was

applicable and that the applicant had identified the appropriate GALL Report AMRs.

The staff reviewed the LRA to confirm that the applicant had (1) provided a brief description of

the system, components, materials, and environment; (2) stated that the applicable aging

effects have been reviewed and are evaluated in the GALL Report; and (3) identified those

aging effects for the containments, structures, and component supports components that are

subject to an AMR. On the basis of its review, the staff determined that for AMRs not requiring

further evaluation, as identified in LRA Table 3.5.1 (Table 1), the applicant's references to the

GALL Report are acceptable and no further staff review is required.

Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report.

The staff also reviewed information pertaining to the applicant's consideration of recent

operating experience and proposals for managing associated aging effects. On the basis of its

review, the staff found that the AMR results that the applicant claimed to be consistent with the

GALL Report, are consistent with the AMRs in the GALL Report. Therefore, the staff found that

the applicant had demonstrated that the effects of aging for these components will be

adequately managed so that their intended function(s) will be maintained for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

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3.5.2.2 AMR Results That Are Consistent with GALL Report, for Which Further Evaluation

Is Recommended

In LRA Section 3.5.2.2 the applicant provided further evaluation of aging management as

recommended by the GALL Report for Units 1 and 2 containment building structure, control

building structure, circulating water pumphouse structure, diesel generator building structure,

Units 1 and 2 facade structure, primary auxiliary building structure, Units 1 and 2 turbine

building structure, yard structures, cranes, hoists, and lifting devices, component supports

commodity group, fire barrier commodity group, 13.8 KV switchgear building structure, fuel oil

pumphouse structure, and gas turbine building structure. The applicant provided information

concerning how it will manage the following aging effects:

PWR Containments:

* aging of Inaccessible concrete areas;

* cracking, distortion, and increase in component stress levels due to settlement;

reduction of foundation strength due to erosion of porous concrete subfoundations, if not

covered by the Structures Monitoring Program;

* reduction of strength and modulus of concrete structures due to elevated temperature;

* loss of material due to corrosion in inaccessible areas of steel containment shell or liner

plate;

* loss of prestress due to relaxation, shrinkage, creep, and elevated temperature;

* cumulative fatigue damage; and

* cracking due to cyclic loading and SCC.

Class I Structure:

* aging of structures not covered by the Structures Monitoring Program; and

* aging management of inaccessible areas.

Component Supports:

* aging of supports not covered by the Structures Monitoring Program; and

* cumulative fatigue damage due to cyclic loading.

For component groups evaluated in the GALL Report for which the applicant claimed

consistency with the GALL Report, and for which the GALL Report recommends further

evaluation, the staff audited and reviewed the applicant's evaluation to determine whether it

adequately addressed the issues that were further evaluated. In addition, the staff reviewed the

applicant's further evaluations against the criteria in SRP-LR Section 3.5.3.2. Details of the

staff's audit are documented in the staff's PBNP audit and review report.

3.5.2.2.1 PWR Containments

The staff reviewed LRA Section 3.5.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.1,

which addresses several areas discussed below.

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Aging of Inaccessible Concrete Areas. The staff reviewed LRA Section 3.5.2.2.1.1 against the

criteria in SRP-LR Section 3.5.2.2.1.1. In LRA Section 3.5.2.2.1.1, the applicant addressed

aging of inaccessible concrete areas for the containment.

The ASME Code Subsection IWL exempts from examination portions of the concrete

containment that are inaccessible (e.g., concrete covered by liner, foundation material, or

backfill, or obstructed by adjacent structures or components). However,

10 CFR 50.55a(b)(2)(ix) requires that the applicant 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 AMP recommended by the GALL Report for managing the aging of the accessible portions

of the containment structures is GALL AMP XI.S2, "ASME Section Xl, Subsection IWL." The

applicant addressed this with ASME Code Section Xl, Subsections IWE and IWL Inservice

Inspection Program. The staff reviewed the applicant's ASME Code Section Xl, Subsection

IWE and IWL ISI Program and its evaluation is addressed in SER Section 3.0.3.2.2.

In GALL Report, Volume 2, Chapter II, Table Al, as updated by ISG-03 dated

November 23, 2001, "Proposed Revision of Chapters II and IlIl of Generic Lessons Learned

(GALL) Report on Aging Management of Concrete Elements," states that further evaluation is

recommended for managing the aging effects for containment concrete components located in

inaccessible areas for 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. Possible aging effects for containment concrete structural components due to

these five aging mechanisms are cracking, change in material properties, and loss of material.

(1) Freeze-thaw. SRP-LR Section 3.5.2.2.1.1 does not address freeze-thaw as an aging

mechanism for concrete containments because no further evaluation is recommended in

the GALL Report. However, ISG-03 clarifies the staff position that further evaluation is

appropriate if the applicant's facility is subject to moderate to severe weathering

conditions unless the concrete meets certain specifications and subsequent inspections

have confirmed that the aging mechanism has not caused degradation of the concrete.

The applicant stated that Units 1 and 2 are located in a severe weathering region. In

LRA Table 3.5.0-1, Part (11), the applicant stated that construction of the containment

was performed under a contract containing concrete specifications. The specifications

specified concrete entrained air content and water-to-cement ratio which meet the

recommendations contained in the American Concrete Institute (ACI) specification

ACI 318 63, "Building Code Requirements for Reinforced Concrete." Therefore, loss of

material and cracking due to freeze-thaw is not an applicable aging mechanism

requiring management. Additionally, the entire containment structures are protected

from the weather by the facade structure. However, the applicant stated that the

inspections performed in accordance with the requirements of the ASME Code

Section Xl, Subsections IWE and IWL Inservice Inspection Program would detect

freeze-thaw aging effects during the period of extended operation, should they occur.

During the audit, the staff interviewed members of the applicant's technical staff and

reviewed relevant operating experience to confirm that loss of material from freeze-thaw

has not been observed, either through ASME Code Section Xl, Subsection IWE and

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IWL Inservice Inspection Program or the Structures Monitoring Program. The staff

agreed that the concrete specification applied at PBNP would be expected to protect

against the freeze-thaw aging effects. The staff's review of operating experience did not

identify any history of freeze-thaw aging effects. During these discussions, the applicant

.stated that, even though they do not believe freeze-thaw Is an active aging mechanism

at PBNP, the inspections performed in accordance with the requirements of the ASME

Code Section Xi, Subsections IWE and IWL Inservice Inspection Program, would detect

freeze-thaw aging effects during the period of extended operation, should they occur.

The staff agrees that this program adequately manages the aging effect of freeze-thaw.

On the basis of its review, the staff found that, based on the concrete specifications for

the containment, in conjunction with the physical protection provided to the containment

by the facade structure, the applicant is consistent with the GALL Report, Chapter II,

Containment Structures, Item Al .1-a, as updated by ISG-03, and has demonstrated that

loss of material and cracking due to freeze-thaw will be adequately managed.

(2) Leaching of calcium hydroxide. SRP-LR Section 3.5.2.2.1.1 states that cracking,

spalling, and increases in porosity and permeability due to leaching of calcium hydroxide

could occur in inaccessible areas of PWR concrete and steel containments. The GALL

Report, as updated by ISG-03, recommends further evaluation of plant-specific

programs to manage the aging effects for inaccessible areas if specific criteria cannot

be satisfied.

The GALL Report, Chapter II, Containment Structures, Item A1.1-b 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

likely if the concrete is constructed to ensure that it is dense, well-cured, has low.

permeability, and that cracking is well controlled. Cracking is controlled through proper

arrangement and distribution of reinforcing bars. All of the above characteristics are

assured if the concrete was constructed with the guidance of ACI 201 .2R-77, 'Guide to

Durable Concrete."

In LRA Table 3.5.0-1, Part (8), the applicant stated that its concrete specification met

the intent of ACI 201.2R and that the containment is not exposed to flowing water. Also, the containment structures are protected from the weather by the facade structure.

On the basis of its review, the staff found that, based on the concrete specifications for

the containment, lack of exposure to flowing water, and the protection from the weather

provided to the containment by the facade structure, the applicant is consistent with the

GALL Report, Chapter II, Containment Structures, Item Al.1-b,!as updated by lSG-03,

and has demonstrated that cracking, spalling, and increases in porosity and permeability

due to leaching of calcium hydroxide will be adequately managed.

(3) Aggressive chemical attack. SRP-LR Section 3.5.2.2.1.1 Ing,

and increases in porosity and permeability due to aggressive chernical Attack could

occur in inaccessible areas of PWR concrete and steel containmns.I The GALL

Report, as updated by ISG-03, recommends further evaluation of plart-specific

programs to manage the aging effects for inaccessible areas if specific criteria defined

in the GALL Report cannot be satisfied.

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The GALL Report, Chapter II, Containment Structures, Item A1.1-c, states that for

below-grade exterior reinforced concrete (basemat, embedded walls), a plant-specific

aging management program is required only if the below-grade environment is

aggressive (pH less than 5.5, chlorides greater than 500 ppm, or sulfates greater than

1500 ppm). Examination of representative samples of below-grade concrete, when

excavated for any reason, is to be included as part of a plant-specific program. ISG-03

also states that a plant-specific aging management program is recommended for

inaccessible areas if the below-grade environment is found to be aggressive.

The applicant stated that the below-grade/lake-water environment is not aggressive.

Also, the applicant stated that Its Structure Monitoring Program requires periodic

monitoring of ground/lake water to confirm chemistry remains nonaggressive.

The staff's review of LRA Section 3.5 identified an area in which additional information

was necessary to complete the review of the applicant's results. The applicant

responded to the staff's RAI as discussed below.

RAI 3.5-13. In LRA Section 3.5.2.2.1.1, the applicant stated that concrete degradation

in air due to aggressive rainwater is insignificant and that the below-grade/lake water

environment is nonaggressive. In RAI 3.5-13, dated March 30, 2005, the staff

requested the applicant to provide sufficient data to support this statement.

Furthermore, during the review, the staff was unable to identify how the LRA addresses

the items described in ISG-03. The staff requested the applicant to provide detailed

information as to how its AMRs address all the items described in ISG-03.

During conversations with the staff, the applicant agreed to provide its most recent data

with respect to the below-grade/lake water. Additionally, the applicant committed to

provide a table detailing how the AMRs satisfy all the items described in ISG-03. This

was identified as confirmatory item (Cl) 3.5-13.

In its response to Cl 3.5-13, by letter dated June 9, 2005, the applicant provided its

ground water environment monitoring data and an explanation of where the LRA

addresses each of the provisions of ISG-03. In addition, the applicant clarified the

percentage of entrapped air in the containment concrete. As part of the response, the

applicant committed to monitoring ground water chemistry (pH, chlorides, sulfates) at

least once every 5 years.

The staff found the applicant's response to RAI 3.5-13 and its commitment to monitor

ground water chemistry to be consistent with the guidance of the GALL Report and

ISG-03. The staff's concerns are resolved; therefore, Cl 3.5-13 is closed.

On the basis of its review, the staff found that, based on the nonaggressive

below-grade/lake-water environment and the periodic confirmatory water monitoring, the

application is consistent with the GALL Report, Chapter Il, Containment Structures,

Item A1.1-c, as updated by ISG-03, and demonstrated that cracking, spalling, and

increases in porosity and permeability due to aggressive chemical attack will be

adequately managed.

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(4) Reaction with Agareaates. SRP-LR Section 3.5.2.2.1.1 does not address cracking due

to reaction with aggregates as an aging mechanism for concrete containments because

no further evaluation is recommended in the GALL Report. However, ISG-03 clarifies

the staff position that further evaluation is appropriate if investigations, tests, or

examinations have demonstrated that the aggregates are reactive.

ISG-03 recommends using GALL AMP XI.S6, "Structures Monitoring Program," to

manage aggregate reactions in accessible areas. ISG-03 states that inspections and

evaluations performed in accordance with the Structures Monitoring Program will

indicate the presence of expansion and cracking due to reaction with aggregates. For

inaccessible areas, the ISG states that evaluation is needed if investigations, tests, and

petrographic examinations of aggregates performed in accordance with ASTM C295-54,

ASTM C227-50, or ACI 201.2R-77 (NUREG-1557) demonstrate that the aggregates are

reactive.

In LRA Table 3.5.0-1, Part (8), the applicant stated that the containment concrete

specifications specified testing of aggregate for potential reactivity in accordance with

ASTM C227 and C295. Based on the criteria of ISG-03 and the aggregate tests, which

demonstrated the lack of reactive aggregate, the staff agreed that evaluation of

inaccessible areas is not needed at PBNP.

On the basis of its review, the staff found that, based on the testing of aggregate for

potential reactivity performed during construction, the applicant is consistent with the

GALL Report, Chapter II, Containment Structures, Item A1.1-d, as updated by ISG-03,

and has demonstrated that cracking due to reaction with aggregates will be adequately

managed.

(5) Corrosion of embedded steel. SRP-LR Section 3.5.2.2.1.1 states that cracking,

spalling, loss of bond, and loss of material due to corrosion of embedded steel could

occur in inaccessible areas of PWR concrete and steel containments. The GALL

Report, as updated by ISG-03, 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.

The GALL Report, Chapter II, Containment Structures, Item A1.1 -e, states that for

below-grade exterior reinforced concrete (basemat, embedded walls), a plant-specific

aging management program is required only if the below-grade environment Is , aggressive (pH less than 5.5, chlorides are greater than 500 ppm, or sulfates are

greater than 1500 ppm). Examination of representative samples of below-grade

concrete, when excavated for any reason, is to be included as part a plant-specific

program. ISG-03 also states that a plant-specific aging management program is

required for inaccessible areas if the below-grade environment is found to be

aggressive.

In LRA Section 3.5.2.2.1.1, the applicant stated that the below-grade/lake-water

environment is not aggressive. Also, the applicant stated that its Structure Monitoring

Program requires periodic monitoring of ground/lake water to confirm that the water

chemistry remains nonaggressive.

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The staff found that based on the nonaggressive below-grade/lake-water environment

and the periodic confirmatory water monitoring, the application is consistent with the

GALL Report, Chapter II, Containment Structures, Item A1.1-e, as updated by ISG-03.

The applicant demonstrated that cracking, spalling, loss of bond, and loss of material

due to corrosion of embedded steel will be adequately managed.

The staff reviewed the results of the applicant's AMR for inaccessible concrete areas. On the

basis of its review and as discussed above, the staff found that the applicant had appropriately

evaluated AMR results involving management of aging of inaccessible concrete areas for the

containment, as recommended in the GALL Report and ISG-3. Since the applicant's AMR

results are otherwise consistent with the GALL Report, the staff found that the applicant had

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

Crackina. Distortion, and Increase in ComDonent Stress Level Due to Settlement: Reduction of

Foundation Strenath Due to Erosion of Porous Concrete Subfoundations. If Not Covered by

Structures Monitoring Program. The staff reviewed LRA Section 3.5.2.2.1.2 against the criteria

in SRP-LR Section 3.5.2.2.1.2.

SRP-LR Section 3.5.2.2.1.2 states that cracking, distortion, and increase in component stress

level due to settlement could occur in PWR concrete and steel containments. SRP-LR

Section 3.5.2.2.1.2 also states that reduction of foundation strength due to erosion of porous

concrete subfoundations could occur in all types of PWR containments.

The GALL Report recommends no further evaluation if these activities are included in the scope

of the applicant's Structures Monitoring Program.

In LRA Section 3.5.2.2.1.2, the applicant stated that all structures are founded on either spread

footings, basemats, or basemats with steel foundation piles that are driven to refusal.

Settlement monitoring and structural inspections indicate no visible evidence of uneven or

excessive settlement since construction of the station. In addition, in LRA Section 3.5.2.2.1.2,

the applicant stated that structure foundations were constructed of normal concrete and not the

porous type, and that the foundations are not subject to flowing water. The applicant also

stated that its Structures Monitoring Program monitors for settlement, cracking, and distortions.

The staff reviewed the applicant's Structures Monitoring Program and its evaluation is

documented in SER Section 3.0.3.2.19. On the basis of its review, the staff found that, based

on the foundation designs used at PBNP and on the absence of porous concrete in

subfoundations, the applicant satisfied the specific criteria in the GALL Report and

demonstrated that cracking, distortion, and increase in component stress level due to

settlement and reduction of foundation strength due to erosion of porous concrete

subfoundations will be adequately managed.

On the basis of its review, the staff found that the applicant had appropriately evaluated AMR

results involving management of cracking, distortion, and increase in component stress level

due to settlement; and reduction of foundation strength due to erosion of porous concrete

subfoundations, if not covered by Structures Monitoring Program for the containment, as

recommended in the GALL Report. Since the applicant's AMR results are otherwise consistent

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with the GALL Report, the staff found that the applicant had demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

Reduction of Strenath and Modulus of Concrete Structures Due to Elevated Temperature. The

staff reviewed LRA Section 3.5.2.2.1.3 against the criteria in SRP-LR Section 3.5.2.2.1.3.

In LRA Section 3.5.2.2.1.3, the applicant addressed reduction of strength and modulus of

concrete structures due to elevated temperature in containments.

SRP-LR Section 3.5.2.2.1.3 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 aging management program and recommends further

evaluation if any portion of the concrete containment components exceeds specified

temperature limits (i.e., general area temperature of 66 OC (150 OF) and local area temperature

of 93OC (200 OF)).

The applicant stated that for plant areas of concern, temperatures are normally maintained

below the specified limits. As documented in the audit and review report, the applicant stated

that, by design, containment concrete should not be exposed to temperatures above FSAR

specified limits; however, the applicant stated that four Unit 2 containment penetrations

associated with the main steam and feedwater systems concrete may be exposed to

temperatures above the specified limits. This Unit 2 nonconforming condition is captured and

addressed by the corrective action program. Currently, the status of the main steam

penetrations is operable but degraded. The applicant further stated that, as part of the plant's

existing corrective action process, the main steam penetrations would be inspected and

restored to original design conditions during the next Unit 2 refueling outage, which was

planned for Spring 2005.

The applicant stated that it included susceptible components within the scope of the Structures

Monitoring Program and the ASME Code Section Xi, Subsections IWE and IWL Inservice

Inspection Program, to monitor for loss of material, cracks, and changes in material properties.

The staff reviewed the applicant's Structures Monitoring Program and ASME Code Section Xl,

Subsections IWE and IWL Inservice Inspection Program, and its evaluations are documented in

SER Sections 3.0.3.2.19 and 3.0.3.2.2, respectively. The staff found that, based on the design

of the hot penetration areas, in combination with the resolution of the corrective action

associated with concrete that operated at an elevated temperature and continuing monitoring

under the Structures Monitoring Program and ASME Code Section Xi, Subsections IWE and

IWL Inservice Inspection Program, any reduction of strength and modulus of elasticity due to

elevated temperatures in PWR concrete will be adequately managed.

The staff's review of LRA Section 3.5 identified areas in which additional information was

necessary to complete the review of the applicant's results. The applicant responded to the

staff's RAls as discussed below.

RAI 3.5-3. In LRA Section 3.5.2.2.1.3, and LRA Table 3.5.0-1, Item 9 (plant-specific response

to WCAP-1 4756-A), the applicant asserted that the concrete temperatures around the

high-energy piping penetrations are well below the established threshold value of 200 OF.

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However, the applicant's report (PB OPR 000096) indicated that the concrete temperatures

around the main steam lines were found to be about 380 'F for an unknown period of time. The

staff noted that such sustained temperatures not only affect the concrete compressive strength

and its elastic modulus, but also accentuate the concrete creep and relaxation of prestressing

tendons located in the vicinity of high temperature areas. The net effect could lower tendon

forces in these areas. In RAI 3.5-3, dated July 27, 2004, the staff requested the applicant to

provide information regarding the actions taken to (1) control the concrete temperatures in

these areas, (2) assess the condition of the concrete in these areas, (3) assess the condition of

penetration liners, and (4) monitor the prestressing forces in the affected tendons. Also, the

applicant was requested to discuss the consequences of the sustained high temperatures on

the concrete and the prestressing tendons during the extended period of operation.

In its response, dated August 26, 2004, the applicant stated that the issues related to

Items 1, 2, and 3, above are captured as part of the non-conforming condition in the corrective

action program, namely: (1) CAP 51854, N2 MS Line Containment Penetration Concrete Temp

Above FSAR Specified Allowable dated 11/15/03, (2) OPR 96, N2 MS Line Containment

Penetration Concrete Temp Above FSAR Specified Allowable dated 11/16/03, (3) OBD

(operable but degraded) 124, U2 MS Line Cont Pen Concrete Temp Above FSAR Specified

Allowable - Action Plan dated 11/18/03, (4) OBD 134, Open & Inspect 2 Main Steam & 2 Main

Feedwater Penetrations of Unit 2 Containment dated 12/17/03.

With respect to RAI Item 4, the applicant stated that the Tendon Surveillance Program is in

accordance with the ASME Code Subsection IWL, 1992 Edition through 1992 Addenda, which

includes the limitations and modification requirements endorsed by 10 CFR 50.55a, and

RG 1.35, Revision 3, dated July 1990. The program also includes tendon prestressing force

inservice inspection and monitoring of time-dependent and other losses. The lift-off monitoring

test monitors all losses including relaxation of prestressing steel and effects of variations in

temperatures. To date, comparison of the measured tendon forces against the predicted forces

at the time of the lift-off has been well above the lower predicted limit. The applicant further

clarified that the non-conforming high temperature main steam line containment penetration

could have an effect on the hoop tendons. This condition was evaluated and documented in

Operability Recommendation OPR 96. The applicant noted that the tendon's exposure to the

slightly higher temperature, has occurred over a relatively short length of the tendon and it was

determined to present a negligible effect. The applicant indicated that consideration will be

given to include one of these random tendons for testing during the next regularly scheduled

surveillance test for that unit.

During the current license period, the applicant is addressing this issue through operability

evaluations and additional inspections. The staff will pursue this issue as a current licensing

concern to ascertain that the licensee will formalize a corrective action that would ensure the

effects of high temperatures on the concrete and the prestressing tendons are appropriately

addressed. The staff found that the ASME Code Section Xl, Subsections IWE and IWL

Inservice Inspection Program would provide the assurance of the containment integrity during

the period of extended operation. On the basis of the above discussion, the staff's concerns

described in RAI 3.5-3 are resolved.

RAI 3.5-5. The evaluation in LRA Section 3.5.2.2.1.3 associated with LRA Table 3.5.1 line Item

3.5.1-27 indicated that the reactor cavity cooling subsystem maintains acceptable ambient

temperature at the primary shield and reactor vessel support structure. In RAI 3.5-5, dated

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July 27,2004, the staff requested the applicant to provide the following information related to

the concrete temperatures and monitoring activities in the primary shield and reactor vessel

support areas for Units 1 and 2:

(1) Operating experience related to the functionality of the reactor cavity cooling subsystem

including a range of temperatures maintained between the reactor vessel and the

primary shield wall, and at the reactor vessel support, and means of monitoring these

temperatures;

(2) If a separate cooling system is installed to cool the primary shield wall concrete, the

operating experience related to the functionality of this system, and means used to

monitor the primary shield concrete temperatures; and

(3) A summary of the results of the last inspection performed in these areas, such as

concrete cracking, spalling, pop-outs, etc.

In its response, dated August 26, 2004, the applicant stated that in response to Item (1), the

primary concrete shielding and its temperature are discussed on FSAR page 11.6-3. The

reactor cavity cooling system (VNRC) consists of two fans and two cooling coils (one per fan).

The fans draw containment air over the service water cooling coils where the air is dehumidified

and cooled. The fans discharge the air into a common duct which supplies cooled air to the

reactor vessel annulus for cooling the primary shield wall and nuclear instrumentation

immediately external to the reactor. Normally, one fan and cooling coil set is in operation with

the other set in standby. The applicant further clarified that the VNRC is not within the scope of

license renewal. In addition, the applicant stated that the reactor cavity cooling fans are started

manually from the control room. Only one fan and service water cooler is required for operation

as each fan and cooler are sized for 100 percent capacity. Service water flow through the

coolers is manually controlled. A flow switch on the fan outlet indicates and alarms low flow

conditions on the control room control board. Temperature elements located in various areas

provide temperature information to the plant process computer system.

In response to item (2), the applicant stated that there is no separate cooling system employed

other than the reactor cavity cooling system. In response to item (3), the applicant explained

that the pressure boundary reactor vessel sump area is presently inspected in accordance with

the ASME Code IWE program. Inspections of component supports in this area are conducted,

as are inspections for the reactor vessel lower head. The applicant further stated that

enhancements are required to the Structural Monitoring Program to address the containment

non-pressure boundary internal structure inspections. The Structural Monitoring Program will

be enhanced to explicitly conduct and document a structural condition survey for this area. The

applicant also explained the process used for controlling the temperature and monitoringfI

degradation of structural components around the reactor vessel and the sump areas. The staff

found the inspections and monitoring measures acceptable.

The staff found the process used, including the planned enhancements, for managing the

degradation of structural components around the reactor vessel and the sump areas during the

period of extended operation adequate and acceptable. The staff's concerns described in

RAI 3.5-5 are resolved. l

r r i I : On the basis of its review, the staff found that the applicant had appropriately evaluated the

AMR results involving reduction of strength and modulus of concrete structures due to elevated

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temperature for the containment, as recommended in the GALL Report. Since the applicant's

AMR results are otherwise consistent with the GALL Report, the staff found that the applicant

had demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

Loss of Material Due to Corrosion in Inaccessible Areas of Steel Containment Shell or Liner

Plate. The staff reviewed LRA Section 3.5.2.2.1.4 against the criteria in SRP-LR

Section 3.5.2.2.1.4.

In LRA Section 3.5.2.2.1.4, the applicant addressed loss of material due to corrosion in

inaccessible areas of the steel containment shell or the steel liner plate for the containment.

SRP-LR Section 3.5.2.2.1.4 states that loss of material due to corrosion could occur in

inaccessible areas of the steel containment shell or the steel liner plate for all types of PWR

containments.

The GALL Report, Chapter II, Containment Structures, Item A1 .2-a states that for inaccessible

areas (embedded containment steel shell or liner), loss of material is not significant if the

following conditions are satisfied: (1) concrete meeting the requirements of ACI 318 or 349 and

the guidance of 201 .2R was used for the containment concrete in contact with the embedded

containment shell or liner; (2) the concrete is monitored to ensure that it is free of penetrating

cracks that provide a path for water seepage to the surface of the containment shell or liner; (3)

the moisture barrier, at the junction where the shell or liner becomes embedded, is subject to

aging management activities in accordance with IWE requirements; (4) borated water spills and

water ponding on the containment concrete floor are not common and when detected are

cleaned up in a timely manner. If any of the above conditions cannot be satisfied, then a

plant-specific aging management program for corrosion is recommended.

The applicant stated that plant operating experience has shown that borated water spills in

containment have impacted the containment liner and accordingly, the liner plate has been

selected to receive augmented inspections, category E-C, in accordance with ASME

Code Section Xl, Subsection IWE. In addition, the Boric Acid Corrosion Program is also

credited with assessing and managing loss of material in the containment liner.

The staff reviewed the applicant's Boric Acid Corrosion Program and is evaluation is

documented in SER Section 3.0.3.2.6.

The staff's review of LRA Section 3.5.2.2.1.4 identified an area in which additional information

was necessary to complete the review of the applicant's results. The applicant responded to

the staff's RAI as discussed below.

RAI 3.5-4. The Discussion column of LRA Item 3.5.1-12 refers to LRA Section 3.5.2.2.1.4 for

further evaluation. In the discussion, the applicant noted that liner corrosion was identified in

both units due to borated water leakage, and that ASME Code Subsection IWE augmented

inspections would be performed in these areas. In RAI 3.5-4, dated July 27, 2004, the staff

requested the applicant to provide a quantitative summary of extent of liner corrosion found in

each unit, and the corrective actions taken. The applicant was also requested to include a

discussion of acceptable liner plate corrosion before it is reinstated to its nominal thickness.

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In its response, dated August 26, 2004, the applicant stated that the areas of concern include

(1) the bottom containment liner plate (floor), which is covered by an eighteen-inch thick

concrete floor, and (2) SW and CCW penetrations. The penetrations have detectable pitting in

the flued head region. On occasion, spilled borated water has seeped into the liner plate floor

crevice. The liner plate floor receives UT measurements at selected locations. The applicant

further emphasized that the liner plate material loss has been minimal with no adverse effect to

the pressure boundary function. In addition, the applicant stated that Sump A had coating

degradation at the scum line but no notable material loss. Regarding the acceptable liner

corrosion, the applicant stated that there is no absolute limit for material loss exceeding a

percentage of nominal containment wall thickness that would necessitate a repair to restore

nominal thickness. The acceptance criteria are based on the effect, or impact, corrosion would

have on the containment structural integrity or leak tightness.

During a meeting, on February 15, 2005, the staff indicated and the applicant agreed, that this

response required further clarification. The staff requested the applicant to clarify the corrective

actions taken, when loss of material is identified in the containment penetration flued heads,

containment liner, or sump liner. The staff noted that IWE-3500 does not provide specific

guidance in this regard. The applicant was requested to provide a procedural description of the

corrective actions taken when such a loss of material is identified.

In its response, a clarification letter dated March 15, 2005, the applicant summarized that the

necessity for repair has been determined on a case-by-case basis. The table provided with the

response showed the liner plate base thickness reduction was as high as 46 percent. The

response indicated that such degradation was found acceptable without repair. Furthermore,

the response noted that the 1/4-inch liner plate design is based on the predicted strains without

leaking. As this process will be continued during the period of extended operation, the staff

requested additional information regarding the basic criteria used in the engineering evaluation.

The staff considered this an unresolved item. The staff requested the applicant to provide a

summary of the engineering evaluations performed for CAP 22754, and CAP 13912

(designated in the applicant's response table), including the type of corrosion (whether general,

pitting, galvanic, etc.), loads considered in the evaluation, acceptable liner strains, and strain

concentration factors considered, if applicable. The applicant was also requested to provide the

procedure describing the 'as left" condition of the degradation (e.g., repairing, cleaning, recoating, and a schedule for reexamination to verify stability of the degradation). This was

identified as open item (01) 3.5-4.

In its response to 01 3.5-4, by letter dated June 10, 2005, the applicant provided the condition

reports and the engineering evaluations (CR 01-1517 and CR 01-1220) prepared for the two

events. The staff reviewed the applicant's response and its evaluation is documented below.

* CR-01 -1517: The report refers to the NDE measurements of the basemat iiner in j988.

Based on the 13 year period (1975 to 1988), the report calciltesthe rate of Torosion

as .003 inches per year. The report concludes that it is very srniaiirated h ot1 vere

extending the same rate to 60 years will result in corrosion 0! !inertpte i D 18coies, nt 

leaving the plate thickness of 0.10 inch at the end of the pe of etendedpe nt rat.

This is not acceptable, in view of the fact that the basemat linejis inaccessible for IWE

inspections, unless the applicant monitors the affected area(s) under augmented

inspection (IWE-1241) and sets a limit on acceptable liner corrosion.

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* CR-01-1220: For the liner plate attached to the concrete wall, the report statement

*under normal operating condition, the liner experience no strain," is not correct.

Though the liner is not accounted for in structural calculations, by virtue of its being

anchored to the concrete, it experiences compressive strains due to dead load,

prestressing and creep of concrete. This is evidenced by a number of prestressed and

reinforced concrete containments having bulging of liners between the anchors. At the

bottom of the containment wall, it is subjected to bending strains due to hoop

prestressing and concrete creep. Unless an analysis is performed to show that, with the

reduced thickness of 0.116 inch, the liner will be able to withstand the postulated loads

without giving rise to a different mode of failure (e.g. pullout of the anchors, tearing of

the plate because of strain concentration). Such corrosion without corrective action is

not acceptable. The analysis must consider all the locked-in strains and superimposed

strains due to pressure, temperature, and the postulated seismic loads. In the

assessment, the staff noted that NRC has accepted up to 50 percent loss in liner

thickness in a very localized areas without such analysis.

Subsequently, the staff indicated and the applicant agreed that details with respect to these

engineering evaluations required further clarification. In its response dated July 8, 2005, the

applicant stated that the steel liner for the concrete containment building receives an inservice

inspection in accordance with IWE, 1992 Edition with 1992 Addenda. In accordance with

Table IWE-2500-1, the acceptance standards for Examination Category E-A, Containment

Surfaces, are discussed in IWE-3510 and IWE-3122. Conditions (degradation) that may affect

containment structural integrity or leak tightness shall be accepted by engineering evaluation or

corrected by repair or replacement. If thickness of the base metal is reduced by more than

10 percent of the nominal plate thickness, the component shall be acceptable by evaluation if

the reduced thickness can be shown by analysis to satisfy the requirements of the design

specifications. Furthermore, the applicant noted that if localized area thickness of the

containment liner base metal is reduced by 50 percent or more of the nominal plate thickness,

then, every attempt should be made to correct by repair or replacement. If the repair or

replacement option is impractical, an acceptance by engineering evaluation option may be

pursued. When component examination results require acceptance by engineering evaluation

for flaws or areas of degradation (IWE-3122.4) and the component is found to be acceptable

for continued service, the areas containing such flaws or degradation shall be re-examined

during the next inspection period scheduled in accordance with Table IWE-2500-1, Examination

Category E-C (IWE-2420(b)).

When the re-examinations reveal that the flaws or areas of degradation remain essentially

unchanged for three consecutive inspection periods, then the areas containing such flaws or

degradation no longer require augmented examination in accordance with Examination

Category E-C (IWE-2420(c)). If localized area thickness of the base metal is reduced by

approximately 50 percent or more of the nominal plate thickness, then the reexaminations

required by IWE-2420(b) will be continued in the succeeding inspection periods and the

provisions of IWE-2420(c) will not be applied. This evaluation, repair, or replacement

discussion, and reexaminations will be included in the Acceptance Criteria element of the

ASME Section Xl, Subsections IWE and IWL Inservice Inspection Program of the LRA

(Section B2.1.2). The above evaluation, repair or replacement, and re-examination

requirements will assure that leak-tightness and structural integrity of the liner will be

maintained.

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After describing the general methodology for evaluating cracks and degradation of the liner

plate, as discussed above, the applicant made the following commitments:

An evaluation, repair or replacement requirement discussion will be included in the

Acceptance Criteria element of the ASME Section Xl, Subsections IWE and IWL

Inservice Inspection Program of the LRA prior to the period of extended operation. If

localized area thickness of the containment liner base metal is reduced by 50 percent or

more of the nominal plate thickness, then every attempt should be made to correct by

repair or replacement. If the repair or replacement option is impractical, an acceptance

by engineering evaluation option may be pursued.

* If localized area thickness of the base metal is reduced by approximately 50 percent or

more of the nominal plate thickness, then the re-examinations required by IWE 2420(b)

will be continued in the succeeding inspection periods and the provisions of

IWE-2420(c) will not be applied.

Based on the applicant's responses to RAI 3.5-4, the description of the process and the

commitments discussed above, the staff found the overall approach in detecting and correcting

the flaws and degradation in the containment liner plates acceptable. The staff's concerns are

resolved; therefore, 01 3.5-4 is closed.

On the basis of Its review, the staff found that the applicant had appropriately evaluated AMR

results involving loss of material due to corrosion in inaccessible areas of the steel containment

shell or the steel liner plate for the containment, as recommended in the GALL Report. Since

the applicant's AMR results are otherwise consistent with the GALL Report, the staff found that

the applicant had demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

Loss of Prestress Due to Relaxation. Shrinkage. CreeD. and Elevated Temperature. In LRA

Section 3.5.2.2.1.5, the applicant stated that loss of prestress is a TLAA, as defined in

10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21 (c)(1). SER

Section 4.5 documents the staff's review of the applicant's evaluation of this TLAA.

Cumulative Fatigue Damage. In LRA Section 3.5.2.2.1.6, the applicant stated that fatigue is a

TLAA, as defined in 10 CFR 54.3. Applicants'must evaluate TLAAs in accordance with

10 CFR 54.21 (c)(1). SER Section 4.3 documents the staff's review of the applicant's evaluation

of this TLAA.

Cracking Due to Cyclic Loadinq and Stress Corrosion Cracking (SCC). The staff reviewed LRA

Section 3.5.2.2.1.7 against the criteria in SRP-LR Section 3.5.2.2.1.7.

In LRA Section 3.5.2.2.1.7, the applicant addressed cracking due to cyclic loading and SCC.

SRP-LR Section 3.5.2.2.1.7 states that cracking of containment penetrations due to cyclic

loading or SCC could occur in containments. Further evaluation of inspection methods is

recommended to detect cracking due to cyclic loading and SCC because visual (VT-3)

examinations may be unable to detect this aging effect.

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The applicant stated that a fatigue review was performed for the liner penetrations and that

cracking due to cyclic loading is addressed as a TLAA in LRA Section 4.3.11. Additionally, the

applicant stated that carbon steel components within penetrations are not susceptible to SCC

and that stainless steel components require both a high temperature, greater than 140 OF, and

exposure to an aggressive chemical environment (e.g., exposure to chlorides). The bellows at

PBNP are not exposed to aggressive chemical environments.

The staff reviewed the information provided in the LRA and agreed with the applicant that

carbon steel components within penetrations are not susceptible to SCC, persuant to the GALL

Report guidance. Also, cracking due to cyclic loading of the liner plate and penetrations is a

TLAA which is evaluated and discussed in SER Section 4.6.

The staff's review of LRA Section 3.5.2.2.1.7 identified areas in which additional information

was necessary to complete the review of the applicant's results. The applicant responded to

the staff's RAI as discussed below.

RAI 3.5-12. In LRA Section 3.5.2.2.1.7, the applicant stated that SCC is not an applicable

aging mechanism for penetrations, sleeves, bellows, and dissimilar metal welds. The applicant

also stated that the liner penetrations have had a fatigue review and are bounded by the GALL

Report line Item 3.5.1-01/ll.A3.1-b. Therefore, the applicant did not address cracking due to

cyclic loading. In RAI 3.5-12, dated -March 30, 2005, the staff requested the applicant to

address the difference between its position and the GALL Report recommendation of enhanced

inspection methods. The staff noted that the TLAA in LRA Section 4.3.11 does not detect and

manage cracking due to cyclic loading. The applicant was requested to provide further

clarification for crediting this specific line Item to manage cracking due to cyclic loading.

During conversations with the staff, the applicant clarified that if explicit fatigue analyses were

performed, then only a TLAA is required. The staff agreed with the applicant's approach. The

applicant will provide a formal letter to reflect this statement. This was identified as

confirmatory item (Cl) 3.5-12.

In its response to Cl 3.5-12, by letter dated June 9, 2005, the applicant clarified its basis for

concluding that the use of a fatigue analysis as the basis for managing fatigue is consistent with

the positions stated in the GALL Report (NUREG-1801 Vol. 1, Table 5, Items 3.5.1-1 and

3.5.1-2). In addition, the applicant stated that SCC is not an applicable aging effect, due to the

lack of an aggressive chemical environment. Further, the applicant clarified that aging

management of the containment penetration sleeves is addressed by the ASME Section Xl,

Subsection IWE and IWL Inservice Inspection Program and the Boric Acid Corrosion Program.

Lastly, the applicant stated that PBNP does not have any penetration bellows in the scope of

license renewal.

The staff found the applicant's response to RAI 3.5-12, the categorization of aging effects and

its aging management appropriate and consistent with the guidance of the GALL Report. The

staff's concern is resolved and, therefore, Cl 3.5-12 is closed.

RAI 3.5-1. In discussing LRA Table 3.5.1 Item Number 3.5.1-3, the applicant stated that the

AMR results are consistent with NUREG-1 801. NUREG-1 801, Item A3.1 recommends further

evaluation regarding the stress corrosion cracking of containment bellows. In RAI 3.5-1, dated

July 27, 2004, the staff requested the applicant to provide additional information regarding the

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containment pressure boundary bellows, relevant operating experience, and method(s) used to

detect their age-related degradation. The staff also noted that in many cases, IWE VT-3

examination and Appendix J, Type B testing cannot detect aging effects as discussed in NRC

IN 92-20.

In its response, dated August 26, 2004, the applicant stated that PBNP does not have any

containment penetration bellows that function as a pressure boundary within the scope of

license renewal. The applicant referred to FSAR pages 5.1-65 and 5.1-66, and Figures 5.1-2

and 5.1-16 for a description of the configuration of the containment penetrations, and clarified

that containment bellows are not provided as part of the containment pressure boundary

design. All penetrations with bellows are external to containment and are not subject to

containment pressure. The applicant noted that the fuel transfer tube penetration has bellows

with a leak-tight barrier function for refueling water at the refueling cavity and no containment

pressure boundary function. The staff's review of the figures cited by the applicant confirmed

that the PBNP containments do not have any pressure boundary bellows. The staff's concerns

described in RAI 3.5-1 are resolved.

On the basis of its review, the staff found that the applicant had appropriately evaluated AMR

results involving management of cracking due to cyclic loading and stress corrosion cracking

for the containment, as recommended in the GALL Report. Since the applicant's AMR results

are otherwise consistent with the GALL Report, the staff found that the applicant had

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

RAI 3.5-2. During its review, the staff inquired about the integrity of seals and gaskets of the

containment mechanical and electrical penetrations. For seals and gaskets related to

containment penetrations, in LRA Item Number 3.5.1-6, containment ISI and containment leak

rate testing have been identified as the designated aging management programs. For

equipment hatches and air-locks, the staff agreed with the applicant's assertion that the leak

rate testing program will monitor aging degradation of seals and gaskets, as they are leak rate

tested after each opening. In RAI 3.5-2, dated July 27, 2004, the staff requested the applicant

to provide information regarding the adequacy of Type B leak rate testing frequency to monitor

aging degradation of seals and gaskets of mechanical and electrical penetrations.

In its response, dated August 26, 2004, the applicant stated that PBNP is committed to

Option B of 10 CFR 50, Appendix J. RG 1.163 stipulates a local leak rate test (LLRT)

frequency of up to 60 months for Type C tested penetrations. The applicant affirmed that

PBNP employs the same 60-month maximum frequency for all Type B tested penetrations.

The penetrations of interest are the ones that utilize an elastomer seal and are Type B tested.

The applicant also stated that the affected penetrations include the Conax and Westinghouse

modular electrical penetration assembles (EPA), and noted that the majority of the EPAs are of

the Westinghouse canister type with no elastomer material.

The staff found the response acceptable, as the applicant will monitor the integrity of the seals

and gaskets associated with the containment mechanical and electrical penetrations every 60

months in accordance with the RG 1.163 criteria. The staff's concern described in RAI 3.5-2 is

resolved.

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On the basis of its review, the staff found that the applicant had appropriately evaluated AMR

results for the containment, as recommended in the GALL Report. Since the applicant's AMR

results are otherwise consistent with the GALL Report, the staff found that the applicant had

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.5.2.2.2 Class 1 Structures

The staff reviewed LRA Section 3.5.2.2.2 against the criteria in SRP-LR Section 3.5.2.2.2,

which addresses several areas discussed below.

Aging of Structures Not Covered by Structures Monitoring Program. The staff reviewed LRA

Section 3.5.2.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.2.1.

In LRA Section 3.5.2.2.2.1, the applicant addressed aging of Class 1 structures not covered by

the Structures Monitoring Program.

SRP-LR Section 3.5.2.2.2.1 states that the GALL Report recommends further evaluation of

certain structure/aging effect combinations if they are not covered by the Structures Monitoring

Program. This is described in GALL Report Chapter III and includes (1) scaling, cracking, and

spalling due to repeated freeze-thaw for Groups 1-3, 5, 7-9 structures; (2) scaling, cracking,

spalling and increase in porosity and permeability due to leaching of calcium hydroxide and

aggressive chemical attack for Groups 1-5, 7-9 structures; (3) expansion and cracking due to

reaction with aggregates for Groups 1-5, 7-9 structures; (4) cracking, spalling, loss of bond, and

loss of material due to corrosion of embedded steel for Groups 1-5, 7-9 structures; (5) cracks,

distortion, and increase in component stress level due to settlement for Groups 1-3, 5, 7-9

structures; (6) reduction of foundation strength due to erosion of porous concrete

subfoundations for Groups 1-3, 5-9 structures; (7) loss of material due to corrosion of structural

steel components for Groups 1-5, 7-8 structures; (8) loss of strength and modulus of concrete

structures due to elevated temperatures for Groups 1-5; and (9) crack initiation and growth due

to SCC and loss of material due to crevice corrosion of stainless steel liner for Groups 7 and 8

structures. Further evaluation is necessary only for structure/aging effect combinations not

covered by the Structures Monitoring Program.

Also, technical details of the aging management issue are presented in SRP-LR

Subsection 3.5.2.2.1.2 for structure/aging effect combinations Items (5) and (6) and SRP-LR

Subsection 3.5.2.2.1.3 for Item (8), above.

In LRA Section 3.5.2.2.2 and Tables 3.5.1 and 3.5.2-1, 3.5.2-6, and 3.5.2-10, the applicant

indicated that the Structures Monitoring Program will not be used to manage the aging effects

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due to loss of material for those steel structural elements potentially exposed to borated water

leakage. These structural elements Include:

a

S

S

0

ASME equipment, and pipe supports

and restraints

containment liner plate

containment penetrations

crane support girders

electrical enclosures

equipment supports, pipe restraints

framing columns and beams

HVAC ducts and supports

mechanical equipment

non-ASME equipment supports

* panels and cabinets

* platforms and stairs

* raceway supports

* raceways

* roof truss

* structural framings

* structural fasteners of RCS component

supports

* supports of miscellaneous steel

structures

The applicant proposed to use the Boric Acid Corrosion Program to manage the aging effects

caused by boric acid corrosion. According to the applicant, this program complies with its

response to NRC GL 88-05 and requires periodic visual inspection of systems that contain

borated water for evidence of leakage or accumulations of dried boric acid. This inspection will

cover all structural elements listed above. As stated in LRA Section B2.1.6, this program is an

existing program that is consistent, without exceptions, with GALL XI.M1 0, "Boric Acid

Corrosion." On this basis, the staff concluded that the use of the Boric Acid Corrosion Program

to manage the aging effects of above mentioned steel structural elements due to loss of

material caused by boric acid wastage is acceptable.

In LRA Section 3.5.2.2.2 and Tables 3.5.1 and 3.5.2, the applicant indicated that the Structures

Monitoring Program will not be used to cover concrete structural elements to be used as fire

barriers, flood barriers, missile barriers, shelters and supports. These structural elements

include walls, ceilings, floors, columns, roofs, equipment pedestals, and the spent fuel pool.

For these concrete structural elements, the applicant stated that no aging effects requiring

management were identified. However, the applicant proposed to use the Fire Protection

Program for periodic monitoring of potential degradation. As stated in LRA Section B2.1.10,

under this program, periodic visual inspections of structural elements will be performed to

ensure that the function capability and operability of these barriers is maintained. From its

review of the LRA, the staff found that the aging effects of concrete structural elements will be

managed by the Structures Monitoring Program and that periodic inspection under the Fire

Protection Program will be performed to ensure that the intended functions of these structural

elements are maintained.

The staff's review of LRA Section 3.5.2.2.2 identified an area in which additional information

was necessary to complete the review of the applicant's results. The applicant responded to

the staff's RAI as discussed below.

RAI 3.5-11. In LRA Table 3.5.2-2, the applicant indicated that aging effects (changing material

properties and loss of material of all wood/outdoor with the intended function of missile barrier)

are to be managed by the Structures Monitoring Program. However, the staff's review of LRA

Section B2.1.20 found that the scope of the Structures Monitoring Program does not include

wood components. In RAI 3.5-11, dated July 7, 2004, the staff requested the applicant to

clarify how the aging effects on wood structures will be managed.

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In its response, dated August 26, 2004, the applicant stated that the Structures Monitoring

Program, as detailed in LRA Appendix B, provides a detailed discussion of the 10 program

elements. The element "Parameters Monitored or Inspected" does not explicitly make

reference to wood material. The applicant clarified that the omission of reference to wood

material was an oversight, as this item is presented in LRA Table 3.5.2-2 on page 3-446. The

applicant committed to correct this omission during the annual LRA update. The staff

determined that the applicant's commitment is acceptable and resolves the staff's concern

described in RAI 3.5-11.

In LRA Section 3.5.2.2.2.1, the applicant stated that its Structures Monitoring Program identifies

that an aging mechanism is present and active. The applicant stated that the Structures

Monitoring Program also provides confirmation and verification of the absence of all types of

aging effects. The applicant further stated that aging effects may be absent if the materials of

construction, design specifications, and operational environment preclude an aging mechanism,

but it is prudent to periodically assess the condition of SSCs regardless of the likelihood that a

particular aging mechanism is applicable. The staff reviewed the applicant's Structures

Monitoring Program and its evaluation is documented in SER Section 3.0.3.2.19. Additional

discussion of specific structure/aging effect combinations is documented below.

(1) Freeze-thaw. SRP-LR Section 3.5.2.2.1.2 does not address freeze-thaw as an aging

mechanism for concrete containments because no further evaluation is recommended in

the GALL Report. However, ISG-03 clarifies the staff position that further evaluation is

appropriate if the applicant's facility is subject to moderate to severe weathering

conditions unless the concrete meets certain specifications and subsequent inspections

have confirmed that the aging mechanism has not caused degradation of the concrete.

PBNP is located in a region considered to have severe weathering conditions. In the

LRA, the applicant stated that the contract specified air contents are within the range

specified by ACI 318-63, and the contract specified water-to-cement ratio meets the

recommendations of ACI 318-63. Therefore, loss of material and cracking of concrete

due to freeze-thaw are not probable aging effects and have not been observed to date.

The staff interviewed the applicant's technical staff and confirmed that the concrete at

PBNP was allowed to properly cure. In addition, it was confirmed that a loss of material

from freeze-thaw has not been observed, either through the applicant's ASME Code

Section Xl, Subsections IWE and IWL Inservice Inspection Program or the Structures

Monitoring Program.

On the basis that concrete that satisfies the requirements of ACI 318-63 will meet the

recommendations of the GALL Report as clarified by ISG-03, and on the basis of the

lack of freeze-thaw effects to date, the staff found that loss of material and cracking due

to freeze-thaw will be adequately managed.

(2a) Leaching of calcium hydroxide. SRP-LR Section 3.5.2.2.2.1 states that cracking,

spalling, and increases in porosity and permeability due to leaching of calcium hydroxide

could occur in inaccessible areas of PWR concrete and steel containments. The GALL

Report, as updated by ISG-3, recommends further evaluation of plant-specific programs

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to manage the aging effects for inaccessible areas exposed to flowing water, unless the

criteria of ACI 201.2R are met.

The GALL Report states that leaching of calcium hydroxide becomes significant only if

the concrete is exposed to flowing water. Even if reinforced concrete is exposed to

flowing water, such leaching is not significant if the concrete Is constructed to ensure

that it is dense, well-cured, has low permeability, and that cracking is well controlled.

The applicant stated that the original specifications met the intent of ACI 201.2R, and

that a change in material properties due to leaching of calcium hydroxide is not a

probable aging effect and has not been observed to date. The applicant used concrete

per ACI 318-63 to construct these components. The differences between the ACI 318

concrete and ACI 201 standard are concrete rated at 3500 psi, some concrete cured to

a time that was slightly shorter, use of type 1 versus type 2 cement and tested its

aggregate per alternate ASTM C 295 and C 227. The lower strength and shorter cure

time were consistent with the plant design criteria and affect abrasion resistance

primarily. Type 1 cement is a higher quality cement than type 2. The alternate

aggregate ASTM test standards are accepted by the GALL Report as an alternative.

As documented in the audit and review report, the staff reviewed the information

provided in the LRA and held discussions with the applicant. The staff considered these

differences and concluded that the ACI concrete possesses comparable aging

resistance properties and will perform as well as concrete fabricated to the later ACI

201-2R guidance. The staff found that, based on the concrete specifications for Class 1

structures, the applicant is consistent with the GALL Report as updated by ISG-03, and

demonstrated that cracking, spalling, and increases in porosity and permeability due to

leaching of calcium hydroxide will be adequately managed.

(2b) Aggressive chemical attack. SRP-LR Section 3.5.2.2.2.1 states that cracking, spalling,

and increases in porosity and permeability due to aggressive chemical attack could

occur in inaccessible areas of Class 1 structures. The GALL Report recommends

further evaluation of plant-specific programs to manage the aging effects for

inaccessible areas if specific criteria defined in the GALL Report, as updated in ISG-3,

cannot be satisfied.

The GALL Report, as updated by ISG-03, states that aggressive chemical attack is not

significant unless pH is less than 5.5, chlorides are greater than 500 ppm, or sulfates

are greater than 1500 ppm.

The applicant stated that concrete degradation in air due to aggressive rainwater is

insignificant and the below-grade environment is not aggressive. The Structures

Monitoring Program requires periodic monitoring of ground/lake water to confirm that the

water chemistry remains nonaggressive. Concrete degradation due to aggressive

chemical attack has not been observed to date at PBNP.

The staff's review of LRA Section 3.5.2.2.2.1 identified an area in which additional

information was necessary to complete the review of the applicant's results. The

applicant responded to the staff's RAI as discussed below.

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RAI 3.5-10. In LRA Section 3.5.2.2.2.1, the applicant stated-that the Structures

Monitoring Program requires periodic monitoring of ground/lake water to verify that the

chemistry remains non-aggressive. However, the staff's review of the Structures

Monitoring Program (LRA Item B2.1.20) revealed that the applicant did not commit to a

program to monitor the groundllake water chemistry. Therefore, in RAI 3.5-10, dated

July 27, 2004, the staff requested the applicant to clarify this inconsistency.

In its response, dated August 26, 2004, the applicant stated that PBNP has a

groundwater monitoring program (reference NP 7.7.9, Attachment D and Form

PBF-7043). Data have been collected for groundwater level and chemical analysis,

including pH and chloride determination. The applicant further indicated that

groundwater level measurements are performed at an initial frequency once every

quarter. The applicant will initially perform groundwater chemistry (pH, chlorides, and

sulfates) monitoring at a frequency of once every nine months. At such frequency,

monitoring will facilitate obtaining data affected by the seasonal rotation. A number of

data points would be obtained with the above frequency. Based on an analysis and

trend of the data, a determination will be made as to the appropriate frequency for

continued monitoring. Subsequently, in response to Cl 3.5-13, by letter dated

June 9, 2005, the applicant committed to monitor ground water chemistry at least once

every 5 years. The staff's review found that the applicant does have a groundwater

monitoring program to be used to monitor the quality of groundwater by collecting data,

analyzing water chemistry and content, and ensuring that the quality of groundwater

meets the GALL criteria. On this basis, the staff's concern described in RAI 3.5-10 is

resolved.

The staff found that, based on the nonaggressive below-grade/lake-water environment,

the applicant is consistent with the GALL Report, as updated by ISG-03, and has

demonstrated that cracking, spalling, and increases in porosity and permeability due to

aggressive chemical attack will be adequately managed.

(3) Reaction with aaggreaates. SRP-LR Section 3.5.2.2.2.1 does not address reaction with

aggregates as an aging mechanism for concrete containments because no further

evaluation is recommended in the GALL Report. However, ISG-03 clarifies the staff

position that further evaluation is appropriate if investigations, tests, or examinations

have demonstrated that the aggregates are reactive.

The applicant stated that during construction, the aggregates were tested for potential

reactivity in accordance with ASTM C227 and ASTM C295. Consequently, cracking and

expansion due to reaction with aggregates are not probable aging effects and have not

been observed to date.

ISG-03 states that aggregates are not reactive if constructed with concrete using the

ASTM standards. The staff found that the applicant tested the aggregates using the

ASTM standards, as recommended by the GALL Report, as updated by ISG-03, and

demonstrated that cracking due to reaction with aggregates will be adequately

managed.

(4) Corrosion of embedded steel. SRP-LR Section 3.5.2.2.2.1 states that loss of material

due to corrosion of embedded steel could occur in inaccessible areas of Class 1

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structures. The GALL Report, as updated by ISG-03, 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.

The GALL Report states that a plant-specific program is required only if the below-grade

environment is aggressive.

The applicant stated that, since the embedded steel is not exposed to an environment

that is considered aggressive, loss of material, cracking, and loss of bond due to

corrosion of embedded steel are not probable aging effects and have not been observed

to date.

The staff's review of LRA Section 3.5.2.2.2.1 identified an area in which additional

information was necessary to complete the review of the applicant's results. The

applicant responded to the staff's RAI as discussed below.

RAI 3.5-6. LRA Section 3.5.2.2.2.1, "Aging of Structures Not Covered by Structures

Monitoring Program," states that since the embedded steel is not exposed to an

environment that is considered aggressive, loss of material, cracking, and loss of bond

due to corrosion of embedded steel are not probable aging effects and have not been

observed to date. The staff's concern is that, based on its past experience, many cases

of corroded embedded steel (rebars and/or anchors) have been identified even within

reinforced concrete elements exposed to a non-aggressive environment. In RAI 3.5-6,

dated July 27, 2004, the staff requested the applicant to provide a basis for its

statement.

In its response, dated August 26, 2004, the applicant referred to GALL Item III.A1 .1-e,

which states that if the environment is not aggressive, the aging effects such as loss of

material, cracking, and loss of bond are not significant. In addition, in its response to

RAI 3.5-10, the applicant committed to initially monitor water chemistry every nine

months to ensure that the contents (pH, chlorides, and sulfate) of groundwater are

within the GALL limits. Based on an analysis and trend of the data, a determination will

be made as to the appropriate frequency for continued monitoring. The staff considers

the applicant's response acceptable because the applicant's commitment ensures aging

management. The staff's concern described in RAI 3.5-6 is resolved.

The staff found that, based on the nonaggressive below-grade/lake-water environment,

the applicant is consistent with the GALL Report, as updated by ISG-03, and

demonstrated that cracking, spalling, loss of bond, and loss of material due to corrosion

of embedded steel will be adequately managed.

(5) Settlement. SRP-LR Section 3.5.2.2.2.1 refers to SRP-LR Section 3.5.2.2.1.2 for

discussion of settlement. SRP-LR Section 3.5.2.2.1.2 states that cracking, distortion,

and increase in component stress level due to settlement could occur in Class 1

structures. Some plants may rely on a dewatering system to lower the site groundwater

level. If the plant's CLB credits a dewatering system, the GALL Report recommends

verification of the continued functionality of the dewatering system during the period of

extended operation. The GALL Report recommends no further evaluation if this activity

is included within the scope of the applicant's Structures Monitoring Program.

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In LRA Section 3.5.2.2.2.1, the applicant stated that all structures are founded on either

spread footings, basemats, or basemats with steel foundation piles that are driven to

refusal. Settlement monitoring and structural inspection indicate no visible evidence of

uneven or excessive settlement since construction of the station. Cracking, distortion,

and an increase in component stress levels due to settlement are not probable aging

effects and have not been observed to date. Additionally, according to LRA

Table 3.5.0-1, Item 13, there is no permanent dewatering system at PBNP.

The staff's review of LRA Section 3.5.2.2.2.1 identified an area in which additional

information was necessary to complete the review of the applicant's results. The

applicant responded to the staff's RAI as discussed below.

RAI 3.5-7. Based on observed experience, as long as structural foundations are

founded on soils, even with spread footings, basemats, or basemats with steel piles

driven to the refusal, etc., it is expected that settlements will occur, especially for sandy

soil. These settlements, in most cases, cannot be detected by visual inspection. In

RAI 3.5-7, dated July 27, 2004, the staff requested the applicant to clarify its statement

that settlement monitoring and structural inspections did not indicate visible evidence of

uneven or excessive settlement since construction of the station. The applicant was

requested to substantiate its statement based on measurements taken instead of visual

observations or judgment.

In its response, dated August 26, 2004, the applicant stated that consolidation of soils

beneath building foundations typically occurs within the first three to four years after

construction. Consolidation of the soil after that time frame is typically negligible. PBNP

has a facilities settlement monitoring program (reference NP 7.7.9, Attachment E and

Bechtel drawing 6118-C-102). During original plant construction, numerous

benchmarks were established throughout the plant. The benchmarks were first

surveyed in the fall of 1969. Subsequent surveys have been performed and differential

settlement values determined. To date, the average differential settlement from all

benchmarks is 0.636 inches. The maximum differential settlement between any of the

points (non-adjacent) is 1.296 inches. The applicant confirmed that settlement

monitoring will continue during the period of extended operation.

The staff's review of the applicant's response found that the settlement of plant building

structures was monitored by survey (instead of visual inspection) under the settlement

monitoring program. The average differential settlement from all benchmarks is less

than one inch and the maximum differential settlement between any of the points

(non-adjacent) is 1.296 inches, which is negligible. The applicant also committed in the

response to continue settlement monitoring during the period of extended operation. On

the basis of its evaluation and the above discussion the staff's concern described in

RAI 3.5-7 is resolved.

The staff found that, based on the foundation designs used at PBNP, the applicant

satisfied the specific criteria in the GALL Report and demonstrated that cracking,

distortion, and increase in component stress level due to settlement will be adequately

managed.

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(6) Erosion of norous concrete subfoundation. SRP-LR Section 3.5.2.2.2.1 refers to

SRP-LR Section 3.5.2.2.1.2 for discussion of erosion of porous concrete subfoundation.

SRP-LR Section 3.5.2.2.1.2 states that reduction of foundation strength due to erosion

of porous concrete subfoundations could occur in all types of Class 1 structures. Some

plants may rely on a dewatering system to lower the site groundwater level. If the

plant's CLB credits a dewatering system, the GALL Report recommends verification of

the continued functionality of the dewatering system during the period of extended

operation. The GALL Report recommends no further evaluation if this activity is

included in the scope of the applicant's Structures Monitoring Program.

SRP-LR Section 3.5.2.2.1.2 states that reduction of foundation strength due to erosion

of porous concrete subfoundations could occur in all types of PWR containments. LRA

Section 3.5.2.2.1.2 states that the structure foundations were constructed of normal

concrete and not the porous type, and that the foundations are not subject to flowing

water. The Structures Monitoring Program monitors for settlement and cracking.

The staff found that, based on the foundation designs used at PBNP and based on the

absence of porous concrete in subfoundations, the applicant has satisfied the specific

criteria in the GALL Report and demonstrated that cracking, distortion, and increase in

component stress level due to settlement and reduction of foundation strength due to

erosion of porous concrete subfoundations will be adequately managed.

(7) Corrosion of structural steel components. SRP-LR Section 3.5.2.2.2.1 states that

corrosion of structural steel components could occur and that further evaluation is

necessary only for structure/aging effect combinations not covered by the Structures

Monitoring Program.

The staff reviewed the AMR results involving management of aging effects resulting

from corrosion of structural steel components and confirmed that the Structures

Monitoring Program addresses each of the affected SSCs. The staff reviewed the

applicant's Structures Monitoring Program and its evaluation is documented in SER

Section 3.0.3.2.19. On the basis of its review, the staff found that the applicant had

appropriately evaluated AMR results involving this aging effect and that corrosion of

structural steel components is adequately managed by the Structures Monitoring

Program.

(8) Elevated temperatures. SRP-LR Section 3.5.2.2.2.1 refers to SRP-LR

Section 3.5.2.2.1.3 for discussion of elevated temperatures. SRP-LR

Section 3.5.2.2.1.3 states that reduction of strength and modulus of elasticity due to

elevated temperatures could occur in Class 1 structures. The GALL Report calls for a

plant-specific aging management program and recommends further evaluation if any

portion of the concrete components exceeds specified temperature Jimts (i.e., general

area temperature 660C (150°F) and local area temperature 93°C ( '00IF)).

The applicant stated that for plant areas of concern, temperatures n iormally

maintained below the specified limits; therefore, loss of material, cracking, change in

material properties due to elevated temperatures are not probable aging effects and

have not been observed to date. However, fin response to RAI 3.5-3, the applicant

stated that the concrete temperatures in Unit 2 around the main steam lines were found

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to be about 380 'F for an unknown period of time. Such sustained temperatures not

only affect the concrete compressive strength and its elastic modulus, but they also

accentuate the concrete creep and relaxation of prestressing tendons located in the

vicinity of high temperature areas. The net effect could be lower tendon forces in these

areas. In its response, dated August 26, 2004, the applicant stated that in 2003

corrective actions were initiated to address this issue. The applicant further stated that

the penetrations will be restored to their original design condition during the Unit 2

Spring 2005 refueling outage. This inspection will confirm whether or not there are any

adverse conditions. If adverse conditions are identified, corrective actions will be taken.

The staff reviewed the applicant's Structures Monitoring Program and its evaluation is

documented in SER Section 3.0.3.2.19. The staff also reviewed the AMR results and

RAI response involving management of aging effects resulting from elevated

temperature. The staff found that the applicant had appropriately evaluated AMR

results involving reduction of strength and modulus due to elevated temperature, as

recommended in the GALL Report, and that it is adequately managed by the Structures

Monitoring Program.

(9) Agina effects for stainless steel liners for tanks. The applicant stated that no tanks with

stainless steel liners are included in the structural AMRs. Tanks subject to an AMR are

evaluated with their respective mechanical systems.

On the basis of its review, the staff agreed that no tanks with stainless steel liners are

included in the structural AMRs.

The staff reviewed the results of the applicant's AMR for accessible interior and exterior

concrete and steel components of Class 1 structures. On the basis of its review, the staff found

that the applicant had appropriately evaluated AMR results involving management of aging of

accessible interior and exterior concrete and steel components of Class I structures. Since the

applicant's AMR results are otherwise consistent with the GALL Report, the staff found that the

applicant had demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

Aging Management of Inaccessible Areas. The staff reviewed the LRA Section 3.5.2.2.2.2

against the criteria in SRP-LR Section 3.5.2.2.2.2.

In LRA Section 3.5.2.2.2.2, the applicant addressed aging of inaccessible areas of Class 1

structures.

SRP-LR Section 3.5.2.2.2.2 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 due to corrosion of embedded steel could occur in below-grade inaccessible concrete

areas. The GALL Report recommends further evaluation to manage these aging effects in

inaccessible areas of Groups 1-3, 5, 7-9 structures, if an aggressive below-grade environment

exists.

The applicant stated that the below-grade environment is not aggressive. The applicant uses

the Structures Monitoring Program to examine below-grade concrete when it is exposed by

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excavation and monitor the ground/lake water to confirm that the chemistry remains

nonaggressive. Inspections of accessible concrete have not revealed degradation from

aggressive chemical attack or corrosion of embedded steel.

The staff reviewed the applicant's Structures Monitoring Program and its evaluation is

documented in SER Section 3.0.3.2.19. The staff agreed with the applicant that the

below-grade environment is not aggressive and that excavated concrete has been and will

continue to be monitored. The staff found that increases in porosity and permeability, loss of

material, cracking due to aggressive chemical attack and cracking, loss of bond, and loss of

material due to corrosion of embedded steel are adequately managed for concrete in

inaccessible areas.

The staff's review of LRA Section 3.5.2.2.2.2 identified areas in which additional information

was necessary to complete the review of the applicant's results. The applicant responded to

the staff's RAls as discussed below.

RAI 3.5-8. LRA Section 3.5.2.2.2.2, states that since the below-grade/lake water environment

is nonaggressive and the structures monitoring program requires periodic monitoring of

ground/lake water to verify that the water chemistry remains non-aggressive, the loss of

material and change in material properties due to aggressive chemical attack are not probable

aging effects at PBNP. Also, since the embedded steel is not exposed to an environment that

is considered aggressive, loss of material, cracking, and loss of bond due to corrosion of

embedded steel are not probable aging effects. The staff agreed with this statement only for

the case of uncracked reinforced concrete elements. However, the staff identified a concern

that the inaccessible concrete components, such as exterior walls below grade and embedded

structural foundations, may crack due to settlement and corrosion of reinforcing steel may be

expected. In RAI 3.5-8, dated July 27, 2004, the staff requested the applicant to justify the

validity of the LRA statement.

In its response, dated August 26, 2004, the applicant referred to Section III of the GALL Report,

which states that, if the environment is not aggressive, the aging effects such as loss of

material, cracking, and loss of bond are not significant. In addition, inspection of all PBNP

concrete structures and buildings within the scope of license renewal will look for signs of

concrete distress cracking, rust staining, and spalling from any aging effect/source type to

identify any aging effect. The staff determined that the applicant's response is consistent with

the GALL Report. The staff's concern described in RAI 3.5-8 is resolved.

RAI 3.5-9. LRA Table 3.5.1 Item 3.5.1-21 states that the aging management program will be I

plant-specific, and the Discussion column of the table refers to LRA Section 3.5.g 2.2.2.'

However, there is no plant-specific aging management program describec infthii !IA ~sction.

In RAI 3.5-9, dated July 27, 2004, the staff requested the applicant toclar f this itatem6nt.

In its response, dated August 26, 2004, the applicant stated that Line Item Table 421 i

Discussion column, dealing with inaccessible concrete areas, points to S&ction' 3 5.2.2.Z for

further evaluation. LRA Section 3.5.2.2.2.2 concludes that there are rwo Sking Its for this

line item. LRA Table 3.5.1-21 makes reference to a plant-specific progr if an aggressive

below-grade environment exists, which it does not. Therefore, no plant-s ecific program is

needed or identified. As discussed in the resolution of RAI 3.5-6, the staff found the applicant's

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clarification consistent with the GALL Report. The staff's concern described in RAI 3.5-9 is,

therefore, resolved.

On the basis of its review, the staff found that the applicant had appropriately evaluated AMR

results involving management of aging of accessible interior and exterior concrete and steel

components of Class 1 structures. Since the applicant's AMR results are otherwise consistent

with the GALL Report, the staff found that the applicant had demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.2.3 Component Supports

The staff reviewed LRA Section 3.5.2.2.3 against the criteria in SRP-LR Section 3.5.2.2.3,

which addresses several areas discussed below.

Aging of Supports Not Covered by the Structures Monitorina Program. The staff reviewed LRA

Section 3.5.2.2.3.1 against the criteria in SRP-LR Section 3.5.2.2.3.1.

In LRA Section 3.5.2.2.3.1 and Table 3.5.1, line item 3.5.1-29, the applicant addressed aging of

component supports that are not managed by the Structures Monitoring Program.

SRP-LR Section 3.5.2.2.3.1 states that the GALL Report recommends further evaluation of

certain component support/aging effect combinations If they are not covered by the Structures

Monitoring Program. This includes (1) reduction in concrete anchor capacity due to

degradation of the surrounding concrete, for Groups B1-B5 supports; (2) loss of material due to

environmental corrosion, for Groups B2-B5 supports; and (3) reduction/loss of isolation function

due to degradation of vibration isolation elements, for Group B4 supports. Further evaluation is

necessary only for structure/aging effect combinations not covered by the Structures Monitoring

Program.

In LRA Table 3.5.1, line item 3.5.1-29, the applicant stated that for Groups B1-B5 these

component supports are included in the Structures Monitoring Program. In LRA Table 3.5.2-10,

the applicant stated that loss of material due to corrosion of steel support components is an

aging effect requiring management. The applicant stated that this aging effect is managed by

the Structures Monitoring Program.

LRA Table 3.5.1, line item 3.5.1-32, states that component supports in Group B1 are managed

using the ASME Code Section Xl, Subsection IWF Inservice Inspection Program. The

applicant further stated that its Structures Monitoring Program includes baseplates, grout, and

expansion anchors for Group Bi supports, and are inspected at the same time as the ASME

Code Section Xl IWF Inservice Inspections.

Component supports have been evaluated for the following aging mechanisms:

(1)' Reduction in concrete anchor capacity due to surrounding concrete for Groups BI -B5

supports.

The applicant stated that its concrete anchors and surrounding concrete are included in

the Structures Monitoring Program.

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(2) Reduction/loss of isolation function due to degradation of vibration isolation elements for

Group B4 supports.

The applicant stated that Structures Monitoring Program identifies and evaluates the

degradation of vibration isolation elements.

The staff reviewed the applicant's Structures Monitoring Program and ASME Code Section Xl,

Subsection IWF Inservice Inspection Program, and its evaluations are documented in SER

Sections 3.0.3.2.19 and 3.0.3.3.2, respectively.

The staff's review of LRA Section 3.5.2.2.3.1 identified an area in which additional information

was necessary to complete the review of the applicant's results. The applicant responded to

the staff's RAI as discussed below.

RAI 3.5-14. In LRA Table 3.5.1, Item 3.5.1-33, the applicant stated that the Bolting Integrity

Program includes the use of Inservice Inspection to evaluate and monitor crack initiation and

growth due to SCC, if present, in high strength low-alloy steel bolts used in NSSS component

supports. In LRA Tables 3.5.2-1 through 3.5.2-14, the applicant does not address Group B1.1,

high-strength, low-alloy bolts.

In LRA Section B2.1.4, the applicant indicated that high-strength component support bolting is

used in pinned connections associated with steam generator, reactor coolant pumps and

reactor vessel supports and is loaded only in shear with no preload stress.

In RAI 3.5-14, dated March 31, 2005, the staff requested the applicant to identify the aging

management program for the Group Bi.1 high-strength, low-alloy bolts. During conversations

with the staff, the applicant stated that this RAI is similar to one previously issued for the Bolting

Integrity Program, RAI B2.1.4-3. The staff reviewed the applicant's response and found it

acceptable. The staff's evaluation of this RAI is documented in SER Section 3.0.3.2.4. The

applicant also acknowledged that PBNP has some torqued high-strength bolts. The applicant

will supplement its response to reflect this statement. This was identified as confirmatory item

(Cl) 3.5-14.

In its response to Cl 3.5-14, by letter dated April 29, 2005, the applicant stated that the aging

effect mechanism associated with line item 3.5.1-33 is crack initiation and growth due to SCCN

and that it had evaluated SCC as not being an applicable aging effect requiring management at

PBNP. The aging effects requiring management for Group B1.1 bolting include line item

3.5.1-31, loss of material due to boric acid wastage; and line item 3.5.1-32, loss of material due

to general corrosion. These aging effects are depicted in LRA Table 3.5.2-10, which addresses

Group B13.1 bolting. The intent of the Discussion column for line item 3.5.1-33 was that Nif

present, cracking may be detected during ISI inspections, which would evaluate any noted

non-conformance.

The staff evaluated the applicant's response to RAI 3.5-14 and the technical basis provided and

agreed that SCC is not an active aging mechanism requiring management in this situation. The

staff's concern is resolved and, therefore, Cl 3.5-14 is closed.

On the basis of its review, the staff found that the applicant had appropriately evaluated AMR

results involving management of aging of supports not covered by Structures Monitoring

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Program for the component supports, as recommended in the GALL Report. Since the

applicant's AMR results are otherwise consistent with the GALL Report, the staff found that the

applicant had demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

Cumulative Fatigue Damage Due to Cyclic Loading. In LRA Section 3.5.2.2.3.2, the applicant

stated that fatigue is a TLAA, as defined in 10 CFR 54.3. Applicants must evaluate TLAAs in

accordance with 10 CFR 54.21 (c)(1). SER Section 4.3 documents the staff's review of the

applicant's evaluation of this TLAA.

3.5.2.2.4 Quality Assurance for Aging Management of Non-Safety-Related Components.

SER Section 3.0.4 provides the staff's evaluation of the applicant's quality assurance program.

Conclusion. On the basis of its review, for component groups evaluated in the GALL Report for

which the applicant claimed consistency with the GALL Report, and for which the GALL Report

recommends further evaluation, the staff determines that (1) those attributes or features for

which the applicant claimed consistency with the GALL Report were indeed consistent and (2)

the applicant had adequately addressed the issues that were further evaluated. The staff found

that the applicant had demonstrated that the effects of aging will be adequately managed so

that the intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

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

Summaary of Technical Information in the ADplication. In LRA Tables 3.5.2-1 through 3.5.2-14,

the staff reviewed additional details of the results of the AMRs for material, environment, aging

effect requiring management, and AMP combinations that are not consistent with the GALL

Report or are not addressed in the GALL Report.

As documented under RAI 2.1-1 in SER Section 2.1, by letter dated April 29, 2005, the

applicant changed the methodology used to determine the nonsafety-related SCs that are

within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(2).

As a result of the implementation of the scoping methodology changes, the applicant identified

no changes to LRA Tables 3.5.2-1 through 3.5.2-14.

In LRA Tables 3.5.2-1 through 3.5.2-14, the applicant indicated, via Notes F through J, that

neither the identified component nor the material and environment combination is evaluated in

the GALL Report and provided information concerning how the aging effect requiring

management will be managed.

Staff Evaluation. For component type, material and environment combinations that are not

evaluated in the GALL Report, the staff reviewed the applicant's evaluation to determine

whether the applicant demonstrated that the effects of aging will be adequately managed so

that the intended function will be maintained during the period of extended operation.

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3.5.2.3.1 Containments, Structures, and Component Supports Components That Have No

Aging Effects - Tables 3.5.2-1 through 3.5.2-14

In LRA Tables 3.5.2-1 through 3.5.2-14, the applicant identified line items where no aging

effects were identified as a result of the aging review process. Specifically, instances in which

the applicant stated that no aging effects were identified occurred when components fabricated

from structural stainless steel, carbon steel foundation piles, glass, grout, concrete (reinforced)

or fiber-reinforced cement that were exposed to air, or were buried concrete (reinforced).

Neither air nor buried concrete is identified in the GALL Report as an environment for these

components and materials. No aging effects are considered to be applicable to buried

reinforced concrete or structural stainless steel, carbon steel foundation piles, glass, grout,

concrete (reinforced) or fiber reinforced cement that have been exposed to air environments.

On the basis of its review of current industry research and operating experience, the staff found

that dry air on metal will not result in aging that will be of concern during the period of extended

operation. There is not an aging effect/mechanism on structural stainless steel, carbon steel

foundation piles, glass, grout, concrete (reinforced) or fiber-reinforced cement in air

environment. Therefore, the staff concluded there are no applicable aging effects requiring

management for structural stainless steel, carbon steel foundation piles, glass, grout, concrete

(reinforced) or fiber reinforced cement in air environment. The staff also found that no

applicable aging effects for buried reinforced concrete or structural stainless steel, carbon steel

foundation piles, glass, grout, concrete (reinforced) or fiber reinforced cement that were

exposed to air environments.

3.5.2.3.2 Containment Unit 1 and 2 Building Structure - Aging Management Evaluation -

Table 3.5.2-1

The staff reviewed LRA Table 3.5.2-1, which summarized the results of AMR evaluations for the

Units 1 and 2 containment building structure component groups. I

The applicant proposed to manage loss of material due to boric acid wastage of structural steel

carbon material for component types of structural carbon steel/indoor including the containment

liner, keyway channels, exposed portions of embedded steel, electrical and mechanical

penetrations and bolting exposed to indoor with no external air conditioning environment, by

using the Boric Acid Corrosion Program.

The staff reviewed the applicant's Boric Acid Corrosion Program and its evaluation is

documented in SER Section 3.0.3.2.6. On the basis of its review of the applicants

plant-specific and industry operating experience, the staff found that loss of material due to

boric acid wastage for components in the Units 1 and 2 containment structure is effectively

managed using the Boric Acid Corrosion Program. Therefore, the staff found that management

of loss of material due to boric acid wastage in the Units 1 and 2 containment building structure

using this program is acceptable.

The applicant proposed to manage loss of material due to wear of structural copper alloy

material (Zn<1 5%) for component type of structural copper alloy/indoor including airlock

bushings exposed to indoor with no external air conditioning environment, by using the ASME

Section Xl, Subsection IWE and IWL Inservice Inspection Program.

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The staff reviewed the applicant's ASME Section Xl, Subsection IWE and IWL Inservice

Inspection Program and its evaluation is documented in SER Section 3.0.3.2.2. On the basis of

its review of the applicant's plant-specific and industry operating experience, the staff found that

loss of material due to wear for components in the Units 1 and 2 containment building structureis effectively managed using the ASME Section Xl, Subsection IWE and IWL Inservice

Inspection Program. Therefore, the staff found that management of loss of material due to

wear in the Units 1 and 2 containment building structure using this program is acceptable.

The applicant also proposed to manage loss of material due to crevice corrosion, MIC, and

pitting corrosion of structural stainless steel, including the refueling cavity liner, sandbox covers

and fuel transfer tube including bolting exposed to treated water borated with temperature less

than 140 0F, by using the Water Chemistry Control Program and ASME Section XI, Subsections

IWE and IWL Inservice Inspection Program.

The staff reviewed the applicant's Water Chemistry Control Program and ASME Section Xl,

Subsections IWE and IWL Inservice Inspection Program. Its evaluations are documented in

SER Sections 3.0.3.2.20 and 3.0.3.2.1. On the basis of its review of the applicant's

plant-specific and industry operating experience, the staff found that loss of material due to

crevice corrosion, MIC, and pitting corrosion for components in the Units 1 and 2 containment

building structure is effectively managed using the Water Chemistry Control Program and

ASME Section XI, Subsections IWE and IWL Inservice Inspection Program. Therefore, the

staff found that management of loss of material due to crevice corrosion, MIC, and pitting

corrosion in the Units 1 and 2 containment building structure using these programs is

acceptable.

3.5.2.3.3 Control Building Structure - Aging Management Evaluation - Table 3.5.2-2

The staff reviewed LRA Table 3.5.2-2, which summarized the results of AMR evaluations for the

control building structure component groups.

The applicant proposed to manage loss of material due to general corrosion and due to wear of

structural steel carbon material for the component type doors/indoor, including all doors

throughout the building exposed to an indoor with no external air conditioning environment, by

using the Structures Monitoring Program and the Fire Protection Program. The staff reviewed

the applicant's Structures Monitoring Program and Fire Protection Program and its evaluations

are documented in SER Sections 3.0.3.2.19 and 3.0.3.2.1 0, respectively.

On the basis of its review of the applicant's programs, and plant-specific and industry operating

experience, the staff found that loss of material due to general corrosion and loss of material

due to wear for components in the control building structure are effectively managed using the

Structures Monitoring Program and Fire Protection Program. Therefore, the staff found that

management of loss of material due to general corrosion and due to wear in the control building

structure using these programs is acceptable.

The applicant proposed to manage change in material properties due to elevated temperature,

cracking due to elevated temperature, ultraviolet radiation and ozone of elastomer materials for

component type of elastomers/indoor, including rubber flap-DGR louver, rubber sill, sweep flood

doors, gaskets, seals and the control room door exposed to indoor with no external air

conditioning environment, by using the Fire Protection Program.

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The staff reviewed the applicant's Fire Protection Program and its evaluation is documented in

SER Section 3.0.3.2.10. The staff found that elastomers experience changes in material

properties and cracking gradually. On the basis of its review ofthe applicant's programs, and

plant-specific and industry operating experience, the staff found that change in material

properties due to elevated temperature, cracking due to elevated temperature, ultraviolet

radiation and ozone for components in the control building structure are effectively managed

using the Fire Protection Program. Therefore, the staff found that management of change in

material properties due to elevated temperature, cracking due to elevated temperature,

ultraviolet radiation and ozone in the control building structure using this program is acceptable.

The applicant proposed to manage change in material properties and loss of material due to rot

and mildew of wood for component type of wood/outdoor, including missile shield (an integral

part of the diesel generator air intake) exposed to the outdoors, by using the Structures

Monitoring Program. -

In LRA Section 3.5.2.1.2, the applicant identified that the outdoor wood missile shield for the

diesel generator air intake is subject to the aging effects of change in material properties and

loss of material due to rot and mildew. For the management of these aging effects, the

applicant proposed to use the Structures Monitoring Program, under which periodic inspections

will be performed to ensure that these aging effects are properly managed. As discussed in the

resolution of RAI 3.5-11, the applicant committed to revise the scope of the Structures

Monitoring Program to include structural components made of wood material during the annual

LRA update. Based on the applicant's commitment, the staff found that the identified aging

effects of these structural elements will be properly managed.

The staff reviewed the applicant's Structures Monitoring Program and its evaluation is

documented in SER Section 3.0.3.2.19. On the basis of its review of the applicant's programs,

and plant-specific and industry operating experience, the staff found that changes in material

properties and loss of material due to rot and mildew for components in the control building

structure are effectively managed using the Structures Monitoring Program. Therefore, the

staff found that management of changes in material properties due to rot and mildew and loss

of material due to rot and mildew in the control building structure using this program is

acceptable.

3.5.2.3.4 Circulating Water Pumphouse Structure - Aging Management Evaluation -

Table 3.5.2-3

The staff reviewed LRA Table 3.5.2-3, which summarized the results of AMR evaluations for the

circulating water pumphouse structure component groups.

The applicant proposed to manage loss of material due to abrasion and cavitation of reinforced

concrete material for component type of concrete/raw water, including the forebay structure and

the pump bays exposed to a submerged raw water environment, by using the Structures

Monitoring Program.

The staff reviewed the applicant's Structures Monitoring Program and its evaluation is

documented in SER Section 3.0.3.2.19. The staff found that limited loss of material due to

abrasion and cavitation can occur in a raw water submerged external environment. On the

basis of its review of the applicant's programs, plant-specific and industry operating experience,

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the staff found that loss of material due to abrasion and cavitation for components in the

circulating water pumphouse structure is effectively managed using the Structures Monitoring

Program. Therefore, the staff found that management of loss of material due to abrasion and

cavitation in the circulating water pumphouse structure using this program is acceptable.

The applicant proposed to manage loss of material due to general corrosion and loss of

material due to wear of structural steel carbon material for component type of indoor doors,

including all doors throughout the building exposed to indoor with no external air conditioning

environment, by using the Fire Protection Program.

The staff reviewed the applicant's Fire Protection Program and its evaluation is documented in

SER Section 3.0.3.2.10. On the basis of its review of the applicant's programs, plant-specific

and industry operating experience, the staff found that loss of material due to general corrosion

and loss of material due to wear for components in the circulating water pumphouse structure

are effectively managed using the Fire Protection Program. Therefore, the staff found that

management of loss of material due to general corrosion in the circulating water pumphouse

structure using this program is acceptable.

The applicant proposed to manage loss of material due to general corrosion of structural steel

carbon material for component type of structural indoor carbon steel, including framings,

columns, beams, structural carbon steel fasteners indoors, and structural steel framing exposed

to indoor with no external air conditioning environment, by using the Structures Monitoring

Program.

The staff reviewed the applicant's Structures Monitoring Program and its evaluation is

documented in SER Section 3.0.3.2.1 9. On the basis of its review of the applicant's programs,

plant-specific and industry operating experience, the staff found that loss of material due to

general corrosion for components in the circulating water pumphouse structure is effectively

managed using the Structures Monitoring Program. Therefore, the staff found that

management of loss of material due to general corrosion in the circulating water pumphouse

structure using this program is acceptable.

3.5.2.3.5 Diesel Generator Building Structure - Aging Management Evaluation - Table 3.5.2-4

The staff reviewed LRA Table 3.5.2-4, which summarized the results of AMR evaluations for the

diesel generator building structure component groups.

The applicant proposed to manage loss of material due to general corrosion and due to wear of

structural steel carbon material for component type of outdoor doors and indoor doors,

including all doors throughout the building exposed to outdoor and indoor with no external air

conditioning environment, by using the Fire Protection Program.

The applicant proposed to manage loss of material due to general corrosion of structural steel

carbon material for component type of structural carbon steel fasteners indoor and outdoor,

including all platform stairs and missile shields, and structural carbon steel indoor and outdoor,

including all framing and missile shields, by using the Structures Monitoring Program.

The staff reviewed the applicant's Fire Protection Program and Structures Monitoring Program

and its evaluations are documented in SER Sections 3.0.3.2.10 and 3.0.3.2.19. On the basis of

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its review of the applicant's plant-specific and industry operating experience, the staff found that

loss of material due to general corrosion and due to wear for components in the diesel

generator building structure is effectively managed using the Fire Protection Program and

Structures Monitoring Program. Therefore, the staff found that management of loss of material

due to general corrosion and due to wear in the diesel generator building structure using these

programs is acceptable.

3.5.2.3.6 Facade Units 1 and 2 Structure - Aging Management Evaluation - Table 3.5.2-5

The staff reviewed LRA Table 3.5.2-5, which summarized the results of AMR evaluations for the

Units 1 and 2 facade structure component groups.

In LRA Table 3.5.2-5, the applicant stated that the AMRs for the Units 1 and 2 facade structure

components are consistent with the GALL Report.

The staff confirmed that the AMR results are consistent with the GALL Report.

3.5.2.3.7 Primary Auxiliary Building Structure - Aging Management Evaluation - Table 3.5.2-6

The staff reviewed LRA Table 3.5.2-6, which summarized the results of AMR evaluations for the

primary auxiliary building structure component groups.

The applicant proposed to manage loss of material due to general corrosion and due to wear of

structural steel carbon material for component type of indoor doors, including all doors

throughout the building exposed to indoor with no external air conditioning environment, by

using the Structures Monitoring Program and the Fire Protection Program.- The staff reviewed

the applicant's Structures Monitoring Program and Fire Protection Program and its evaluations

are documented in SER Sections 3.0.3.2.19 and 3.0.3.2.10, respectively.

On the basis of its review of the applicant's plant-specific and industry operating experience, the

staff found that loss of material due to general corrosion and loss of material due to wear for

components in the primary auxiliary building structure are effectively managed using the

Structures Monitoring Program and the Fire Protection Program. Therefore, the staff found that

management of loss of material due to general corrosion and loss of material due to wear in the

primary auxiliary building structure using these programs is acceptable.

The applicant proposed to manage change in material properties due to elevated temperature,

cracking due to elevated temperature, and due to ultraviolet radiation and ozone of elastomer

materials for component type of indoor elastomers, including rubber sill, sweep and flood doors

exposed to indoor with no external air conditioning environment, by using the Fire Protection

Program and Structures Monitoring Program.

The staff reviewed the applicant's Fire Protection Program and Structures Monitoring Program

and its evaluations are documented in SER Sections 3.0.3.2.10 and 3.0.3.2.19. The staff found

that elastomers experience changes in material properties and cracking gradually. On the

basis of its review of the applicant's plant-specific and industry operating experience, the staff

found that change in material properties due to elevated temperature, cracking due to elevated

temperature, and cracking due to ultraviolet radiation and ozone for components in the primary

auxiliary building structure is effectively managed using the Fire Protection Program and

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Structures Monitoring Program. Therefore, the staff found that management of change in

material properties due to elevated temperature, cracking due to elevated temperature, and

cracking due to ultraviolet radiation and ozone in the primary auxiliary building structure using

these programs is acceptable.

The applicant proposed to manage loss of material due to boric acid wastage of structural steel

carbon material for component types of structural carbon steel indoor fasteners, including

structural steel framing, indoor structural carbon steel, crane support girders, framing, columns,

beams, roof trusses, platforms, and stairs in an indoor with no external air conditioning

environment, by using the Boric Acid Corrosion Program.

The staff reviewed the applicant's Boric Acid Corrosion Program and found it acceptable. The

staff's evaluation of this program is documented in SER Section 3.0.3.2.6. On the basis of its

review of the applicant's plant-specific and industry operating experience, the staff found that

loss of material due to boric acid wastage for components in the primary auxiliary building

structure is effectively managed using the Boric Acid Corrosion Program. Therefore, the staff

found that management of loss of material due to boric acid wastage in the primary auxiliary

building structure is acceptable.

The applicant proposed to manage loss of material due to crevice corrosion, MIC, and pitting

corrosion of structural stainless steel exposed to borated water, including spent fuel pool (SFP),

SFP canal, SFP gates; structural stainless steel, and storage racks exposed to treated and

borated water with an external temperature less than 140 OF, by using the Water Chemistry

Control Program.

The staff reviewed the applicant's Water Chemistry Control Program and its evaluation is

documented in SER Section 3.0.3.2.20. The staff found that use of only the Water Chemistry

Control Program for loss of materials in treated borated water is consistent with the GALL

Report Table 2, Items IlI.A5.2-b and VII.A2.1 -c. On the basis of its review of the applicant's

plant-specific and industry operating experience, the staff found that loss of material due to

crevice corrosion, MIC, and pitting corrosion for components in the primary auxiliary building

structure is effectively managed using the Water Chemistry Control Program. Therefore, the

staff found «iat management of loss of material due to crevice corrosion, MiC, and pitting

corrosion in the primary auxiliary building structure using this program is acceptable.

3.5.2.3.8 Turbine Building Units 1 and 2 Structure - Aging Management Evaluation -

Table 3.5.2-7

The staff reviewed LRA Table 3.5.2-7, which summarized the results of AMR evaluations for the

Units 1 and 2 turbine building structure component groups.

In LRA Table 3.5.?-7, the applicant stated that the AMRs for the Units 1 and 2 turbine building

structure components are either consistent with the GALL Report or do not have an aging effect

that requires management.

The staff confirmed that the AMR results are consistent with the GALL Report.

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3.5.2.3.9 Yard Structures - Aging Management Evaluation - Table 3.5.2-8

The staff reviewed LRA Table 3.5.2-8, which summarized the results of AMR evaluations for the

yard structures component groups.

The applicant proposed to manage loss of material due to surface runoff and erosion of earth

material for component type of outdoor earth berm, including berm around the fuel oil storage

tanks exposed to outdoor environment, by using the Structures Monitoring Program.

The staff reviewed the applicant's Structures Monitoring Program and its evaluation is

documented in SER Section 3.0.3.2.19. On the basis of its review of the applicant's

plant-specific and industry operating experience, the staff found that loss of material due to

surface runoff and erosion for components in the yard structures is effectively managed using

the Structures Monitoring Program. Therefore, the staff found that management of loss of

material due to surface runoff and erosion of earth material in the yard structures using this

program is acceptable.

The applicant proposed to manage loss of material due to general corrosion and loss of

material due to selective leaching of structural cast iron material for component type of outdoor

structural cast iron, including manhole frames and covers exposed to outdoor environment, by

using the Structures Monitoring Program.

In LRA Table 3.5.2-8, the applicant identified that outdoor carbon steel manhole covers, frames,

bus ducts, cast iron manhole covers and frames are subject to the aging effect of loss of

material due to general corrosion. Also, the cast iron manhole covers and frames are subject to

the aging effect of loss of material due to leaching. For the management of these aging

effects, the applicant proposed to use the Structures Monitoring Program to ensure that these

aging effects are properly managed. The Structures Monitoring Program was revised to credit

the One-Time Inspection Program to identify selective leaching for these components. The

One-Time Inspection Program includes a visual inspection and hardness measurements to

identify selective leaching of susceptible components. As stated in LRA Section B2.1.20, the

and Structures Monitoring Program scope covers yard structures that are within the scope of

license renewal. On the basis of the above discussion and program evaluation, the staff found

that the identified aging effect of these structural elements will be properly managed.

The applicant also proposed to use the Structures Monitoring Program to manage potential

aging effects of buried concrete electrical duct banks, equipment foundations, support pads,

manholes, indoor concrete manhole interior, outdoor concrete equipment foundations, pads,

manholes and covers. The applicant noted (LRA Section 3.5 Note 26) that no aging effects

requiring management were identified for these structural elements. However; the applicant

committed to periodically monitor these structural elements for potential degradation by

employing the Structures Monitoring Program. The staff found that the applicant's LRA

commitment is reasonable and acceptable. It will ensure that potential degradation of these

structural elements will be identified for proper corrective action.

The staff reviewed the applicants Structures Monitoring Program and its evaluation Is

documented in SER Section 3.0.3.2.19. The staff found that loss of material due to general

corrosion and loss of material due to selective leaching in manhole covers and frames can

gradually occur in outdoor environments but is not expected to be significant. On the basis of

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its review of the applicant's program, plant-specific and industry operating experience, the staff

found that loss of material due to general corrosion and loss of material due to selective

leaching for components in the yard structures are effectively managed using the Structures

Monitoring Program. Therefore, the staff found that management of loss of material due to

general corrosion and loss of material due to selective leaching in the yard structures using this

program is acceptable.

3.5.2.3.10 Cranes, Hoists, and Lifting Devices - Aging Management Evaluation - Table 3.5.2-9

The staff reviewed LRA Table 3.5.2-9, which summarized the results of AMR evaluations for the

cranes, hoists, and lifting devices component groups.

The applicant proposed to manage loss of material due to general corrosion and due to wear of

structural steel carbon for component type of indoor structural carbon steel, including the bridge

and trolley framing, crane rails, monorails, and lifting rigs exposed to an indoor with no external

air conditioning environment, by using the Structures Monitoring Program.

The staff reviewed the applicant's Structures Monitoring Program and its evaluation is

documented in SER Section 3.0.3.2.19. The staff found that loss of material due to general

corrosion is minimal in indoor environments. On the basis of its review of the applicant's

program, plant-specific and industry operating experience, the staff found that loss of material

due to general corrosion and due to wear for components in the cranes, hoists, and lifting

devices is effectively managed using the Structures Monitoring Program. Therefore, the staff

found that management of loss of material due to general corrosion and due to wear in the

cranes, hoists, and lifting devices using this program is acceptable.

The applicant proposed to manage loss of material due to crevice corrosion, MIC, and pitting

corrosion of structural stainless steel exposed to borated water, including RV internals lifting rig

exposed to treated or borated water with a temperature less than 140 OF, by using the

Structures Monitoring Program.

The staff reviewed the applicant's Structures Monitoring Program and its evaluation is

documented in SER Section 3.0.3.2.19. The staff found that the effect of loss of material of

structural steel-stainless material in treated borated water environments is minimal or

non-existent. On the basis of its review of the applicant's program, plant-specific and industry

operating experience, the staff found that loss of material due to crevice corrosion, loss of

material due to MIC, and loss of material due to pitting corrosion for components in the cranes,

hoists, and lifting devices are effectively managed using the Structures Monitoring Program.

Therefore, the staff found that management of loss of material due to crevice corrosion, loss of

material due to MIC, and loss of material due to pitting corrosion in the cranes, hoists, and

lifting devices using this program is acceptable.

3.5.2.3.11 Component Supports Commodity Group - Aging Management Evaluation -

Table 3.5.2-10

The staff reviewed LRA Table 3.5.2-10, which summarized the results of AMR evaluations for

the component supports commodity group component groups.

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The applicant proposed to manage loss of material due to general corrosion of structural steel

carbon material for component type of indoor structural carbon steel fasteners, including ASME

equipment, ASME pipe supports and restraints, and indoor structural carbon steel exposed to

indoor with no external air conditioning environment, by using the Structures Monitoring

Program.

The staff reviewed the applicant's Structures Monitoring Program and its evaluation is

documented in SER Section 3.0.3.2.19. On the basis of its review of the applicant's

plant-specific and industry operating experience, the staff found that loss of material due to

general corrosion for components in the component supports commodity group is effectively

managed using the Structures Monitoring Program. Therefore, the staff found that

management of loss of material due to general corrosion in the component supports commodity

group using this program is acceptable.

3.5.2.3.12 Fire Barrier Commodity Group - Aging Management Evaluation - Table 3.5.2-11

The staff reviewed LRA Table 3.5.2-11, which summarizes the results of AMR evaluations for

the fire barrier commodity group component groups.

The applicant proposed to manage cracking/delamination due to movement, shrinkage and

vibration; loss of material due to abrasion; and separation due to movement, shrinkage, and

vibration of calcium silicate board, ceramic fiber, board and mat, and silicone-based materials

for component types of indoor calcium silicate board, ceramic fiber, ceramic fiber-board,

ceramic fiber-mat, and silicone-based material exposed to indoor with no external air

conditioning, by using the Fire Protecjton Program.

The staff reviewed the applicant's Fire Protection Program and its evaluation is documented in

SER Section 3.0.3.2.10. On the basis of its review of the applicant's plant-specific and industry

operating experience, the staff found that the aging effects mentioned above are effectively

managed using the Fire Protection Program. Therefore, the staff found that management of

these effects in the fire barrier commodity group using this program is acceptable.

The applicant proposed to manage loss of material due to general corrosion of structural steel

carbon material for component of indoor structural carbon steel, including fire damper frames

and cable tray covers exposed to indoor with no external air conditioning environment, by using

the Fire Protection Program.

The staff reviewed the applicant's Fire Protection Program and its evaluation is documented in

SER Section 3.0.3.2.10. On the basis of its review of the applicant's plant-specific and industry

operating experience, the staff found that loss of material due to general corrosion for

components in the fire barrier commodity group is effectively managed using the Fire Protection

Program. Therefore, the staff found that management of loss of material due to general

corrosion in the fire barrier commodity group using this program is acceptable.

3.5.2.3.13 13.8 KV Switchgear Building Structure - Aging Management Evaluation -

Table 3.5.2-12

The staff reviewed LRA Table 3.5.2-12, which summarized the results of AMR evaluations for

the 13.8 KV switchgear building structure component groups.

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In LRA Table 3.5.2-12, the applicant stated that the AMRs for the 13.8 KV switchgear building

structure components do not have aging effects that require management; however, concrete

and grout are periodically monitored for potential degradation by using the Structures

Monitoring Program.

The staff reviewed the applicant's Structures Monitoring Program, and its evaluation is

documented in SER Section 3.0.3.2.19. On the basis of its review, the staff confirmed that the

AMR results are consistent with the GALL Report.

3.5.2.3.14 Fuel Oil Pumphouse Structure - Aging Management Evaluation - Table 3.5.2-13

The staff reviewed LRA Table 3.5.2-13, which summarized the results of AMR evaluations for

the fuel oil pumphouse structure component groups.

In LRA Table 3.5.2-13, the applicant stated that AMRs for the fuel oil pumphouse structure

components do not have aging effects that require management; however, concrete and grout

are periodically monitored for potential degradation by using the Structures Monitoring Program.

The staff reviewed the applicant's Structures Monitoring Program and its evaluation is

documented in SER Section 3.0.3.2.19. On the basis of its review, the staff confirmed that the

AMR results are consistent with the GALL Report.

3.5.2.3.15 Gas Turbine Building Structure - Aging Management Evaluation - Table 3.5.2-14

The staff reviewed LRA Table 3.5.2-14, which summarized the results of AMR evaluations for

the gas turbine building structure component groups.

In LRA Table 3.5.2-14, the applicant stated that the AMRs for the gas turbine building structure

components do not have aging effects that require management; however, concrete and grout

are periodically monitored for potential degradation by using the Structures Monitoring Program.

The staff reviewed the applicant's Structures Monitoring Program and its evaluation is

documented in SER Section 3.0.3.2.19. On the basis of its review, the staff confirmed that the

AMR results are consistent with the GALL Report.

All AMRs in Tables 3.5.2-1 through 3.5.2-14 were evaluated. The staff found them to be

acceptable.

Conclusion. On the basis of its review, the staff found that the applicant had appropriately

evaluated AMR results involving material, environment, aging effect requiring management, and

AMP combinations that are not evaluated in the GALL Report. The staff found that the

applicant had demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

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3.5.3 Conclusion

On the basis of its review, the staff concluded that the applicant had demonstrated that the

aging effects associated with the containments, structures, and component supports

components will be adequately managed so that the intended functions will be maintained 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 concluded

that they adequately describe the AMPs credited for managing aging of the containments,

structures, and component supports as required by 10 CFR 54.21 (d).

3.6 Aging Manaaement of Electrical Components

This section of the SER documents the staff's review of the applicant's AMR results for the

electrical and instrumentation and controls (I&C) components and component groups

associated with the following systems:

* 120 VAC vital instrument power system

* 125 VDC power system

* 4160 VAC power system

* 480 VAC power system

* control rod drive and Indication system and nuclear process Instrumentation

* miscellaneous AC power and lighting system

* offsite power system

* reactor protection system including anticipated transient without scram

* engineered safety features actuation system

* plant communications system

* 13.8K VAC power system

* <radiation monitoring system

3.6.1 Summary of Technical Information In the Application

In LRA Section 3.6, the applicant provided AMR results for electrical and I&C components and

component groups. In LRA Table 3.6.1. "Summary of Aging Management Evaluations in

Chapter VI of NUREG-1 801 for Electrical Components," the applicant provided a summary

comparison of its AMRs with the AMRs evaluated in the GALL Report for the electrical and I&C

components and component groups.

The applicant's AMRs incorporated applicable operating experience in the determination of

AERM. 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 AERM. 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.

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3.6.2 Staff Evaluation

The staff reviewed LRA Section 3.6 to determine if the applicant provided sufficient information

to demonstrate that the effects of aging for the electrical and l&C 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).

Also, the staff performed an onsite audit of AMRs to confirm the applicant's claim that certain

identified AMRs are consistent with the GALL Report. The staff did not repeat its review of the

matters described in the GALL Report. However, the staff did verify that the material presented

in the LRA was applicable and that the applicant had identified the appropriate GALL AMPs.

The staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff's

audit evaluations are documented in the staff's PBNP audit and review report and summarized

in SER Section 3.6.2.1.

The staff also performed an onsite audit of those AMRs that are consistent with the GALL

Report and for which further evaluation is recommended. During the audit, the staff verified

that the applicant's further evaluations were consistent with the acceptance criteria in

NUREG-1 800 Section 3.6.2.2, "Standard Review Plan for Review of License Renewal

Applications for Nuclear Power Plants," dated July 2001. The staff's audit evaluations are

documented in the staff's PBNP audit and review report and summarized in SER

Section 3.6.2.2.

The staff performed an onsite audit and conducted a technical review of the remaining AMRs

that were not consistent with or not addressed in the GALL Report. The audit and technical

review included evaluating whether all plausible aging effects had been identified and whether

the aging effects listed were appropriate for the combination of materials and environments

specified. The staff's audit evaluations are documented in the staff's PBNP audit and review

report and summarized in SER Section 3.6.2.3. The staff's evaluation of its technical review is

also documented in SER Section 3.6.2.3.

Finally, the staff reviewed the AMP summary descriptions in the FSAR supplement to ensure

that they provided an adequate description of the programs credited with managing or

monitoring aging for the electrical and l&C system components.

Table 3.6-1, below, provides a summary of the staff's evaluation of components, aging

effects/mechanisms, and AMPs listed in LRA Section 3.6 that are addressed in the GALL

Report.

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

Report

Component Group Aging Effec AJUIP In GA LL AMP in LRA: Stafflluation

Mechanism Report -

Electrical Degradation due to EQ of electric TLAA This TLAA is

equipment subject various aging components evaluated in

to 10 CFR 50.49 mechanisms Section 4.8,

EQ requirements Environmental

(Item Number Qualification. (See

3.6.1-01) Section 3.6.2.2.1)

Electrical cables Embrittlement, Aging management Cable Condition Consistent with

and connections not cracking, melting, program for Monitoring Program GALL, which

subject to discoloration, electrical cables recommends no

10 CFR 50.49 EQ swelling, or loss of and connections not further evaluation

requirements dielectric strength subject to (See

(Item Number leading to reduced 10 CFR 50.49 EQ Section 3.6.2.1)

3.6.1-02) insulation requirements

resistance (IR);

electrical failure

caused by thermal/

thermoxidative

degradation of

organics; radiolysis

and photolysis (UV

sensitive materials

only) of organics;

radiation-induced

oxidation; moisture

intrusion

Electrical cables Embrittlement, Aging management Cable Condition Consistent with

used in cracking, melting, program for Monitoring Program GALL, which

Instrumentation discoloration, electrical cables recommends no

circuits not subject swelling, or loss of used in further evaluation

to 10 CFR 50.49 dielectric strength instrumentation (See

EQ requirements leading to reduced circuits not subject Section 3.6.2.1)

that are sensitive to IR; electrical failure to 10 CFR 50.49

reduction in caused by thermaV EQ requirements conductor insulation thermoxidative

resistance degradation of

(Item Number organics;

3.6.1-03) radiation-induced

oxidation; moisture

Intrusion

Inaccessible Formation of water Aging management Cable Condition Consistent with

medium-voltage trees, localized program for Monitoring Program GALL, which

(2 kV to 15 kV) damage leading to inaccessible recommends no

cables (e.g., electrical failure medium-voltage further evaluation

Installed In conduit (breakdown of cables not subject (See

or directly buried) insulation); water to 10 CFR 50.49 Section 3.6.2.1)

not subject to trees caused by EQ requirements

10 CFR 50.49 EQ moisture intrusion

requirements

(Item Number 3.6.1-04)

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Component Grup AL;LaEvauation

Mechanism-epr -

Electrical Corrosion of Boric acid corrosion Boric Acid Consistent with

connectors not connector contact Corrosion Program GALL, which

subject to surfaces caused by recommends no

10 CFR 50.49 EQ intrusion of borated further evaluation

requirements that water (See

are exposed to Section 3.6.2.1)

borated water

leakage

(Item Number

3.6.1-05)

The staff's review of the PBNP electrical and instrumentation and controls and associated

components followed one of several approaches. One approach, documented in SER

Section 3.6.2.1, involves 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 SER Section 3.6.2.2, involves

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 for which further evaluation is

recommended. A third approach, documented in SER Section 3.6.2.3, involves the staff's

review of the AMR results for components 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's review of AMPs that are credited to manage or monitor aging effects of the

electrical and l&C components is documented in SER Section 3.0.3.

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 Application. In LRA Section 3.6.2.1, the applicant

identified the relevant materials, environments, and AERM. The applicant also identified the

following programs that manage aging effects related to electrical and l&C components:

* Boric Acid Corrosion Program

* Cable Condition Monitoring Program

* Environmental Qualification Program

Staff Evaluation. In LRA Table 3.6.2-1, the applicant provided a summary of AMRs for the

electrical and l&C components and identified which AMRs it considered to be consistent with

the GALL Report.

For component groups evaluated in the GALL Report for which the applicant has claimed

consistency with the GALL Report, and for which the GALL Report does not recommend further

evaluation, the staff performed an audit and review to determine whether the plant-specific

components contained in these GALL Report component groups were bounded by the GALL

Report evaluation.

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The applicant provided a note for each AMR line item. The notes describe how the information

in the tables aligns with the information in the GALL Report. The staff's audit of those AMRs

with Notes A through E, indicate the AMR is consistent with the GALL Report.

Note A indicated that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the AMP

identified in the GALL Report. The staff audited these line items to verify consistency with the

GALL Report and the validity of the AMR for the site-specific conditions.

Note B indicated that the AMR line item Is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

AMP identified in the GALL Report. The staff audited these line items to verify consistency with

the GALL Report. The staff verified that the identified exceptions to the GALL AMPs had been

reviewed and accepted by the staff. The staff also determined whether the AMP identified by

the applicant was consistent with the AMP identified in the GALL Report and whether the AMR

was valid for the site-specific conditions.

Note C indicated that the component for the AMR line item, although different, is consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent

with the AMP identified by the GALL Report. This note indicates that the applicant was unable

to find a listing of some system components in the GALL Report. However, the applicant

identified a different component in the GALL Report that had the same material, environment,

aging effect, and AMP as the component that was under review. The staff audited these line

items to verify consistency with the GALL Report. The staff also determined whether the AMR

line item of the different component was applicable to the component under review and whether

the AMR was valid for the site-specific conditions.

Note D indicated that the component for the AMR line item, although different, is consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP takes some

exceptions to the AMP identified in the GALL Report. The staff audited these line items to

verify consistency with the GALL Report. The staff verified whether the AMR line item of the

different component was applicable to the component under review. The staff verified whether

the identified exceptions to the GALL AMPs had been reviewed and accepted by the staff. The

staff also determined whether the AMP identified by the applicant was consistent with the AMP

identified in the GALL Report and whether the AMR was valid for the site-specific conditions.

Note E indicated that the AMR line item is consistent with the GALL Report for material, ,

environment, and aging effect, but a different aging management program isrcredited. The

staff audited these line items to verify consistency with the GALL Report. The staff also

determined whether the identified AMP would manage the aging effect consistent with the AMP

identified by the GALL Report and whether the AMR was valid for the'site-specific cIn itiOns,

The staff conducted an audit and review of the information provided in the LtRA asI cicumentd

in its PBNP audit and review report. The staff did not repeat its review of, the mattedPdesribed

in the GALL Report. However, the staff did verify that the material presented in the LRA was

applicable and that the applicant had identified the appropriate GALL Report AMRs. n

The staff reviewed the LRA to confirm that the applicant had (1) provided a brief description of

the system, components, materials, and environment; (2) stated that the applicable aging

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effects have been reviewed and are evaluated in the GALL Report; and (3) identified those

aging effects for the electrical and I&C components that are subject to an AMR. On the basis

of its review, the staff determined that for AMRs not requiring further evaluation, as identified in

LRA Table 3.6.1 (Table 1), the applicant's references to the GALL Report are acceptable and

no further staff review is required.

Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report.

The staff also reviewed information pertaining to the applicant's consideration of recent

operating experience and proposals for managing associated aging effects. On the basis of its

review, the staff found that the AMR results that the applicant claimed to be consistent with the

GALL Report are consistent with the AMRs in the GALL Report. Therefore, the staff found that

the applicant had demonstrated that the effects of aging for these components will be

adequately managed so that their intended function(s) will be maintained consistent with the

CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

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

Evaluation Is Recommended

Summary of Technical Information in the Application. In LRA Section 3.6.2.2, the applicant

provided further evaluation of aging management as recommended by the GALL Report for

electrical components. The applicant provided information concerning how it will manage the

aging effects of electrical equipment subject to environmental qualification.

The applicant stated that environmental qualification is a TLAA as defined in 10 CFR 54.3.

TLAAs are required to be evaluated in accordance with 10 CFR 54.21 (c)(1). The staff's

evaluation of this TLAA is addressed in SER Section 4.8, Environmental Qualification of Electric

Equipment.

Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant

claimed consistency with the GALL Report, and for which the GALL Report recommends further

evaluation, the staff reviewed the applicant's evaluation to determine whether it adequately

addressed the issues that were further evaluated.

3.6.2.2.1 Electrical Equipment Subject to Environmental Qualification

In LRA Section 3.6.2.2.1, the applicant stated that environmental qualification is a TLAA, as

defined in 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with

10 CFR 54.21 (c)(i). SER Section 4.8 documents the staff's review of the applicant's evaluation

of its TLAA.

Conclusion. On the basis of its review, for component groups evaluated in the GALL Report for

which the applicant claimed consistency with the GALL Report, and for which the GALL Report

recommends further evaluation, the staff determined that (1) those attributes or features for

which the applicant claimed consistency with the GALL Report were indeed consistent, and (2)

the applicant had adequately addressed the issues that were further evaluated. The staff found

that the applicant had demonstrated that the effects of aging will be adequately managed so

that the intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

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

Summary of Technical Information in the Application. In LRA Table 3.6.2-1, the applicant

provided additional details of the results of the AMRs for material, environment, AERM, and

AMP considerations that are not addressed in the GALL Report.

As documented under RAI 2.1-1 in SER Section 2.1, by letter dated April 29, 2005, the

applicant changed the methodology used to determine the nonsafety-related SCs that are

within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(2).

As a result of the implementation of the scoping methodology changes, the applicant identified

no changes to LRA Table 3.6.2-1.

In LRA Table 3.6.2-1, the applicant indicated, via Note J, that neither the identified component

nor the material and environment combination is evaluated in the GALL Report and provided

information concerning how the aging effect will be managed.

Staff Evaluation. For component type, material, and environment combinations that are not

evaluated in the GALL Report, the staff reviewed the applicant's evaluation to determine

whether the applicant demonstrated that the effects of aging will be adequately managed so

that the intended function will be maintained consistent with the CLB during the period of

extended operation.

3.6.2.3.1 Electrical Components - Electrical Commodity Groups - Aging Management

Evaluation - Table 3.6.2-1

The applicant identified that AMPs are not required for the following component types:

* high-voltage insulators (offsite power system)

* phase bus (480 VAC, 4160 VAC, and 13.8K VAC power systems)

* :transmission conductors (offsite power systems)

* electrical connections not subject to 10 CFR 50.49 EQ requirements that are exposed to

borated water leakage outside containment and in an indoor environment with no

air-conditioning

Table 3.6-2, below, shows a summary of LRA Table 3.6.2-1 indicating those component types,

systems, materials, and environments for which no AMPs have been identified.

Table 3.6-2 Electrical Component Types, Materials, and Environments Without AMPs

Cofponbent Typ )aterla Evrn et Ang aagm t

(Sys _ _ _ em) _ _ _ _ _ _ _ _ _ _ _ _P rogram

High-voltage insulators Cement Metal Outdoor None Identified

(Offsite Power System) Porcelain

Phase bus Aluminum Porcelain Indoor - with or None Identified

Bronze Silicone without Air

(480 VAC, 4160 VAC, and Copper Stainless Steel Conditioning

13.8K VAC Power Systems) Fiberglass Steel

Noryl

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CoMponn 'A.'Ty Material Envq ronent Aii r¶anagem

(System),. rogram

Transmission conductors Aluminum Steel Outdoor None Identified

(Offsite Power System)

Electrical connections not Connections and Connector Containment None Identified

subject to 10 CFR 50.49 EQ Pins -Various Metals (External), Indoor - requirements that are No Air-conditioning exposed to borated water (external)

(Some Electrical and l&C

Systems)

The applicant stated, per Note J in LRA Table 3.6.2-1, that for the above components neither

the component nor the material and environment combination is evaluated in GALL.

The staff's review of LRA Section 3.6 identified areas in which additional information was

necessary to complete the review of the applicant's results. The applicant responded to the

staff's RAI as discussed below.

RAI 3.6.2.1-1. In RAI 3.6.2.1-1, dated November 18, 2004, the staff requested the applicant to

provide justification for not including the above components in the AMPs, or provide AMPs for

the above components.

During a telephone conference of its response dated January 25, 2005, the applicant agreed to

delete Note J in LRA Table 3.6.2-1. However, the applicant insisted that no AMPs are required

for above components. The staff's RAI for each component listed above, the justification

provided by the applicant for not providing AMPs for the above components, and the staff

evaluation, is as follows:

High-Voltace Insulators (Offsite Power System). The staff reviewed the high-voltage insulators

components, environment, and AMP.

RAI 3.6.2.1-2. In RAI 3.6.2.1-2, dated November 18, 2004, the staff requested the applicant to

explain why an AMP for high-voltage insulators is not needed.

In its response, dated January 25, 2005, the applicant stated:

Various airborne particulate contaminants such as industrial effluents, winter road-salt,

and dust can contaminate insulator surfaces. Due to the location of PBNP in a rural

environment with no major industry in close proximity, contamination from industrial

effluents is not significant. No major traffic runs near the switchyard to make winter

road-salt airborne. Lake Michigan is a fresh-water lake and therefore there is no salt

spray that can affect the insulators. The buildup of any other surface contaminants is

gradual and would be washed away by rainfall or snow, which is seasonal in nature,

and cumulative buildup is not expected. The glazed insulator surface aids this

contamination removal. Operating experience of over thirty years at PBNP has shown

that this is true. Therefore, surface contamination of high-voltage insulators is not an

AERM at PBNP.

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On the basis of the above discussion, the staff found this justification acceptable because the

applicant provided operating experience that demonstrates that an AMP is not needed. The

staff's concern described in RAI 3.6.2.1-2 is resolved.

Phase bus (480 VAC. 4160 VAC. and 13.8K VAC Power Systems). The staff reviewed the

phase bus (480 VAC, 4160 VAC, and 13.8K VAC power systems) components, environment,

and AMP.

RAI 3.6.2.1-3. In RAI 3.6.2.1-3, dated November 18, 2004, the staff requested the applicant to

explain why an AMP for bus ducts is not needed. Conforming to INs 89-64, 98-36, and 2000-4,

the staff requested the applicant to consider providing an AMP.

In its response, dated January 25, 2005, the applicant stated:

The phase bus in-scope for license renewal at PBNP is fully enclosed and installed in

the control building, turbine building, 13.8K VAC switchgear building, gas turbine

building, and outdoors (weatherproof enclosures). Where enclosure vents are part of

the design, filters are provided to ensure cleanliness. No phase bus is installed in the

containment, facade, or the PAB. Thus, no phase bus is installed in an area where it is

exposed to debris or dust, radiation, or high temperatures. The environments for phase

bus in the control building and 13.8K VAC switchgear buildings are indoors, with air

conditioning. Phase bus between non-vital switchgear in the turbine building is routed

beneath the ceiling of the control building. Thus exposure to moisture is eliminated in

these locations. Phase bus located outdoors is weatherproof designed for those

locations, integral to the switchgear connections to the high-voltage and low-voltage

station auxiliary transformers for each unit, and inspected and maintained as part of

those active components, which includes periodic inspections and cleaning. Where

appropriate, heaters are installed to prevent condensation internal to the bus enclosure.

Therefore, exposure to moisture due to water ingress or condensation is mitigated.

Carbon steel hardware (bolts, washers, nuts and clamp screws) was factory coated

(plated or galvanized) to inhibit corrosion and is used only in the bus duct enclosure

assembly. Stainless steel hardware used in bus electrical connections (copper bus bar

and fittings) has no age-related degradation due to moisture in either indoor or outdoor

environments. Bolting is typically done using Belleville or lock washers to maintain

contact pressure. After more than 33 years in these service environments, minimal or

no signs of corrosion or loss of material have been observed and no functional loss has

been observed. Therefore, loss of material for steel hardware due to corrosion or

oxidation, and loosening of connecting hardware are not applicable aging effects that

would lead to a loss of intended function for the phase bus for the period of extended

operation.

Phase bus is supported by static structural components such as concrete foundations,

building steel, and switchgear cabinets. Structural support and enclosures are

considered part of the Component Support Commodity Group for aging management.

Phase bus is connected to static equipment that does not normally vibrate such as

switchgear, transformers and disconnect switches; therefore, loosening of bolted

connections is not an aging effect requiring management. Vibration is not an applicable

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stressor for these connections to non-moving and non-vibrating equipment and

supports, and aging effects due to vibration are not applicable. Flexible connectors are

used throughout the plant in connections between phase bus and different sections of

switchgears.

The one section of phase bus connected to a potential source of vibration connects to

the non-vital gas turbine generator through flexible conductors. These flexible

conductors prevent generator vibrations from propagating into the rigid phase bus.

Internal to the enclosures the bus is supported by porcelain insulators, which have no

aging effects in their controlled environments. Flexible connectors are used throughout

the plant in connections between phase bus and different sections of switchgear. In

addition this equipment is only run for testing and as a (typically) summer peaking unit.

Therefore, the associated bus will have far less than 40 years of actual operation at the

end of the period of an extended license. In addition, vibration is not an applicable

stressor even for phase bus that is connected to equipment that may move, and aging

effects due to vibration are not applicable. Periodic gas turbine maintenance,

inspections, and testing include this phase bus in their scope and would address any

equipment issue found.

All of the bus and flexible connections are copper, silver-plated and/or coated with

anti-oxidant grease. Copper bus, solid and flexible connectors and ground straps are

highly conductive and make a good contact surface. To prevent the formation of oxide

on connection surfaces, the connections were factory silver plated, cleaned to remove

any existing oxide, and covered with grease to prevent air from contacting the surface

before assembly. The grease excludes air from the connection after assembly,

precluding oxidation of the surface, thereby maintaining good conductivity between the

bus connecting surfaces. The grease is a consumable that is replaced during each

routine maintenance of the bus.

The referenced NRC Information Notices (IN) were re-examined during the RAI phase

of the NRC review of the PBNP LRA. Specific attention was directed to the questions

asked by NRC reviewers regarding why PBNP was not proposing a bus bar aging

management program.

* IN 89-64 was previously examined and considered in the Operating Experience

section of the PBNP electrical AMR. The failures noted in this IN were results of

either an accumulation of water or debris, inadequate design, manufacturing

defect, or an environment that caused deterioration of insulation. A review of the

construction, materials, and bus bar environments at PBNP concluded that no

aging effects from this IN were applicable to phase bus at PBNP.

* IN 98-36 was examined and excluded from the AMR since it addresses

event-driven faults caused by impact of an external foreign object (roofing

materials), direct water leakage or moisture intrusion, inadequate design or

assembly, or mis-operation, including an event at PBNP where a bus duct heater

breaker was open for an extended period of time (exceeding one year). These

are all events due to causes other than aging. Therefore, no aging effects from

this IN were applicable to phase bus at PBNP.

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* IN 2000-14 was examined and excluded from the AMR since it addresses a

fault-based event, not aging. Multiple non-Class 1 E buses were lost due to

co-location (crossing) of bus duct with an initiating failure caused by a center bus

bar overheating at a splice joint, causing a PVC boot to smoke, and heat induced

failure of fiberglass insulation on adjacent phases causing phase-to-phase

arcing. A combination of poor design factors was the root cause: mixture of

aluminum and copper bus bars, poor silver-plating on the aluminum bar,

corrosion induced on the aluminum bar due to the PVC boot material, and

undersized splice plates of wrong material not centered on the bus bar, reducing

contact area. Splice plates were undersized aluminum rather than larger copper

plates, used by the vendor during tests to determine design temperature rise to

meet IEEE 37.20-1969 of 650

C. The bus was routinely loaded to 2100 amps

and actual worst case loaded to 2250 amps, its rating limit. This caused the bus

to exceed the design conditions for some time. Torque relaxation likely occurred

due to the overheating and bus bar expansion and contraction. A 1995

explosion of an auxiliary transformer that physically displaced the bus could have

also contributed to the low torque values. Inability to isolate the bus caused a

small event to propagate to multiple buses and major damage.

The only non-Class 1 E buses in-scope for PBNP are in the 13.8K VAC system.

The system was constructed in 1988 - 1991 and is located separate from all

other bus in a dedicated building. Bus bar at PBNP is all copper with proper

sized and located connections, per vendor design (PBNP was a turn-key plant by

Westinghouse, which supplied and installed the original switchgear and bus).

Bus duct are not co-located with other bus duct from the same or different parts

of any electrical systems and are able to be isolated, thus fault propagation is not

an issue. Bus bar loading is low compared to bus bar rating and thus expansion

and contraction is minimized to within the range of the design capacity of the

lock washers and Belleville washers.

The PBNP bus bar configuration is represented by all copper bus, properly assembled

to original vendor specifications, and installed in a dry, clean environment. Therefore,

there are no applicable aging effects for the phase bus that are in-scope for license

renewal at PBNP when exposed to their service conditions for the extended period of

operation.

The staff reviewed the above response and found that sufficient justification had not been

provided for preventing cracking or failure of busbar insulation as observed at many plants

noted in IN 89-64. Similarly, the loosening of terminal connections resulting from the thermal

cycling (as indicated in the Sandia 96-0344 report) was not adequately addressed in the above

response.

The staff discussed the applicant's needs regarding an AMP for bus (phase) duct with at least

the following essential components.

* Parameters Monitored/inspected: A sample of accessible bolted connections will be

checked for proper torque. This program will also inspect the internal portion of the bus

duct for cracks, corrosion, foreign debris, excessive dust buildup, and evidence of water

intrusion. The bus insulation system will be inspected for signs of embrittlement,

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cracking, melting, swelling or discoloration, which may indicate overheating or aging

degradation. The (internal) bus supports will be inspected for structural integrity and

signs of cracks.

* Detection of Aging Effects: This program will be completed before the end of the initial

40-year license term and every 10 years thereafter. This is an adequate period to

preclude failures of the bus ducts since experience has shown that aging degradation is

a slow process. A 10-year inspection frequency will provide two data points during a

20-year period, which can be used to characterize the degradation rate.

* Acceptance Criteria: Bolted connections must meet the minimum torque specifications.

bus ducts are to be free from unacceptable visual indications of surface anomalies,

which suggest that conductor insulation degradation exists.

During a meeting, on February 15, 2005, the staff indicated and the applicant agreed, that the

applicant's response required further clarification.

In its response, a clarification letter dated March 15, 2005, the applicant stated that the

metal-enclosed phase bus in the power systems within the scope of license renewal had not

shown a potential for aging that requires management. Nonetheless, the applicant committed

to perform periodic inspections of the bus duct as part of the Periodic Surveillance and

Preventive Maintenance Program. These periodic visual inspections will look for signs of

insulation cracking, corrosion, debris, excessive buildup, moisture, water intrusion, and

insulation discoloration.

On the basis of the above discussion, the staff found this acceptable. The applicant provided a

commitment, which provides reasonable assurance that aging effects will be adequately

managed. The staff's concern described in RAI 3.6.2.1-3 is resolved.

Transmission Conductors (Offsite Power Systems). LRA Section 2.5.1, under the sub-heading,

"Transmission Conductors," states that the transmission conductor connections to active

disconnect switches, power circuit breakers, and transformers are inspected using

thermography and maintained along with and as part of the disconnect switch, power circuit

breaker or transformer and, therefore, meet the definition of an active component as discussed

in the Statement Of Considerations (SOC) that accompanied the Rule.

RAI 3.6.2.1-4. The reason (Note J) provided in LRA Table 3.6.2-1 for not including

transmission conductors in any AMP was different from the explanation provided in LRA

Section 2.5.1. In RAI 3.6.2.1-4, dated November 18, 2004, the staff requested the applicant to

provide an explanation for the discrepancy between LRA Table 3.6.2-1 and LRA Section 2.5.1

for transmission conductors.

In a telephone conference discussion of its response dated January 25, 2005, the applicant

agreed to delete Note J against transmission conductors in LRA Table 3.6.2-1 to resolve this

discrepancy. On the basis of its review, the staff found acceptable the elimination of Note J

from LRA Table 3.6.2-1. The staff's concern described in RAI 3.6.2.1-4 is resolved.

Electrical Connections Not Subject to 10 CFR 50.49 EQ Requirements That Are Exposed to

Borated Water Leakage. The staff reviewed the electrical connections not subject to EQ

requirements, components, environment, and AMPs.

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RAI 3.6.2.1-5. In RAI 3.6.2.1-5, dated November 18, 2004, the staff requested the applicant to

justify why components located indoors but outside of containment were not included in the

Boric Acid Corrosion Program, per LRA Table 3.6.2-1.

In its email, dated December 9, 2004, preceding its formal response, dated January 25, 2005,

the applicant stated:

Piping systems containing borated water are located in three physical areas of the plant:

the Unit 1 containment, the Unit 2 containment, and the Primary Auxiliary Building. The

environment of Borated Water Leaks (External) in Table 3.6.2-1 applies to any location

in all three areas where in-scope electrical and Instrumentation and Controls (I&C)

cables and connections are located and may be exposed to borated water leakage, both

in and out of containment. Therefore, Table 3.6.2-1 denotes that the Boric Acid

Corrosion Program applies to the in-scope electrical components in all of these

locations.

The connections in these physical locations are identified in Table 3.6.2-1 as also having

normal environments away from sources of borated water, Containment (Extemal) and

Indoor - No Air-Conditioning (Extemal) in the Primary Auxiliary Building, where no AERM

is expected. These materials and environments were considered in our AMR, and for

the locations away from boric acid leaks no AERM were identified. NUREG-1 801 does

not have a specific program for these components, except as part of Xl.E1; therefore,

Note J was referenced. Both the non-boric acid environments and Note J could be

omitted if that eliminates the confusion in this entry.

On the basis of its review, the staff found acceptable the elimination of Note-J from LRA

Table 3.6.2-1. The staff's concern described in RAI 3.6.2.1-5 is resolved.

Switchvard Buses and Connections (Offsite Power Svstem). The staff noted that in LRA

Table 3.6.2-1, it is indicated that "Switchyard buses and connections (Offsite Power System)"

will be covered under Cable Condition Monitoring Program. However, Cable Condition

Monitoring Program does not include switchyard buses and connections. Also, in LRA

Section 2.5.1, under the sub-heading, "Switchyard Bus," the applicant stated that the review of

switchyard bus includes the switchyard bus and the hardware used to secure the bus to a

high-voltage insulator. This includes corona rings and other similar fixtures that are standard

design features of the switchyard bus. The applicant further stated that the bus connection to

an active disconnect switch is inspected using thermography and maintained along with and as

part of the disconnect switch and, therefore, meets the definition of an active component as,

discussed in the SOC that accompanied the Rule.

RAI 3.6.2.1-6. In RAI -3.6.2.1-6, dated November 18, 2004, the staff requested the applicant to

provide an explanation for the discrepancy between LRA Table 3.6.2-1 and LRA Section 2.5.1

regarding switchyard buses and connections.

In its response, dated January 25,2005, the applicant stated that:

The circuit switchers are the boundary components between in-scope and not-in-scope

components in the switchyard. The Cable Condition Monitoring Program covers the

aging management of the connecting control cabling for the switchgear, transformers,

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and circuit switchers located in the switchyard that are in-scope for license renewal. The

only switchyard bus and fixtures in-scope are directly connected to the circuit switchers

and are maintained as part of these active components. High-voltage insulators were

separately evaluated as supports for these components. All switchyard bus, fixtures,

supports, and other components beyond the circuit switchers are not-in-scope. The

description of the types of inspection used are typical of normal plant component

condition monitoring activities and do not constitute an AMP. No aging is expected for

these components. Operating experience of over thirty years at PBNP has shown that

this is true.

On the basis of its review and RAI response, the staff found the elimination of Note J from LRA

Table 3.6.2-1 is acceptable to resolve this discrepancy. The staff's concern described in

RAI 3.6.2.1-6 is resolved.

Conclusion. On the basis of its review, the staff found that the applicant had appropriately

evaluated AMR results involving material, environment, AERM, and AMP combinations that are

not evaluated or addressed in the GALL Report. The staff found that the applicant had

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

3.6.3 Conclusion

On the basis of its review, the staff concluded that the applicant had demonstrated that the

aging effects associated with the electrical and I&C 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 concluded

that they adequately describe the AMPs credited for managing aging of the electrical and l&C

systems, as required by 10 CFR 54.21 (d).

3.7 Conclusion for Aging Management Review Results

The staff reviewed the information in LRA Section 3, 'Aging Management Review Results," and

Appendix B, "Aging Management Programs and Activities." On the basis of its review of the

AMR results and AMPs, the staff concluded that the applicant had 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 concluded that

the FSAR supplement adequately describes the AMPs credited for managing aging as required

by 10 CFR 54.21 (d).

With regard to these matters, the NRC staff has concluded that there is reasonable assurance

that the activities authorized by the renewed license will continue to be conducted in

accordance with the CLB, and that any changes made to the PBNP current licensing basis in

order to comply with 10 CFR 54.21 (a)(3) are in accord with the Atomic Energy Act of 1954, as

amended, and NRC regulations.

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SECTION 4

TIME-LIMITED AGING ANALYSES

4.1 Identification of Time-Limited Aging Analyses

This section addresses the identification of time-limited aging analyses (TLAAs). Nuclear

Management Company, LLC (the applicant) discusses the TLAs in LRA Sections 4.2

through 4.8. SER Sections 4.2 through 4.8 document the review of the TLAAs conducted by

the staff of the U.S. Nuclear Regulatory Commission (NRC or the staff).

TLAAs are certain plant-specific safety analyses that involve time-limited assumptions defined

by the current operating term. Pursuant to Title 10, Section 54.21 (c)(1), of the Code of Federal

Regulations, the applicant for license renewal must provide a list of TLAAs, as defined in

10 CFR 54.3.

In addition, pursuant to 10 CFR 54.21 (c)(2), an applicant must provide a list of plant-specific

exemptions granted under 10 CFR 50.12 that are based on TLAAs. For any such exemptions,

the applicant must provide an evaluation that justifies the continuation of the exemptions for the

period of extended operation.

4.1.1 Summary of Technical Information In the Application

To identify the TLAAs, the applicant evaluated calculations for the Point Beach Nuclear Plant

(PBNP) Units 1 and 2 against the six criteria specified in 10 CFR 54.3. The applicant indicated

that it had identified the calculations that met the six criteria by searching the current licensing

basis (CLB) and industry license renewal related documents including the Standard Review

Plan for License Renewal (SRP-LR) Chapter 4, NEI 95-10, Statements of Consideration for

10 CFR 54, Westinghouse Owners Group Generic Technical Reports, and previously submitted

LRAs for other plants. The CLB includes the FSAR, Technical Specification, NRC SERs,

docketed correspondence, and NRC regulatory commitments and requirements.

The applicant listed the following applicable TLAAs in LRA Table 4.1-2, "Time-Limited Aging Analyses":

* reactor vessel irradiation embrittlement

* fatigue

* fracture mechanics analysis

* loss of preload

* neutron absorber

* wear

* environmental qualification

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Pursuant to 10 CFR 54.21 (c)(2), the applicant identified exemptions granted under

10 CFR 50.12 that were based on TLAAs, as defined in 10 CFR 54.3. The applicant listed the

following exemptions associated with TLAAs in LRA Table 4.1-1, "Active Exemptions

Associated with Time-Limited Aging Analysis":

* determination of adjusted/indexing reference temperatures for pressurized thermal

shock TLAA

* use of the latest Edition of supplemental ASTM El 85-98 for pressurized thermal shock

TLAA

* alternative testing methods of determination of fracture toughness for pressurized

thermal shock TLAA

4.1.2 Staff Evaluation

In LRA Section 4.1, the applicant identified the TLAAs applicable to 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 (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 CLB

The applicant provided a list of common TLAAs from NUREG-1 800, "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 Units 1 and 2 in LRA Table 4.1-2,

"Time-Limited Aging Analyses."

As required by 10 CFR 54.21 (c)(2), an applicant must provide a list of all exemptions granted

under 10 CFR 50.12 that are determined to be based on a TLAA and that 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 CLB and evaluated each exemption in effect for TLAA

applicability. The applicant also identified TLAA-based assumptions.

The staff review of LRA Section 4.1 identified areas in which additional information was

necessary to complete the review of the listed TLAAs and plant-specific exemptions.. The

applicant responded to the staff's requests for additional information (RAI) as discussed below.

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RAI 4.1.1-1. The applicant stated that industry license renewal related documents were

searched to identify a list of known TLAAs that could be applicable to PBNP. This potential list

of TLAAs is itemized in LRA Section 4.1.1.1. The applicant listed the TLAAs applicable in LRA

Table 4.1-2. In RAI 4.1.1-1, dated November 17, 2004, the staff requested the applicant to

indicate whether there are any calculations or analyses at PBNP that address the topics listed

in LRA Section 4.1.1.1 that were not included in LRA Table 4.1-2.

In its response, dated January 25, 2005, the applicant stated that there are no calculations or

analyses at PBNP that address the topics listed in LRA Section 4.1.1.1 that were not included in

LRA Table 4.1-2. Based on the applicant's response, the staff concluded that all appropriate

TLAAs applicable to PBNP were listed, and the staff concluded that the applicant's response to

RAI 4.1.1-1 is acceptable. The staff's concern described in RAI 4.1.1-1 is resolved.

RAI 4.1.1-2. LRA Section 4.1.2, pursuant to 10 CFR 54.21 (c)(2), listed the plant-specific

exemptions granted pursuant to 10 CFR 50.12. This section described the exemptions and

why they were still needed. In RAI 4.1.1-2, dated November 17, 2004, the staff requested the

applicant to provide an evaluation that justifies the continuation of these exemptions for the

period of extended operation.

In its response, dated January 25, 2005, the applicant stated that it had withdrawn the request

for exemptions to 10 CFR 50.61, and Appendices G and H to 10 CFR Part 50, in its letter dated

August 3, 2004. In its letter, dated October 25, 2004, the applicant further stated that it revised

LRA Section 4.1.2 to state that 'No TLAA related exemptions granted pursuant to

10 CFR 50.12 were identified." The staff reviewed the subject letter and noted that the

applicant withdrew its TLAA-related exemptions. Based on the applicant's response that no

TLAA-related exemptions exist, the staff considers that the applicant's response to RAI 4.1.1-2

is acceptable. The staff's concern described in RAI 4.1.1-2 is resolved.

4.1.3 Conclusion

On the basis of its review and the applicant's response to the staff's RAls, the staff concluded

that the applicant provided an acceptable list of TLAAs as required by 10 CFR 54.21(c)(1). In

addition, based on the applicant's RAI responses, the staff concluded that no exemptions were

granted on the basis of a TLAA pursuant to 10 CFR 50.12 and, therefore, the requirement under 10 CFR 54.21 (c)(2) does not apply.

4.2 Reactor Vessel Irradiation Embrittlement

Neutron embrittlement is a significant aging mechanism for all ferritic mateijals that have a

neutron fluence greater than 1017 n/cm2 (E>1 .0 MeV). The relevant calcul tibns use peddictions

of the cumulative damage to -the reactor vessel (RV) from neutron embrittler bpt; a d ere

originally based on the 40 calendar-year plant license. The reactor pressure,1 ess(Rii II

contains the core fuel assemblies and is made of thick steel plates that are weldedto geier.

Neutrons from the fuel in the reactor irradiate the vessel as the reactor is bpemtedand change

the material properties of the steel. The most pronounced and significant changes occur in the

material property known as fracture toughness. ;l I

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Fracture toughness is a measure of the resistance to crack extension in response to stresses.

A reduction in this material property due to irradiation is referred to as embrittlement. The

largest amount of embrittlement usually occurs at the section of the vessel's wall closest to the

reactor fuel, otherwise referred to as the vessel's beltline. The rate at which the vessel's steel

embrittles also depends on its chemical composition. The amounts of two elements in the

steel, specifically copper and nickel, are the most important chemical elements in determining

how sensitive the steel is to neutron irradiation.

The applicant identified three analyses affected by irradiation embrittlement that were identified

as TLAAs. These analyses are discussed in LRA Section 4.2. The analyses identified as

TLAAs are:

(1) pressurized thermal shock (PTS)

(2) reactor vessel upper shelf energy (USE)

(3) pressure/temperature (P-T) limit curves

The corresponding subsections of this SER (4.2.1 - 4.2.3, respectively) present the staff's

evaluation of the RV irradiation embrittlement TLAAs.

4.2.1 Reactor Vessel Pressurized Thermal Shock

4.2.1.1 Summary of Technical Information In the Application

Section 50.61 of 10 CFR provides the fracture toughness requirements protecting the RVs of

pressurized water reactors against the consequences of PTS. Applicants are required to

perform an assessment of the RV materials projected values of the PTS reference temperature

(RTpTs), through the end of their operating licenses. The Rule requires each applicant to

calculate the end-of-life RTp, value for each material located within the beltline of the reactor

pressure vessel. The RTp, value for each beltline material is the sum of the unirradiated nil

ductility reference temperature (RTNDT) value, a shift in the RTNDT value caused by exposure to

high-energy neutron irradiation of the material (i.e., ARTNDT value), and an additional margin

value to account for uncertainties (ie., M value). Section 50.61 of 10 CFR also provides

screening criteria against which the calculated values are to be evaluated. RV beitline

base-metal materials (forging or plate materials) and longitudinal (axial) weld materials are

considered to provide adequate protection against PTS events if the calculated RTpTS values

are less than or equal to 270 "F. RV beltline circumferential weld materials are considered to

provide adequate protection against PTS events if the calculated RTpTs values are less than or

equal to 300 DF.

Regulatory Guide (RG) 1.99, Revision 2, provides an expanded discussion regarding the

calculations of the shift in the RTNDTvalue caused by exposure to high-energy neutron

irradiation and the margin value to account for uncertainties. In this RG, the shift in the RTNDT

value caused by exposure to high-energy neutron irradiation is the product of a chemistry factor

and a fluence factor. The fluence factor is dependent upon the neutron fluence, and the

chemistry factor may be determined from surveillance material or from the tables in the RG. If

the RV beltline material is not represented by surveillance material, its chemistry factor and the

shift in the RTNDT value caused by exposure to high-energy neutron irradiation may be

determined using the methodology documented in position 1.1 and the tables in this RG. The

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chemistry factor determined from the tables in the RG depends upon the amount of copper and

nickel in the beltline. If the RV beltline material is represented by surveillance material, its

chemistry factor may be determined from the surveillance data using the methodology

documented in position 2.1 of this RG. Section 50.61 of 10 CFR contains methods of

determining RTNDT values equivalent to RG 1.99, Revision 2.

In LRA Section 4.2.1, the applicant discussed the PTS analysis for Units 1 and 2, using the

criteria of 10 CFR 50.61.

RTpTs values were calculated for the inside surface of the beltline region materials for the Unit 1

RPV using Charpy-based fracture toughness evaluations in accordance with the methods of

10 CFR 50.61 for a 53 effective full power year (EFPY) operating period. The RTpTs values for

the beltline region materials at the end of the period of extended operation were calculated to

be lower than the applicable screening criteria values established in 10 CFR 50.61.

RTpTS values were calculated for the inside surface of the beltline region materials for the Unit 2

RPV using Charpy-based fracture toughness evaluations in accordance with the methods of

10 CFR 50.61 for a 53 EFPY operating period. The RTp. values for the beltline region

materials at the end of the extended period of operation were calculated to be lower than the

applicable screening criteria values established in 10 CFR 50.61, with the exception of the

intermediate-to-lower shell circumferential weld. The intermediate-to-lower shell circumferential

weld is the limiting Unit 2 RPV weld.

In its revised submittal, letters dated September 10 and October 25, 2004, the applicant

provided information about the plan for addressing PTS concerns prior to exceeding the

screening criteria. Paragraph (c)(iii) of 10 CFR 54.21 allows the applicant to demonstrate that

the effects of aging on the intended functions of the SSC will be adequately managed for the

period of extended operation. This option permits an applicant to elect not to extend the

existing TLAA.

4.2.1.2 Staff Evaluation

The staff's review of LRA Section 4.2.1 identified areas in which additional information was

necessary to complete the review of the PTS evaluation. The applicant responded to the staff's

RAls as discussed below.

In the license renewal revised submittal, the applicant provided Unit 1 RT.. analyses for the

materials in the PBNP reactor vessel beltline. Table 4.2.1-1 in the submittal provides, the

chemistry factor and the predicted RTprs value through 53 EFPY for each forging and weld in

the PBNP reactor vessel beltline.

In order to verify the predicted RTp. value through 53 EFPY, the staff used the neutron values

provided by the applicant. The neutron fluence calculation used END/B-VI scatteringcross

section data set. The calculated fluence projections were determined using methodsaconsistent

with RG 1.190, uCalculational and Dosimetry Methods for Determining Pressure Vessel Neutron

Fluence."

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In addition to the plant-specific neutron exposure calculations, dosimetry sets from 3 in-vessel

and 20 ex-vessel sensor sets irradiated at Unit 1, and 4 in-vessel and 20 ex-vessel sensor sets

irradiated at Unit 2 were also reanalyzed using dosimetry evaluation methodologies that follow

the guidance provided in RG 1.190. The results of these dosimetry re-evaluations were then

used to validate the calculational models that were applied in the plant-specific neutron

transport analysis of the Point Beach RPVs. The projected fluence values for the Units 1 and 2

vessel at the end of extended life, 53 EFPY, are 4.71 x 1019 n/cm2 and 4.85 x 10'9 n/cm2

respectively. The fluence projections were revised in 2004 to account for actual unit operational

history (including the 1.7 percent mini-uprate performed in 2003), and a planned full unit uprate

to 1678 MWt in 2008. These fluence projections were based on historical operational data, and

forecasted uprated (1678 MWt) power conditions using a low-low leakage fuel management

pattern without the presence of hafnium power suppression absorber rods. However, the

applicant also made a commitment that PBNP will continue operation with hafnium absorber

assemblies in service until the resolution of the Unit 2 intermediate-to-lower shell girth weld PTS

issue via an alternative analysis methodology.

The applicant's projected fluence is calculated fluence, not the best-estimate fluence, and the

calculation is based on RG 1.190; therefore, the staff accepts the fluence calculation

methodology.

The staff independently evaluated RTpTs values for Unit 1 and identified that the values are

below the 10 CFR 50.61 screening criteria. Therefore, the staff concluded that PBNP Unit 1 RV

will meet the requirements of 10 CFR 50.61 through the expiration of the period of extended

operation.

RTp. values for Unit 2 are lower than the screening criteria values established in 10 CFR 50.61

for the current license period. The staff independently verified the applicant's RTp. values

provided in LRA Table 4.2.1-2 and concluded that the RTpm values will be below the PTS

screening criteria except for the intermediate-to-lower shell girth weld. The

intermediate-to-lower shell girth weld will exceed the PTS screening criteria for the Unit 2 RV

during the period of extended operation. The screening criteria established in 10 CFR 50.61

will be exceeded for the limiting Unit 2 intermediate-to-lower shell girth weld at a neutron

fluence of 3.31 x 1 019 n/cm2. The fluence projections also indicate that the limiting weld will

experience this fluence at 38.1 EFPYs. Using a long-term capacity factor of 95 percent, this

fluence would be achieved in late 2017.

If a reactor vessel is projected to exceed the PTS screening criteria, 10 CFR 50.61 (b)(3)

requires the applicant to implement a flux reduction program that is reasonably practicable to

avoid exceeding the PTS screening criteria. If the flux reduction program does not prevent the

reactor vessel from exceeding the PTS screening criterion at the end of life, the applicant can

choose between the two options in 10 CFR 50.61 to meet PTS requirements. The applicant

can submit a safety analysis pursuant to 10 CFR 50.61 (b)(4) to determine what, if any,

modifications to equipment, systems, and plant operation are necessary to prevent failure of the

reactor vessel from a postulated PTS event. The other option is to perform a thermal-annealing

treatment of the reactor vessel pursuant 10 CFR 50.61 (b)(7) to recover fracture toughness.

Section 50.61 of 10 CFR requires details of the approach selected to be submitted for NRC

approval at least three years before the reactor vessel is projected to exceed the PTS

screening criteria.

4-6
The license renewal applicant that chooses to use the 10 CFR 54.21 (c)(1)(iii) option for

managing the reactor vessel PTS TLAA must provide an assessment of the CLB TLAA for PTS,

a discussion of the flux reduction program implemented in accordance with 10 CFR 50.61 (b)(3),

if necessary, and an identification of the viable options that exist for managing the aging effect

in the future ("Pressurized Thermal Shock Analyses for Renewal of Certain Nuclear Power

Plant Operating Licenses," Executive Director Memo to Commissioners, dated May 27, 2004,

ML 041190564).

RAI 4.2-1. On August 3, 2004, the staff met with the applicant to discuss the RV integrity

issues related to the license renewal application. In that meeting, the staff stated that when the

applicant provides its revised RPV integrity analyses, one defined 'operational basis for

projecting fluence values to be used for PTS, USE, and P-T limit TLAAs must be chosen.

In its letter dated September 10, 2004, the applicant revised LRA Sections 4.1.2, 4.2.1, 4.2.2,

4.2.3, and Appendices Al 5.2.18, Al 5.4.1, Al 5.5, and B2.1.18. The staff noted from the

revised sections that the applicant did not provide one defined operational basis. The fluence

projections used for PTS are different from the fluence projections used for P-T limits and the

USE evaluation. In RAI 4.2-1, dated September 23, 2004, the staff requested the applicant to

modify its evaluation of reactor vessel TLAAs (P-T, USE, RTp.) using the same projected

fluence basis.

RAI 4.2-2. On August 3, 2004, the staff also discussed that once the applicant chooses its

calculational basis, a PTS analysis should be submitted in accordance with the methodology in

10 CFR 50.61 for both units. The analysis must specifically state when Unit 2 will exceed the

PTS screening criteria.

In its letter dated September 10, 2004, the applicant revised Sections 4.1.2, 4.2.1, 4.2.2, 4.2.3,

and Appendices A15.2.18, A15.4.1, A15.5, and B2.1.18. As a followup to RAI 4.2-2, the staff

requested the applicant to provide the estimated EFPY and calendar year at which RTpTs values

for Unit 2 will exceed the screening criteria.

Recognizing that one of the Unit 2 RV welds will exceed the 10 CFR 50.61 PTS screening

criteria, in its response to the above RAls, by letter dated October 25, 2004, the applicant chose

to use the 10 CFR 54.21 (c)(1)(iii) option for managing the reactor vessel PTS TLAA.

Accordingly, the applicant provided a discussion of the flux reduction program implemented in

accordance with 10 CFR 50.61 (b)(3) and also identified other viable options that exist for

managing the aging effect in the future.

In both letters, the applicant made the following commitments:

* PBNP will continue to implement the low-low leakage loading fuel management pattern

to minimize the limiting weld fluence. In addition, PBNP will continue operation with

hafnium absorber assemblies in service until the resolution of the Unit 2

intermediate-to-lower shell girth weld PTS issue via an alternative analysis methodology.

* Documentation of a flux reduction program and other options, as necessary, allowed by

10 CFR 50.61 (b) for the Unit 2 RPV intermediate-to-lower shell girth weld, will be

completed within one-year of receipt of the extended license. Documentation within this

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time frame will support submittal of any required safety analysis at least three years

prior to the time frame that RTp. for Unit 2 is projected to exceed the screening criteria.

If acceptable PTS results cannot be provided prior to end of life (EOL) with alternative

analysis techniques, the PBNP flux reduction program will evaluate the feasibility and

practicality of pursuing additional aggressive flux reduction measures prior to EOL, such

as the insertion of part-length shielded fuel assemblies.

Based on the above discussion, the staff found that the applicant's response and commitments

are acceptable. The applicant's commitments will ensure that the aging effects will be

managed during the period of extended operation. The staff's concerns described in RAls

4.2-1 and 4.2-2 are resolved.

4.2.1.3 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.

The applicant provided FSAR supplement summary description of PTS in LRA Section Al 5.4.1.

On the basis of its review, the staff concluded that the FSAR supplement summary adequately

describes the TLAA on PTS and, is therefore, acceptable.

4.2.1.4 Concluslon

The staff reviewed the applicant's TLAA on PTS as summarized in Section 4.2.1, and

determined that the RV beltline materials at Unit 1 will continue to comply with the staff's

requirements for PTS in 10 CFR 50.61 throughout the period of extended operation as required

by 10 CFR 54.21 (c)(1)(ii).

In addition, the staff reviewed the applicant's TLAA on PTS as summarized in LRA

Section 4.2.1 and concluded that the applicant's TLAA for PTS at Unit 2 will continue to comply

with the staff's requirements for PTS in accordance with 10 CFR 50.61 throughout the period of

extended operation as required by 10 CFR 54.21 (c)(1)(ii). Although one circumferential weld in

the beltline region exceeds PTS screening criteria, the staff concluded 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)(iii).

The staff also concluded that the FSAR supplement, for both Units 1 and 2, 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 Reactor Vessel Upper Shelf Energy

Appendix G to 10 CFR Part 50 requires that reactor vessel beltline materials have Charpy USE

values in the transverse direction for the base metal and along the weld for the weld material of

no less than 75 ft-tb (102 J) initially, and must maintain Charpy USE values throughout the life

of the vessel of no less than 50 ft-lb (68 J). However, in accordance with Appendix G.

paragraph IV.A.1.a, Charpy USE values below these criteria may be acceptable if it is

4-8
demonstrated, in a manner approved by the Director, Office of Nuclear Reactor Regulation

(NRR), that the lower values of Charpy USE will provide margins of safety against fracture

equivalent to those required by ASME Code Section Xl, Appendix G.

RG 1.99, Revision 2, "Radiation Embrittlement of Reactor Vessel Materials," provides an

expanded discussion regarding the calculations of Charpy USE values and describes two

methods for determining Charpy USE values for RV beltline materials, depending on whether or

not a given RV beltline material is represented in the plant's RV material surveillance program

(i.e., 10 CFR Part 50, Appendix H program). If surveillance data are not available, the Charpy

USE is determined in accordance with position 1.2 in RG 1.99, Revision 2. If two or more

surveillance data are available, the Charpy USE should be determined in accordance with

position 2.2 in RG 1.99, Revision 2. These methods refer to Figure 2 in RG 1.99, Revision 2,

which indicates that the percentage drop in Charpy USE is dependent upon the amounts of

copper and the neutron fluence. Since the analyses performed in accordance with

10 CFR Part 50, Appendix G are based on a flaw with a depth equal to one-quarter of the

vessel wall thickness (1/40, the neutron fluence used in the Charpy USE analysis is the neutron

fluence at the 1/4t depth location.

4.2.2.1 Summary of Technical Information In the Application

The applicant Indicated that calculations have shown that the vessel beltline Charpy USE for

the limiting weld will be less than 50 ft-lb based on RG 1.99, Revision 2. Consequently, a

fracture mechanics evaluation was performed to examine the USE values in the limiting weld.

The evaluation examined the USE values for EOL extension conditions. The USE in the PBNP

fracture mechanics evaluation is reported in J-R (J Resistance) values with units in lb/in. The

J-R ratio methodology is described in B & W Owners Reactor Vessel Working Group reports

BAW-21 78A, "Low Upper Shelf Toughness Fracture Mechanics Analysis of Reactor Vessels of

B & W Owners Reactor Vessel Working Group for Level C & D Service Loads," and

BAW-2192PA "Low Upper Shelf Toughness Fracture Mechanics Analysis of Reactor Vessels of

B & W Owners Reactor Vessel Working Group for Level A & B Service Loads," both dated

April 1994. The staff reviewed and approved both these reports for referencing in licensing

applications in separate safety evaluations on March 29, 1994. The analysis demonstrates that

the limiting RV beltline weld satisfies the ASME Code requirements of Appendix K for ductile

flaw extensions and tensile stability using projected low upper-shelf Charpy impact energy

levels for the weld material at EOL. ASME Code Section Xl, Appendix K contains a

methodology and criteria acceptable to the staff for satisfying the requirement in

10 CFR Part 50, Appendix G, paragraph IV.A.1.a to demonstrate that materials with Charpy,

USE values below 50 ft-lb provide margins of safety against fracture equivalent to those i

required by ASME Code Section Xl, Appendix G. Therefore, by performing an analysis in

accordance with ASME Code Section Xl, Appendix K, the applicant stated that it satisfied the

requirements in 10 CFR Part 50, Appendix G, paragraph IV.A.1.a for 53 EFPY.

42.2.2 Staff Evaluation

The applicant performed a plant-specific fracture mechanics evaluation, BAW-2467NP,

July 2004, and demonstrated acceptable equivalent margins of safety against fracture. The

extended EOL lower bounding J-R values and all acceptance ratios are summarized in LRA

Table 4.2.2-1. From the table, it can be seen that the controlling weld is the Unit 1 RPV

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longitudinal weld SA-847. Since the values of the J-R ratios are greater than one, the

acceptance criteria for the equivalent margins analysis were met.

To confirm that the applicant's analysis satisfied the criteria in ASME Code Section Xl,

Appendix K, the staff performed an independent analysis using the methodologies and models

specified in RG 1.1 61, "Evaluation of Reactor Pressure Vessels With Charpy Upper-Shelf

Energy Less Than 50 ft-lb," NUREG/CR-5729, "Multivariable Modeling of Pressure Vessel and

Piping J-R Data," and ASME Code Section Xl, Appendix K. Based on the analysis, the staff

confirmed that the PBNP reactor vessel would have margins of safety against fracture

equivalent to those required by ASME Code Section Xl, Appendix G through the period of

extended operation.

4.2.2.3 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.

The applicant provided an FSAR supplement summary description of USE in LRA

Section Al 5.4.1. On the basis of its review, the staff concluded that the FSAR supplement

summary adequately describes the TLAA on USE and, is therefore, acceptable.

4.2.2.4 Conclusion

The staff reviewed the applicant's TLAA on USE, as summarized in LRA Section 4.2.2, and

determined that the RV beltline materials at Units 1 and 2 will continue to comply with the staff's

requirements in 10 CFR Part 50 throughout the period of extended operation. The staff

concluded 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 )(iii). The staff also concluded 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).

42.3 Reactor Vessel Pressure/Temperature Limits

Section 50.60 of 10 CFR, "Acceptance Criteria for Fracture Prevention Measures for Lightwater

Nuclear Power Reactors for Normal Operation," and 10 CFR Part 50, Appendix G, 'Fracture

Toughness Requirements," set forth the staff's requirements and criteria for generating the P-T

limits that are required for commercial U.S. light-water reactors.

4.2.3.1 Summary of Technical Information In the Application

Units 1 and 2 heatup and cooldown P-T limit curves were generated using adjusted reference

temperature (ART) values that bound both units. The applicant concluded that the P-T limits for

the units were TLAAs that needed to be assessed against the acceptance criteria of

10 CFR 54.21 (c)(1)(ii). The P-T limit curves that apply for the current operating conditions are

included in the Pressure and Temperature Limits Report (PTLR) for each unit. The PTLR was

approved by the staff, and these requirements are incorporated into its technical specifications.

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The PTLR will continue to be updated as required by either Appendices G or H of

10 CFR Part 50, or as operational needs dictate. The applicant stated that this will assure that

operational limits remain valid for current and projected cumulative neutron fluence levels.

4.2.3.2 Staff Evaluation

Section 50.60 of 10 CFR provides acceptance criteria for fracture prevention measures for light

water nuclear power reactors for normal operation, and it invokes the application of

Appendices G or H of 10 CFR Part 50, as applicable. The PTLR will continue to be updated as

required by either Appendices G or H of 10 Part CFR 50, or as operational needs dictate. The

staff agrees that this will assure that operational limits remain valid for current and projected

cumulative neutron fluence levels. Since the PTLR will continue to be updated as required by

either Appendices G or H of 10 CFR Part 50, as applicable, additional analysis at this time is

not required.

4.2.3.3 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.

The applicant provided an FSAR supplement summary description of P-T limits in LRA

Section Al 5.4.1. On the basis of its review, the staff concluded that the FSAR supplement

summary adequately describes the TLAA on P-T limits and, is therefore, acceptable.

4.2.3.4 Conclusion

The staff reviewed the applicant's TLAA on P-T limits, as summarized in LRA Section 4.3.4,

and determined that the RV beltline materials at Units 1 and 2, will continue to comply with the

staff's requirements in 10 CFR 50.60 throughout the period of extended operation. The staff

concluded that the applicant's TLAA for P-T limits 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 concluded that the FSAR supplement contains

an appropriate summary description of the TLAA on P-T limits for the period of extended

operation, as required by 10 CFR 54.21 (d).

4.3 Metal Fatlaue

A metal component subjected to cyclic loading at loads less than the static design load may fail

due to fatigue. Metal fatigue of components may have been evaluated based on an assumed

number of transients or cycles for the current operating term. The validity of "uch metal fati ue

analyses is reviewed for the period of extended operation. NUREG-i80l -de tifies atigue

aging related effects that require evaluation as possible TLAAs pursuart to 1 CR 5.21(c.

The applicant discussed the design requirements for components of the rea - or oont sys em.

The reactor vessels were designed and fabricated in accordance with the requlrements stat d

in the ASME Boiler and Pressure Vessel Code (ASME Code) Section I1,1 1965 Edition for

Unit 1, and 1968 Edition through winter 1968 Addenda for Unit 2. The reactor coolant pressure

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boundary piping and components were designed and fabricated in accordance with the

requirements of USAS B31.1, "Power Piping Code," 1955 Edition. Other safety-related piping

and fittings were also designed and fabricated in accordance with the requirements of

USAS B31.1, 1967 Edition.

4.3.1 Reactor Vessel Structural Integrity

4.3.1.1 Summary of Technical Information In the Application

In LRA Section 4.3.1, the applicant stated that the Unit 1 reactor vessel was designed to the

ASME Code Section l1l, 1965 Edition and the Unit 2 reactor vessel was designed to ASME

Code Section liI, 1968 Edition with Addenda through winter 1968. The original reactor vessel

Code Stress Reports included ASME Code Section III fatigue analyses of the reactor vessel

components based on a set of nuclear steam supply system (NSSS) design basis transients

and corresponding cycles, which are listed in FSAR Table 4.1-8.

The applicant stated that, in conjunction with the Steam Generator Replacement Project

(SGRP) and the Power Uprate Project (PUP), the number of anticipated NSSS transients was

projected for a 60-year operating period based on current plant operational practices and the

number of NSSS transients actually experienced. With few exceptions, the anticipated number

of transients for a 60-year operating period was far less than the original design number of

transients for a 40-year operating period. However, the pressure test transients projected for a

60-year operating period exceeded the original design number of transients for a 40-year

operating period. The NSSS design transient set was, therefore, revised to include an

increased number of pressure test transients, sufficient for a 60-year operating period. In

addition, the NSSS transient set was also revised to increase the number of steady-state

random reactor coolant system (RCS) pressure and temperature fluctuations to ensure that

adequate margin existed for a 60-year operating period. The revised set of NSSS design

transients were used to perform the detailed engineering evaluations in support of the SGRP

and the PUP. These evaluations were performed to assess the effects of the revised NSSS

design transients on the stress intensity ranges and fatigue cumulative usage factors (CUFs) at

locations identified in the reactor vessel stress reports. In the cases where the revised

transients were not bounded by the original analyses, or the transients were not included in the

original analyses, appropriate revised stress intensity ranges and CUFs were calculated. The

evaluations demonstrated acceptable results in accordance with both the ASME Code

Section 1II, 1965 Edition for the Unit 1 reactor vessel, and the ASME Code Section III, 1968

Edition with Addenda through winter 1968 for the Unit 2 reactor vessel. Otherwise, the design

basis stress intensity ranges and CUFs reported in the original stress reports continued to be

bounding.

The applicant stated that the reactor pressure vessel heads are scheduled for replacement in

the 2005 refueling outages. The replacement heads will also include new control rod drive

mechanisms (CRDMs). Material and design enhancements are being incorporated into the

replacement heads to enhance the corrosion resistance of the head penetration assemblies.

Other design enhancements are also being incorporated, including elimination of Alloy 600

materials, elimination of unnecessary spare head penetrations, elimination of unnecessary

joints in the CRDM housings, and an improved penetration weld joint design. The replacement

heads are being designed and manufactured to ASME Code Section III, 1998 Edition through

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2000 Addenda. The design specification for the replacement RPV heads specifies the same

design transient set that was used in the SGRP and the PUP but specifies a 40-year design-life.

The 40-year design-life of the replacement heads is considered adequate to match the 60-year

design-life of the other reactor vessel components.

4.3.1.2 Staff Evaluation

The applicant stated that the ASME Code Section IlIl Class 1 fatigue analyses at various reactor

vessel limiting locations were evaluated for extended operation, based on the Steam Generator

Replacement Project and Power Uprate Project NSSS design transient set, projected to the end

of the period of extended operation. These transient conditions and corresponding design

cycles are shown in LRA Appendix A Table 4.1.8. A list of the 60-year fatigue CUFs for the

reactor vessel components is also provided in LRA Table 4.3-2, where the highest calculated

CUF is below 1.0. The applicant has, therefore, demonstrated that the fatigue CUFs at these

locations meet the ASME Code Section III Class 1 design limiting value of 1.0 for the period of

extended operation.

The staff's review of LRA Section 4.3.1 identified an area in which additional information was

necessary to complete the review of the reactor vessel structural integrity evaluation. The

applicant responded to the staff's RAI as discussed below.

RAI 4.3-1. In RAI 4.3.1, dated November 17, 2004, the staff requested the applicant to show

that the limiting components of the PBNP reactor vessels evaluated for extended operation,

correspond to the components listed in NUREG-1 801 Table IV.A2, Volume 2, for PWR reactor

vessels.

In its response, dated January 28, 2005, the applicant provided a table showing the

components that were evaluated in the PBNP fatigue TLAAs. The locations shown in the table

correspond to those in NUREG-1 801, Volume 2. The staff found this response acceptable.

The staff's concern described in RAI 4.3.1 is resolved.

Based on its review, the staff concluded that the applicant provided reasonable assurance that

the reactor vessel fatigue TLAAs will remain valid to the end of the period of extended

operation, in accordance with 10 CFR 54.21(c)(1)(ii).

4.3.1.3 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."

The applicant provided an FSAR supplement summary description of reactor vessel structural

integrity in LRA Section Al 5.4.2. On the basis of its review, the staff concluded that the FSAR

supplement summary adequately describes the TLAA on reactor vessel structural integrity and,

is therefore, acceptable.

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4.3.1.4 Conclusion

The staff reviewed the applicant's TLAA on reactor vessel structural integrity, as summarized in

LRA Section 4.3.1, and determined that the metal fatigue assessments at Units 1 and 2 will

continue to comply with the staff's requirements throughout the period of extended operation.

The staff concluded that the applicant's TLAA for reactor vessel structural integrity 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 concluded

that the FSAR supplement contains an appropriate summary description of the TLAA on reactor

vessel structural integrity for the period of extended operation, as required by 10 CFR 54.21 (d).

4.3.2 Reactor Vessel Internals Structural Integrity

4.32.1 Summary of Technical Information In the Application

In LRA Section 4.3.2, the applicant stated that since the reactor vessel internals (RVI) were

designed prior to the introduction of ASME Code Section III, Subsection NG, a plant-specific

stress report on the RVI was not required for the original design. However, the RVI were

analyzed according to Westinghouse criteria that were similar to the criteria described in

Subsection NG. These analyses were used as the basis for the evaluations of critical RVI

components for uprated power conditions for a 60-year operating period.

The RVI fatigue analyses were reevaluated for the same transients evaluated in the reactor

vessel fatigue analyses. Structural evaluations were performed to demonstrate that the

structural integrity of the RVI components were not adversely affected directly by the change in

RCS conditions and transients and/or by secondary effects of the change on reactor

thermal-hydraulic or structural performance. Westinghouse performed a review and an

evaluation of the effects of the revised NSSS design transients and the full-power uprate

conditions on key reactor internal components.

The applicant stated that the results of this evaluation concluded that the change in RCS

thermal transients due to full uprated RCS conditions and a 60-year operating period does not

significantly affect the fatigue CUFs. The CUFs of all RVI components analyzed for fatigue,

using methods similar to those of Subsection NG, were also determined to be within the

allowable limit of 1.0 for a 60-year operating period.

4.3.22 Staff Evaluation

The staff's review of LRA Section 4.3.2 identified areas in which additional information was

necessary to complete the review of the RVI structural integrity evaluation. The applicant

responded to the staff's RAls as discussed below.

RAI 4.3.2-1. In RAI 4.3.2-1, dated November, 17, 2004, the staff requested the applicant to

show that the limiting components of the RVI that were evaluated for extended operation

correspond to the components listed in NUREG-1801 Table IV.B2, Volume 2, for PWR reactor

vessel internals.

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In its response, dated January 28, 2005, the applicant stated that the RVI were designed and

manufactured prior to the availability of ASME Code Section IlIl, Subsection NG, "Core Support

Structures." Fatigue evaluations were, therefore, neither required nor performed for all

components listed in Table IV.B2. However, the applicant indicated that the major RVI

components were evaluated for fatigue, based on the intent of ASME Code Section 1II,

Subsection NB. The applicant provided a table listing these major components (but not minor

components such as hold-down springs, bolts, fuel alignment pins and baffles, and former

plates) that were evaluated for fatigue.

On the basis of the above discussion, the staff found this response acceptable. The

components that were evaluated for fatigue correspond to those shown in Table IV.B2 in

NUREG-1 801, Volume 2. -The staff also found acceptable the justification for those

components for which fatigue analyses were not performed. The staff's concern described in

RAI 4.3.2-1 is resolved.

RAI 4.3.2-2. In RAI 4.3.2-2, dated November 17, 2004, the staff requested the applicant to

provide the 60-year design-basis CUFs for the key RVI listed on LRA page 4-41.

In its response, dated January 28, 2005, the applicant provided a table listing these

components and the corresponding CUFs, with the highest value being below 1.0. The fatigue

CUFs were shown to be below the ASME Code Section III Class 1 fatigue limit of 1.0. The staff

found this response acceptable.

On the basis of its review of LRA Section 4.3.2 and the RAI responses, the staff agreed with the

applicant that the fatigue TLAAs of the RVI, based on power uprated transients and operating

conditions, will remain valid for the period of extended operation, in accordance with the

requirements of 10 CFR 54.21 (c)(1 )(ii). The staff's concern described in RAI 4.3.2-2 is

resolved.

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. The applicant provided an FSAR supplement summary description of the RVI structural integrity

in LRA Section Al 5.4.2. On the basis of its review, the staff concluded that the FSAR

supplement summary adequately describes the TLAA on RVI structural integrity and, is

therefore, acceptable.

4.3.2.4 Conclusion

The staff reviewed the applicant's TLAA on RVI structural integrity, as summarized in LRA

Section 4.3.2, and determined that the metal fatigue assessments at Units 1 and 2 will continue

to comply with the staff's requirements throughout the period of extended operation. The staff

concluded that the applicant's TLAA for RVI structural integrity 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 concluded that

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the FSAR supplement contains an appropriate summary description of the TLAA on RVI

structural integrity for the period of extended operation, as required by 10 CFR 54.21 (d).

4.3.3 Control Rod Drive Mechanism Structural Integrity

4.3.3.1 Summary of Technical Information In the Application

In LRA Section 4.3.3, the applicant stated that both units have full-length (F/L) control rod drive

mechanisms (CRDMs). Unit 2 also has part-length (P/L) CRDMs. The F/L and P/L CRDMs

were designed, constructed, and analyzed to the requirements of their original equipment

specifications and ASME Code Section III. Generic ASME Code stress analyses were

performed, subject to the licensing basis design transient sets that were specified in the original

equipment specifications.

The applicant stated that the structural integrity of the F/L and P/L CRDMs was evaluated for

uprated power conditions and a 60-year operating period, using the 60-year NSSS design

parameters and the NSSS revised design transients. The fatigue analysis for the P/L CRDMs

was determined to be bounded by the fatigue analysis for the F/L CRDMs. The revised set of

NSSS design transients was compared to the transients used in the F/L CRDM equipment

specification and the associated generic code stress analysis. The equipment specification or

the generic code stress analysis values were determined to bound the revised NSSS values

except for the large step-load decrease, loss of load, loss of flow, and reactor trip transients.

The revised power uprate NSSS transient set also required consideration of feedwater cycling,

boron concentration equalization, loss of power, inadvertent actuation of auxiliary spray, steam

line break, and turbine roll tests transients, because they were not defined in the original

equipment specification for the CRDMs. The transients that were not bounded, the unewv

transients, and the additional hydrostatic test pressure transients were evaluated for their

impact on fatigue. Based on these evaluations, and the previous generic code stress analyses,

the applicant concluded that the design of the P/L and F/L CRDMs meets the applicable ASME

Code requirements at uprated NSSS power conditions for up to 60 years of operation.

The applicant also stated that the CRDMs are scheduled for replacement in the 2005 refueling

outages and are currently being manufactured. Material and design enhancements are being

incorporated into the replacement CRDMs to enhance the corrosion resistance of the CRDM

assemblies. Some of the enhancements include elimination of Alloy 600 materials, elimination

of unnecessary spare head penetrations, elimination of unnecessary joints in the CRDM

housings, and an improved penetration weld joint design. The replacement CRDMs are being

designed and manufactured to ASME Code Section 1I1, 1998 Edition through 2000 Addenda.

The design specification for the replacement CRDMs specify the same design transient set that

was used in the PUP but specified only a 40-year design-life. The applicant stated that this

design-life is considered adequate for both original and replacement components to reach the

end of the period of extended operation.

4.3.3.2 Staff Evaluation

The applicant stated that the impact of the power uprate NSSS transients on the fatigue

calculations in the generic code stress analysis associated with the Westinghouse Equipment

Specification for the CRDMs was evaluated and found to be acceptable. The applicant also

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stated that the CRDMs are scheduled for replacement during the 2005 refueling outages. The

Westinghouse design specification for the replacement CRDMs specifies the design transient

set used in the Steam Generator Replacement and the Power Uprate projects. The

replacement CRDMs are being designed to the ASME Code Section III, 1998 Edition through

2000 Addenda, with a 40-year design life. The applicant stated that a 40-year design life is

considered adequate to reach the end of the period of extended operation. The staff agreed

with the specified 40-year design life for the replacement CRDMs, since these will be installed

well past half of the current life of the two units.

The staff's review of LRA Section 4.3.3 identified an area in which additional information was

necessary to complete the review of the CRDM structural integrity evaluation. The applicant

responded to the staff's RAI as discussed below.

RAI 4.3-3. In RAI 4.3-3, dated November 17, 2004, the staff requested the applicant to provide

a comparison of the CLB set of transient conditions and design cycles, and the revised set of

full power uprate design transients.

In its response, dated January 28, 2005, the applicant referred to the two versions of LRA

Table 4.1.8, Thermal and Loading Cycles," shown on pages A-4 and A-5 in Appendix A "FSAR

Supplement." The staff found the response acceptable since the comparison of the two tables

shows a larger number of power uprate design transients and design cycles that are being used

in the replacement CRDM fatigue TLAAs.

On the basis of the above discussion, the staff agreed with the applicant's overall conclusion

that the fatigue analyses of the PBNP CRDMs will remain valid for the period of extended

operation, in accordance with the requirements of 10 CFR 54.21 (c)(1)(ii). The staff's concern

described in RAI 4.3-3 Is resolved.

4.3.3.3 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.

The applicant provided an FSAR supplement summary description of CRDM structural integrity in LRA Section Al 5.4.2. On the basis of its review, the staff concluded that the FSAR

supplement summary adequately describes the TLAA on CRDM structural integrity and, is

therefore, acceptable.

4.3.3.4 Conclusion

The staff reviewed the applicant's TLAA on control rod drive mechanism structural integrity, as

summarized in LRA Section 4.3.3, and determined that the metal fatigue assessments at

Units 1 and 2 will continue to comply with the staff's requirements throughout the period of

extended operation. The staff concluded that the applicant's TLAA for CRDM structural

integrity 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 concluded that the FSAR supplement contains an appropriate summary description of

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the TLAA on CRDM structural integrity for the period of extended operation, as required by

10 CFR 54.21(d).

4.3.4 Steam Generator Structural Integrity

4.3.4.1 Summary of Technical Information In the Application

In LRA Section 4.3.4, the applicant stated that PBNP replaced the steam generators (SGs) in

each unit. The Unit 1 SGs were replaced in 1984, and the Unit 2 SGs were replaced in 1996.

The projected number of SG design transients for a 60-year operating period were determined

to be less than the original design value for a 40-year operating period, with the exception of

hydrostatic pressure tests. The design transient set was revised to increase the number of

hydrostatic pressure test transients for the fatigue analysis performed to cover a 60-year

operating period. Both unit's SGs were designed in accordance with the requirements of the

ASME Code Section 1II. The original fatigue calculations were reanalyzed for the Units 1 and 2

SGs at specified full uprated conditions and increased pressure test load cycles adequate for a

60-year operating period. The structural evaluation concluded that the CUFs of all SG

components analyzed for fatigue are within the ASME Code Section III allowable limit of 1.0 for

a 60-year operating period, with the exception of the Unit 1 inspection port bolts. The structural

evaluation also determined a replacement interval of 12 years for these bolts. The Periodic

Surveillance and Preventive Maintenance Program, described in LRA Section B2.1.15, will

manage the Unit 1 SG inspection port bolt replacement. This bolting replacement program will

remain in place for the period of extended operation.

4.3.4.2 Staff Evaluation

The applicant stated that the SGs were replaced in Unit 1 in 1984 and in Unit 2 in 1996. For

license renewal, the fatigue TLAAs were reanalyzed at full power uprate transient conditions,

and the CUFs were determined to meet the ASME Code Section III Class 1 fatigue limit of 1.0.

The staff's review of LRA Section 4.3.4 identified areas in which additional information was

necessary to complete the review of the SG structural integrity evaluation. The applicant

responded to the staff's RAls as discussed below.

RAI 4.3.4-1. In RAI 4.3.4-1, dated November 17, 2004, the staff requested the applicant to

confirm that the limiting locations on the PBNP Westinghouse Units 1 and 2 SGs evaluated for

extended operation correspond to the components listed in NUREG-1 801, Volume 2

Table IV.D1 for PWR SGs.

In its response, dated January 28, 2005, the applicant provided a table verifying that the

applicable locations specified in NUREG-1801, Volume 2, were evaluated in the PBNP

replacement SG fatigue analyses, except for two components, which are not found in the PBNP

SGs. The staff found the applicant's response acceptable because the components that were

evaluated for fatigue correspond to the components listed in NUREG-1 801 Table IV.D1.

RAI 4.3.4-2. In RAI 4.3.4-2, dated November 17, 2004, the staff requested the applicant to:

provide clarification that the transient conditions and design cycles applicable to verify the

replacement SG fatigue TLAAs were those stated in LRA Appendix A Table 4.1.8.

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In Its response, dated January 28, 2005, the applicant confirmed that the revised set of full

power uprate transient conditions and design cycles shown in the revised LRA Appendix A

Table 4.1.8, "Thermal and Loading Cycles," were used in the fatigue analyses of the Units 1

and 2 SGs, to show conformance with the ASME Code Section III Class 1 fatigue limit of 1.0 to

the end of the period of extended operation.

RAI 4.3.4-3. In RAI 4.3.4-3, dated November 17, 2004, the staff requested the applicant to

provide a list of the key Units 1 and 2 SG components and the corresponding 60-year CUFs.

In its response, dated January 28, 2005, the applicant provided a table which included the

14 key components for both SGs. The highest CUF for the Unit 1 SG was listed as 4.65 for the

bolts of the secondary inspection ports. Since this value exceeds the ASME Code Section III

Class 1 fatigue limit of 1.0, the applicant stated that these are managed by replacement on a

periodic basis. For the other components of the Unit 1 SG, the highest CUF was below 1.0.

For the Unit 2 SG, of a different Westinghouse design, the highest CUF was listed as also

below 1.0.

The staff found these responses acceptable. It demonstrates the adequacy of the Units 1

and 2 SG fatigue TLAAs, and the commitment for periodic replacement under the Periodic

Surveillance and Preventive Maintenance Program of the secondary inspection port bolts,

where the fatigue TLAA does not meet the ASME Code Section III Class 1 fatigue limit of 1.0.

On the basis of the above discussion and its review, the staff agreed with the applicant's

conclusion that the fatigue analyses of the SGs will remain valid for the period of extended

operation, in accordance with the requirements of 10 CFR 54.21 (c)(1)(ii) and (iii). The staff's

concerns described in RAls 4.3.4-1, 4.3.4-2, and 4.3.4-3 are resolved.

4.3.4.3 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.

The applicant provided an FSAR supplement summary description of SG structural integrity in

LRA Section Al 5.4.2. On the basis of its review, the staff concluded that the FSAR supplement

summary adequately describes the TLAA on SG structural integrity and, is therefore,

acceptable.

4.3.4.4 Conclusion

The staff reviewed the applicant's TLAA on SG structural integrity, as summarized in LRA

Section 4.3.4, and determined that the metal fatigue assessments at Units 1 and 2 will continue

to comply with the staff's requirements throughout the period of extended operation. The staff

concluded that the applicant's TLAA for SG structural integrity complies with the staff's --

acceptance criterion for TLAAs in 10 CFR 54.21 (c)(1)(ii) and (iii), 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 concluded that

the FSAR supplement contains an appropriate summary description of the TLAA on SG

structural integrity for the period of extended operation, as required by 10 CFR 54.21 (d).

4-19
4.3.5 Pressurizer Structural Integrity

4.3.5.1 Summary of Technical Information In the Application

In LRA Section 4.3.5, the applicant stated that, based on operating experience and a review of

existing analyses, the Westinghouse Report WCAP-1 4574-A identified the shell, spray nozzle,

manway bolts, lower head, heater wells, surge nozzle, and support skirt and flange as

significant locations with fatigue potential for the period of extended operation.

The applicant stated that the pressurizers were designed in accordance with the requirements

of ASME Code Section III Class 1 vessels. Fatigue usage factors for critical locations in the

pressurizers were initially evaluated using design transients that were specified early in the

plant design process.

The projected number of design transients for a 60-year operating period are less than the

original design value for a 40-year operating period, with the exception of hydrostatic pressure

tests. The pressurizer fatigue calculations were reanalyzed for the uprated power conditions

with an increased number of hydrostatic pressure test-load cycles, adequate for a 60-year

operating period. The applicant stated that the plant-specific fatigue analysis results showed

that the surge nozzle, spray nozzle, and upper head and shell have the highest fatigue CUF,

but do not exceed the ASME Code Section III allowable limit of 1.0.

The applicant stated that thermal fatigue damage to the pressurizer lower head region was

being experienced on an industry-wide basis in excess of the original design allowable limit, due

to apparent insurge/outsurge transients in the pressurizer. The original design analysis

assumed that during an insurge transient, the cooler water from the hot leg entering the hotter

pressurizer would mix in the bottom head of the pressurizer. This, however, has not been the

case, and additional fatigue usage has resulted for the pressurizer components in the lower

head region. The Westinghouse Owners Group (WOG) commissioned a generic evaluation of

the effects of this unanalyzed event. As a result of this evaluation, the WOG tested and

recommended modified operating procedures (MOP) for use in all plants to minimize or

eliminate insurge/outsurge cycling. The WOG also demonstrated acceptable structural integrity

of the pressurizers for the CLB design-life of the plant based on the MOP, and recommended

plant-specific structural integrity evaluations to close the issue.

The applicant stated that PBNP implemented the recommended MOP to minimize the

possibility of pressurizer insurge/outsurge events. In addition, a plant-specific insurge/outsurge

fatigue analysis was performed to demonstrate adequate structural integrity for a projected

60-year operational period. The following locations were selected for analysis:

* pressurizer surge nozzle

* heater penetration well

* lower instrument nozzle

These locations were determined to represent the bounding fatigue locations in the lower head

region. The pressurizer surge nozzle Is subjected to thermal shock in combination with thermal

expansion piping loads, thermal stratification piping loads in the horizontal portion of the surge

line, and pressure. The pressurizer heater tube and instrument penetrations are subjected to

4-20
thermal shock and pressure. The Electric Power Research Institute (EPRI) FatiguePro

software program, part of the Fatigue Monitoring Program described in LRA Section B3.2, was

customized to monitor fatigue-critical locations in the pressurizer's lower head at PBNP. An

analysis was performed based on available real plant data to determine the incremental fatigue

usage factor for known plant transients, including the effects of insurge/outsurge. ASME Code

Section III Class 1 CUFs for the operating life of the plant were computed based on the results

of real plant data, and expected future usage was computed using projections of expected plant

cycles through the period of extended operation.

The technical approach used by the applicant is based on determining flow rates and heat

transfer rates from the incoming fluid to calculate the temperature transients in the lower head

components by using the FatiguePro program. The applicant stated that this approach has

been verified to be conservative, based on thermocouple data from another plant, as well as

plant-specific comparisons between the FatiguePro calculated water temperature and the surge

line temperature instrument reading in the region of the surge nozzle. The temperatures at the

nozzle and lower head are calculated in FatiguePro completely independently from the surge

line temperature instrurment. As part of FatiguePro, stress histories, using finite element

models of the pressurizer surge nozzle and hot leg RCS surge nozzle (including thermal

sleeves), were computed based on the calculated fluid temperatures histories. The stress

histories were used to compute fatigue usage in FatiguePro.

The applicant stated that real plant data from various heatup/cooldown cycles since 1994 were

analyzed to compute incremental fatigue usage for a heatup/cooldown cycle. The location with

the highest fatigue usage in the pressurizer bottom head was determined to be at a heater

penetration weld. However, the applicant stated that for this location, the primary stress

transient is not due to insurge and outsurge, but rather due to the general thermal expansion

stress that arises from the global heatup and cooldown of the pressurizer. This location is a

stainless steel weld to the tube and clad, very close to the low-alloy steel pressurizer shell. A

high steady-state dissimilar-metal thermal expansion stress is established during the heatup

and is relaxed during the cooldown. It is of a magnitude that overwhelms the small stress

additions coming from insurges and outsurges of fluid.

The applicant stated that historical data from actual plant heatup and cooldown cycles from

startup to 1994 was reviewed to more accurately account for early plant operation. Using this

data, and assuming projected plant heatup and cooldown cycles, the expected CUF for the

limiting (heater penetration) location was determined as significantly less than 1.0. The

analysis demonstrated acceptable structural integrity for these pressurizer locations for a

60-year projected life of the plant. The projected combined fatigue usage factors (including

insurge/outsurge) for the three bounding locations are shown in LRA Table 4.3.5-1 "Pressurizer

Lower Head Fatigue Results Including Insurge/Outsurge." The most limiting Units 1 and 2 CUF

was determined as 0.057 for a heater penetration. The applicant also stated that, for

confirmatory purposes, the Fatigue Monitoring Program will monitor fatigue usage at the

fatigue-sensitive locations during the period of extended operation.

4.3.5.2 Staff Evaluation

The applicant stated that, based on operating experience and a review of existing analyses, the

Westinghouse Report WCAP-14574-A identified the shell, spray nozzle, manway bolts, lower

4-21
head, heater wells, surge nozzle, and support skirt and flange as potential fatigue significant

locations for the period of extended operations.

The staff's review of LRA Section 4.3.5 identified areas in which additional information was

necessary to complete the review of the pressurizer structural integrity evaluation. The

applicant responded to the staff's RAls as discussed below.

RAI 4.3.5-1. In RAI 4.3.5-1, dated November 17, 2004, the staff requested the applicant to

confirm that the limiting components on the pressurizers evaluated for extended operation

correspond to the components listed in NUREG-1 801, Volume 2, Table IV.C2.5 for PWR

pressurizers. In its response, dated January 28, 2005, the applicant provided a table confirming

that the applicable components specified in NUREG-1801, Volume 2, were evaluated in the

PBNP pressurizer fatigue analyses, except for one component not within the scope of license

renewal and three components not found in the PBNP pressurizers.

The staff found this response acceptable. The components that were evaluated for fatigue

TLAAs correspond to those shown in NUREG-1 801, Volume 2, Table IV.C2.5. The staff also

found acceptable the justification for those components for which a fatigue analysis was not

performed. These components are either outside the scope of license renewal or not found in

the PBNP pressurizers. The staff's concern described in RAI 4.3.5-1 is resolved.

RAI 4.3.5-2. In RAI 4.3.5-2, dated November 17,2004, the staff requested the applicant to

provide clarification that the transient conditions and design cycles applicable to the pressurizer

fatigue TLAAs were those stated in LRA Appendix A Table 4.1.8. In its response, dated

January 28,2005, the applicant confirmed that the revised set of full power uprate transient

conditions and design cycles shown in the revised LRA Appendix A Table 4.1.8, "Thermal and

Loading Cycles," were used in the fatigue analyses of the PBNP pressurizers to show

conformance with the ASME Code Section III Class 1 fatigue limit of 1.0 to the end of the period

of extended operation.

The staff found this response acceptable; it conforms with general industry practice for

performing metal fatigue analyses. The staff's concern described in 4.3.5-2 is resolved.

RAI 4.3.5-3. In RAI 4.3.5-3, dated November 17,2004, the staff requested the applicant to

clarify whether the plant-specific insurge/outsurge fatigue analyses are based on applicable

insurge/outsurge transients in combination with the revised transients listed in LRA Appendix A

Table 4.1.8. In its response, dated January 28, 2005, the applicant indicated that only heatup

and cooldown transients, which are listed in the table, were significant in the plant-specific

fatigue analysis of the pressurizer lower head and surge line components subjected to

insurge/outsurge transients. The contribution of the other transients to the fatigue CUFs was

found to be negligible.

The applicant stated that actual insurge/outsurge transients experienced by the pressurizer

lower head and surge line components during plant heatup and cooldown were obtained from

real time plant data using the EPRI FatiguePro fatigue monitoring software installed in both

units. The software monitored the hot leg surge nozzle, the pressurizer surge nozzle, a

pressurizer heater penetration weld, and a water temperature instrument nozzle. The heater

penetration weld was determined to be the bounding location for fatigue usage. The fatigue

CUF was estimated based on the number of operational cycles projected from the present to

4-22
the end of the period of extended operation, and the number of cycles estimated to have been

experienced from the start of plant operation until the beginning of fatigue monitoring with the

Fatigue Monitoring Program. The fatigue usage calculations were also adjusted for the

maximum environmental fatigue effect by multiplying by the maximum environmental effect

factor of 15.35. The resulting environmental CUFs were determined to be less than the ASME

Code Section III Class 1 fatigue limit of 1.0, and are shown in LRA Table 4.3.10.2.

The staff found this response acceptable; it conforms with general industry practice for

performing metal fatigue analyses. The staff's concern described in RAI 4.3.5-3 is resolved.

RAI 4.3.5-4. In RAI 4.3.5-4, dated November 17, 2004, the staff requested the applicant to

provide a description of the "Modified Operating Procedures," referenced on page 4-45 of the

LRA, that were used to minimize or eliminate insurge/outsurge cycling. In its response, dated

January 28, 2005, the applicant stated that PBNP follows a "water solid' heatup-cooldown

method for both units. The modified operating procedures set a maximum allowable

temperature differential limit between the RCS hot leg and the pressurizer liquid space. This

ensures that the operation of the plant is within the temperature differential limit assumed in the

surge line thermal stratification analysis.

The staff found this response acceptable; it conforms with standard industry practice. The

staff's concern described In RAI 4.3.5-4 is resolved.

RAI 4.3.5-5. In RAI 4.3.5-5, dated November 17,2004, the staff requested the applicant to list

the key Units 1 and 2 pressurizer components that were evaluated for 60-year fatigue, and to

provide the calculated CUFs for these components. In its response, dated January 28, 2005,

the applicant provided the requested table, listing 12 key components that were evaluated for

fatigue, with the corresponding CUFs to the end of the period of extended operation. The

highest CUF reported was at the spray nozzle, and its magnitude was below the ASME Code

Section III Class 1 fatigue limit of 1.0.

Based on the discussion above, its review and the RAI response, the staff found this TLAA

acceptable. The reported CUFs are below the required ASME Code limit, and it provides a

reasonable demonstration that the fatigue TLAAs for the pressurizer, including insurge/outsurge

transients, will remain valid for the period of extended operation, in accordance with the

requirements of 10 CFR 54.21 (c)(1)(ii).

4.3.5.3 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.

The applicant provided an FSAR supplement summary description of pressurizer structural

integrity in LRA Section Al 5.4.2. On the basis of its review, the staff concluded that the FSAR

supplement summary adequately describes the TLAA on pressurizer structural integrity and, is

therefore, acceptable.

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4.3.5.4 Conclusion

The staff reviewed the applicant's TLAA on pressurizer structural integrity, as summarized in

LRA Section 4.3.5, and determined that the metal fatigue assessments at Units 1 and 2 will

continue to comply with the staff's requirements throughout the period of extended operation.

The staff concluded that the applicant's TLAA for pressurizer structural integrity 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 concluded that

the FSAR supplement contains an appropriate summary description of the TLAA on pressurizer

structural integrity for the period of extended operation, as required by 10 CFR 54.21 (d).

4.3.6 Reactor Coolant Pump Structural Integrity

4.3.6.1 Summary of Technical Information In the Application

In LRA Section 4.3.6, the applicant stated that the reactor coolant pumps (RCPs) were

designed and manufactured prior to the inclusion of pumps into the scope of ASME Code.

Therefore, the RCPs do not have a classical ASME Code Class 1 fatigue analysis. Although

the RCPs were designed and manufactured prior to the inclusion of pumps into the scope of

ASME Code, they were designed and manufactured to the intent of ASME Code

Section III, 1965 Edition. The areas of the RCP that form the reactor coolant pressure

boundary would, therefore, be subject to an ASME Code-type stress analysis. These

components are the casing, the main flange, the main flange bolts, and the thermal barrier

flange.

The main flange bolts, the main flange, and the casing were analyzed to ASME Code rules,

including a fatigue evaluation, in the Westinghouse Model 93 generic stress reports. The

thermal barrier, the seal housing, and the seal housing bolts were included in the Westinghouse

Model 93 generic stress analysis, which evaluated steady-state operating conditions and the

anticipated transient without trip (ATWT) event, an emergency condition, to ASME Code rules.

For PBNP, no transients were specified for the auxiliary nozzles for injection and cooling water,

and no analysis of these areas is contained in the generic stress reports.

The applicant stated that the main flange bolts were analyzed for fatigue and found to have a

usage factor of 0.29. The fatigue-waiver methodology was not used for these bolts. This

usage factor was calculated on the basis of 200 startup/shutdown cycles. This analysis

determined that the transient conditions other than startup/shutdown produced stresses so low

as not to contribute to the fatigue usage of the main flange bolts.

A fatigue analysis was performed for the main flange. A usage factor of 0.025 was calculated

on the basis of 200 startup/shutdown cycles. The analysis determined that the transient

conditions other than startup/shutdown produced stresses so low as not to contribute to the

fatigue usage of the main flange. This is because the thermal barrier serves to isolate the main

flange from temperature transients smaller than startup and shutdown. The pump casing was

analyzed, and the applicant concluded that the fatigue usage factor for the casing is zero.

4-24
The applicant stated that the SG replacement and power uprate evaluations evaluated the

adequacy of the RCPs for uprated power conditions for a 60-year operating period. New NSSS

transient data were created for the Power Uprate Project. The revised transient set was

reviewed against the original RCP design transients. The applicant found that generally, the

revised transient sets were bounded by the original RCP design transient sets. However, the

revised transient sets included some transients that were not included in the original RCP

design transients. These additional transients were evaluated in the justification of the

adequacy of the RCP for uprated conditions for a 60-year operating period. The revised cycle

count for a 40-year operating period was determined to also bound a 60-year operating period.

For the transients that were not bounded by the original design specification transients, the

ASME fatigue-waiver criteria were used to the justify the adequacy of the RCPs for the uprated

power conditions for a 60-year operating period. The temperature difference for a significant

temperature fluctuation per paragraph N-415.1 (d), and the pressure difference for a significant

pressure fluctuation per paragraph N-415.1 (b), were calculated by the applicant. These were

then used to demonstrate that the new or revised transients associated with the Replacement

Steam Generator Project and Power Uprate Project were not significant per the ASME Code

fatigue-waiver criteria and, therefore, do not contribute to the CUF for the RCP components.

The applicant stated that the referenced evaluations confirmed that the design of the Model 93

RCP met the applicable ASME Code requirements for structural integrity at the revised RCS

conditions associated with the uprated core power for up to a 60-year life. The analyses

associated with verifying the structural integrity of the RCPs were projected to the end of the

period of extended operation, in accordance with 10 CFR 54.21 (c)(1)(ii).

4.3.6.2 Staff Evaluation

As described above, the applicant designed the RCPs to the intent of ASME Code Section III

Class 1. These requirements contain explicit criteria for the fatigue analysis of components,

and the applicant identified the fatigue analyses of the RCP pressure boundary as TLAAs. The

staff reviewed the applicant's evaluation of the components for compliance with the provisions

of 10 CFR 54.21 (c)(1).

The specific design criterion for fatigue analysis of RCS components involves calculating the

CUF. The fatigue damage in the component caused by each thermal or pressure transient

depends on the magnitude of the stresses caused by the transient. The CUF sums the fatigue

damage resulting from each transient with the design criterion requiring that the CUF not

exceed 1.0.

The applicant classified the RCP, main flange bolts, and main flange as pressure-retaining

components subject to fatigue. In its technical information section, the applicant indicated that

fatigue usage factors were calculated for these three components and that plant transients,

including those not bounded by the original design transients, were not significant, pursuant to

the ASME Code fatigue waiver criteria, and do not contribute to the CUF for the RCP

components. The effects of fatigue on these system components are addressed under the

Fatigue Monitoring Program, which is evaluated by the staff in SER Section 3.0.3.2.22, and is

acceptable, as previously discussed.

4-25
4.3.6.3 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.

The applicant provided an FSAR supplement summary description of RCP structural integrity in

LRA Section A15.4.2. On the basis of its review, the staff concluded that the FSAR supplement

summary adequately describes the TLAA on RCP structural integrity and, is therefore,

acceptable.

4.3.6.4 Conclusion

The staff reviewed the applicant's TLAA on RCP structural integrity, as summarized in LRA

Section 4.3.6, and determined that the metal fatigue assessments at Units 1 and 2 will continue

to comply with the staff's requirements throughout the period of extended operation. The staff

concluded that the applicant's TLAA for RCP structural integrity 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 concluded that

the FSAR supplement contains an appropriate summary description of the TLAA on RCP

structural integrity for the period of extended operation, as required by 10 CFR 54.21 (d).

4.3.7 Pressurizer Surge Line Structural Integrity

4.3.7.1 Summary of Technical Information In the Application

In LRA 4.3.7, the applicant stated that detailed fatigue analyses of the pressurizer surge lines

were performed in response to NRC Bulletin 88-11, "Pressurizer Surge Line Thermal

Stratification." The analyses were performed in accordance with the requirements of ASME

Code Section IlIl. The methodology and results are presented in WCAP-13509, "Structural

Evaluation of the Point Beach Units 1 and 2 Pressurizer Surge Lines, Considering the Effects of

Thermal Stratification."

The applicant stated that the Westinghouse analysis initially developed surge line transients

from a number of sources. The transients were developed following the same general

approach originally established for the Westinghouse Owners Group. The transients from the

Westinghouse systems standard design transient set were refined through the use of

PBNP-specific and similar-plant surge line monitoring results, operational procedures, and

historical plant operational information. The transient refinements included the potential thermal

effects of thermal stratification and striping. The transient information was used as input to a

structural and stress analysis of the surge lines for the two units. The results of the analysis,

following minor hanger and pipe whip restraint modifications, showed that the ASME Code

stress limits and CUF requirements were acceptable for the remainder of the original license

period.

The applicant stated that the PBNP-specific surge line fatigue analysis was re-evaluated

considering the operational conditions associated with power uprate and a 60-year operating

period. The transient sets were reviewed for the new conditions. The majority of the transients

4-26
defined for original power levels for 40 years were found to be bounding for uprated conditions

for 60 years. Some of the feedwater transients required minor revisions due to a change In

feedwater temperatures associated with the proposed power uprate. The impact of the

changes in the revised RCS conditions, thermal design transients, and the 60-year life were

factored into determining the ASME Code stress levels and allowables for the surge line.

The results of the evaluation for the pressurizer surge line stratification showed that the power

uprate conditions changed the fatigue usage factors at the location of the highest usage factor

by a negligible amount. The calculated change in the loadings on the pressurizer nozzle due to

stratification for the power uprate conditions was not considered significant. The results of the

original evaluation for the surge line, WCAP-1 3509, remain unchanged for the 60-year

operating period.

The analysis associated with verifying the structural integrity of the pressurizer surge line piping

has been projected to the end of the period of extended operation, in accordance with

10 CFR 54.21 (c)(1 )(ii). For license renewal, continuation of the Fatigue Monitoring Program

into the period of extended operation will assure that the design cycle limits are not exceeded.

The Fatigue Monitoring Program is considered a confirmatory program and is described in LRA

Section B3.2.

4.3.7.2 Staff Evaluation

The fatigue TLAAs were performed by Westinghouse in response to the criteria of NRC

Inspection & Enforcement (I&E) Bulletin 88-11 to evaluate the structural integrity of the surge

lines due to thermal stratification transients.

The staff's review of LRA Section 4.3.7 identified an area in which additional information was

necessary to complete the review of the pressurizer surge line structural integrity evaluation.

The applicant responded to the staff's RAI as discussed below.

RAI 4.3-7. In RAI 4.3-7, dated November 17, 2004, the staff requested the applicant to provide

a comparison of the CLB set of transient conditions and design cycles and the set of full power

uprate transients that were used to evaluate the pressurizer surge line fatigue TLAAs under

power uprate conditions and to show that the fatigue TLAAs will remain valid for the period of

extended operation.

In its response, dated January 28, 2005, the applicant stated that Westinghouse had evaluated

the impact of the changes in the RCS operating conditions, thermal design transients, and

projected 60-year life on the surge line thermal stratification analyses. The evaluation showed

that the effect of the power uprate operating conditions on the surge line fatigue TLAAs

changed the CUF at the location of the limiting fatigue CUF by a negligible amount. The

applicant concluded that the results presented in the Westinghouse responses to M&E

Bulletin 88-11 remain essentially unchanged.

On this basis, the staff concluded that the fatigue TLAAs associated with power uprated

operating conditions and thermal stratification transient conditions for the pressurizer surge

lines conform with current industry license renewal practices and will remain valid to the end of

4-27
the period of extended operation, in accordance with the requirements of

10 CFR 54.21 (c)(1)(ii). The staff's concern described in RAI 4.3-7 is resolved.

4.3.7.3 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.

The applicant provided an FSAR supplement summary description of pressurizer surge line

structural integrity in LRA Section Al 5.4.2. On the basis of its review, the staff concluded that

the FSAR supplement summary adequately describes the TLAA on pressurizer surge line

structural integrity and, is therefore, acceptable.

4.3.7.4 Conclusion

The staff reviewed the applicant's TLAA on pressurizer surge line structural integrity, as

summarized in LRA Section 4.3.7, and determined that the metal fatigue assessments at

Units 1 and 2 will continue to comply with the staff's requirements throughout the period of

extended operation. The staff concluded that the applicant's TLAA for pressurizer surge line

structural integrity 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 concluded that the FSAR supplement contains an

appropriate summary description of the TLAA on pressurizer surge line structural integrity for

the period of extended operation, as required by 10 CFR 54.21(d).

4.3.8 Pressurizer Spray Header Piping Structural Integrity

4.3.8.1 Summary of Technical Information In the Application

In LRA Section 4.3.8, the applicant stated that the piping connections to the RCS were

evaluated in response to NRC Bulletin 88-08 (including Supplements 1 through 3) "Thermal

Stresses in Piping Connected to Reactor Coolant Systems." Two unisolable piping connections

were identified that have the potential to be subjected to thermal stratification or temperature

oscillations. These lines are the auxiliary charging connection and the auxiliary spray

connection. The applicant inspected these lines with surface and volumetric inspection

techniques to identify the presence of service-related degradation. No service-related

degradation was discovered by the applicant.

These lines were also subject to temperature monitoring to identify and quantify thermal

stratification. No thermal stratification was noted on the auxiliary charging lines. Thermal

stratification was noted on one of the auxiliary spray lines, where it ties into the spray header.

To evaluate the effect of thermal stratification on the pressurizer spray line header, including

the auxiliary spray line connection, fatigue analyses were performed for each unit's applicable

piping system. The analyses were based on actual piping surface temperature data obtained

during a 153-day period (including one startup) of direct temperature monitoring on the Unit 2

piping. The Unit 2 data were considered applicable and bounding for both units since Unit 2

experienced more stratification, and the line configuration was similar in both units.

4-28
The applicant stated that the piping transient set was developed by expanding the measured

piping thermal behavior to equate to a 40-year operating period. The analyses showed that the

limiting CUFs in the subject piping were 0.66 for Unit 1 and 0.33 for Unit 2. Extrapolating the

results of the original NRC Bulletin 88-08 analyses to a 60-year operating period resulted in

CUFs of 0.99 for the Unit 1 piping system, and 0.60 for the Unit 2 piping system.

In view of the lack of margin with the Unit 1 piping system analysis result for the extended EOL,

additional analysis investigations were pursued by the applicant. The original NRC Bulletin

88-08 analyses incorporated simplified analysis techniques and assumptions. The applicant

concluded that it was not clear that the analysis was in fact conservative. Therefore, the NRC

Bulletin 88-08 fatigue analyses were re-performed with refined analysis techniques and

assumptions, using the original temperature monitoring data. The reanalysis resulted in a

60-year CUF of 0.277 for the limiting Unit 1 piping system location.

The applicant stated that the analyses verifying the structural integrity of the pressurizer

auxiliary spray line and spray header, were projected to the end of the period of extended

operation, in accordance with 10 CFR 54.21 (c)(1)(ii).

4.3.8.2 Staff Evaluation

The fatigue TLAAs were performed in response to the criteria of NRC ME Bulletin 88-08 to

evaluate the structural integrity of unisolable lines connected to the RCS, subject to thermal

stratification transients resulting from leaking isolation valves.

The staff's review of LRA Section 4.3.8 identified an area in which additional information was

necessary to complete the review of the pressurizer spray header piping structural integrity

evaluation. The applicant responded to the staff's RAI as discussed below.

RAI 4.3-8. The applicant stated that the highest 40-year CUF for the pressurizer spray line

headers in both units, including the auxiliary spray line connections, was calculated as 0.66.

The projected highest CUF value for 60-year operation was, therefore, below 1.0. Although this

value was below the ASME Code Section III Class 1 limit, the applicant determined that the

original calculation may not have been conservative. In view of the small margin in the

projected CUF value, the applicant therefore, calculated a 60-year CUF using refined fatigue analysis techniques and assumptions, and determined a CUF value of 0.277.

In RAI 4.3-8, dated November 17, 2004, the staff requested the applicant to provide a detailed

description of the refined fatigue analysis techniques and assumptions used to deterrrine the

60-year CUF. i1 I

In its response, dated January 28, 2005, the applicant stated that in the oriin'l . r spoi'ise t I 

NRC l&E Bulletin 88-08, the thermal stratification stresses were estimated implfji" u hnd

calculations. These calculations contained estimates of global moments, ahc, radiaj as"Eiai

stresses. A review of the assumptions made in these simplified calculations Enditedpat'they

may have been non-conservative. The correct thermal stratification stresses were therefore,

calculated using a commercial finite-element analysis computer program which has the

capability to calculate non-axisymmetric transient thermal and stress distributions in pipe walls,

as well as global bending moments and stresses.

4-29
Input to this analysis consisted of thermal stratification data collected over a 153-day period

from thermocouples installed on the auxiliary spray lines as part of the requirements of l&E

Bulletin 88-08 to monitor the thermal stratification transients in these lines. These

thermocouples recorded stratified thermal conditions resulting from a leaking auxiliary spray

isolation valve. The applicant reviewed the thermocouple data in detail and extrapolated this

data to a 60-year plant life, assuming that the same amount of valve leakage and thermal

stratification continued to exist to the end of plant extended operation. The 60-year fatigue

usage was computed at the limiting location of the auxiliary spray line using a method shown in

ASME Code Section III, Subsection NC for Class 2 piping, based on thermal expansion and

thermal stratification stress ranges.

The staff reviewed the methodology and procedures described in the applicant's response and

found them acceptable; they conform with commonly accepted industry practice. The staff's

concern described in RAI 4.3-8 is resolved.

The staff reviewed Section 4.3.8 and the applicant's response to the RAI and found it

acceptable; it conforms with current industry license renewal practice. On this basis the staff

concluded that the fatigue TLAAs associated with power uprated operating conditions and the

thermal stratification transient conditions for the pressurizer spray header lines associated with

l&E Bulletin 88-08, will remain valid to the end of the period of extended operation, in

accordance with the requirements of 10 CFR 54.21 (c)(1 )(ii).

4.3.8.3 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.

The applicant provided an FSAR supplement summary description of pressurizer spray header

piping structural integrity in LRA Section Al 5.4.2. On the basis of its review, the staff

concluded that the FSAR supplement summary adequately describes the TLAA on pressurizer

spray header piping structural integrity and, is therefore, acceptable.

4.3.8.4 Conclusion

The staff reviewed the applicant's TLAA on pressurizer spray header piping structural integrity,

as summarized in LRA Section 4.3.8, and determined that the metal fatigue assessments at

Units 1 and 2 will continue to comply with the staff's requirements throughout the period of

extended operation. The staff concluded that the applicant's TLAA for pressurizer spray header

piping structural integrity 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 concluded that the FSAR supplement contains an

appropriate summary description of the TLAA on pressurizer spray header piping structural

integrity for the period of extended operation, as required by 10 CFR 54.21 (d).

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4.3.9 USAS B31.1 Piping Structural Integrity

4.3.9.1 Summary of Technical Information In the Application

In LRA Section 4.3.9, the applicant stated that piping and associated pressure boundary

components were originally designed to the requirements of USAS B31.1, "USA Standard Code

for Pressure Piping." The B31.1 Code requirements assume a stress range reduction factor to

provide conservatism in the piping design to account for the effects of thermal fatigue due to

thermal cycling during operation. This reduction factor is 1.0, provided that the number of

anticipated cycles is limited to 7000 equivalent full-temperature cycles. This represents a

condition in which a piping system would have to be thermally cycled approximately once every

three days over the extended plant life of 60 years.

Considering this limit, the applicant stated that a review of the piping and associated pressure

boundary components included within the scope of license renewal was performed to identify

those systems that operate at elevated temperature and to establish their cyclic operating

practices. Under current plant operating practices, piping and associated pressure boundary

components are occasionally subjected to cyclic operation. Typically, piping and associated

pressure boundary components are subjected to continuous steady-state operation and

operating temperatures, and only vary during plant heatup and cooldown, during plant

transients, or during periodic testing. Therefore, the applicant stated that it is very unlikely for

any piping system subject to thermal fatigue, that the actual number of thermal cycles would

approach the assumed B31.1 limit of 7000 cycles during the period of extended operation

except for the primary sampling system lines.

Establishing sample flow from the RCS results in thermal transients and cyclic stresses

whenever the RCS is above ambient temperatures. The hot leg sample line receives the

highest number of thermal cycles of all piping. An evaluation of the number of thermal cycles

that the hot leg sample line would be expected to experience over a 60-year period of operation

was performed. The applicant stated that its evaluation demonstrated that the hot leg sample

line will not exceed 7000 thermal cycles over a 60-year operating period. Therefore, no piping

and associated pressure boundary components are expected to exceed 7000 thermal cycles

over a 60-year operating period, and will remain within the bounds of their original design code.

4.3.9.2 Staff Evaluation

This piping and associated pressure boundary components at PBNP were originally designed to

the requirements of the USAS B31.1, 1967 Edition, "Power Piping Code," with the exception'of

the RCS piping and components which were designed to the requirements of the 1955 Edition.

The USAS 831.1, 1967 Edition, Code requirements assume stress range reduction factors in

the piping design to account for the effects of fatigue due to thermal cycling during plant

operation. For anticipated thermal cycles equivalent to 7000 equivalent full-temperaturp cycles

or less, the stress range reduction factor is 1.0. This represents a condition in which a piping

system would have to be thermally cycled approximately once every 3 days over the extended

plant life of 60 years. I

The applicant reviewed the piping and associated pressure boundary components within the I

scope of license renewal to identify those systems that operate at elevated temperature and to

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establish their cyclic operating practices, considering the 7000-cycle limit. Based on this

review, the applicant concluded that no piping and associated pressure boundary components

are expected to exceed 7000 thermal cycles, including cycling occurring under full power uprate

conditions, over a 60-year operating period and, will therefore, remain within the bounds of their

original design code.

Based on current industry practice and experience and the applicant's compliance with the

acceptance criteria in NUREG-1 800, the staff agreed with the applicant's assessment that, for

any PBNP piping system designed to USAS B31.1, 1967 Edition, with the exception of the RCS

piping and components designed to the requirements of the 1955 Edition, it is highly unlikely

that the 7000-cycle limit will be exceeded for the 60-year life of the plant.

On the basis of its review, the staff concluded that the fatigue analyses of the PBNP piping

designed to the USAS B31.1 Power Piping Code were determined to remain valid for the period

of extended operation, in accordance with the requirements of 10 CFR 54.21 (c)(1)(i).

4.3.9.3 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.

The applicant provided an FSAR supplement summary description of USAS B31.1 piping

structural integrity in LRA Section Al 5.4.2. On the basis of its review, the staff concluded that

the FSAR supplement summary adequately describes the TLAA on USAS B31.1 piping

structural integrity and, is therefore, acceptable.

4.3.9.4 Conclusion

The staff reviewed the applicant's TLAA on USAS B31.1 piping structural integrity, as

summarized in LRA Section 4.3.9, and determined that the metal fatigue assessments at

Units I and 2 will continue to comply with the staff's requirements throughout the period of

extended operation. The staff concluded that the applicant's TLAA for USAS B31.1 piping

structural integrity complies with the staff's acceptance criterion for TLAAs 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 concluded that the FSAR supplement contains an

appropriate summary description of the TLAA on USAS B31.1 piping structural integrity for the

period of extended operation, as required by 10 CFR 54.21(d).

4.3.10 Environmental Effects on Fatigue

4.3.10.1 Summary of Technical Information In the Application

In the December 1999 closure of GSI-1 90, the staff concluded that environmental effects have

a negligible impact on core damage frequency, and as such, no generic regulatory action was

required. However, as part of the closure, the staff concluded that licensees who apply for

license renewal should address the effects of reactor coolant environment on component

fatigue life as part of their aging management programs. In LRA Section 4.3.10, the applicant

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addressed the potential effects of reactor water environments on RCS component fatigue life to

determine if any aging management program actions are required during the period of

extended operation.

In NUREG/CR-6260 "Application of NUREG/CR-5999 Interim Fatigue Curves to Selected

Nuclear Power Plant Components," the Idaho National Engineering Laboratories (INEL)

evaluated fatigue-sensitive component locations at plants designed by all four U.S. NSSS

vendors. The applicant stated that the pressurized water reactor calculations, especially the

early-vintage Westinghouse calculations, are directly relevant to PBNP. In addition, the

transient cycles considered in the evaluation match or bound the PBNP design. The

fatigue-sensitive component locations chosen in NUREG/CR-6260 for the early-vintage

Westinghouse plant were:

* reactor vessel shell and lower head

* reactor vessel inlet and outlet nozzles

* pressurizer surge line (including the pressurizer and hot leg nozzles)

* reactor coolant system piping charging system nozzle

* reactor coolant system piping safety injection nozzle

* residual heat removal system class 1 piping

For the latter three component locations, INEL performed representative design-basis fatigue

calculations, because early-vintage Westinghouse plants, including PBNP, utilized USAS B31.1

design methodology for the majority of the Class 1 piping. NUREG/CR-6260 calculated the

fatigue usage factors for these locations using the interim environmental fatigue curves

provided in NUREG/CR-5999.

For license renewal, the applicant stated that environmental fatigue calculations were

performed for those component locations included in NUREG/CR-6260, using the Fen

methodology contained in NUREG/CR-6583 for carbon/low-alloy steel material, and

NUREG/CR-5704 for stainless steel material. The results are summarized below.

Reactor Pressure Vessel Locations. The applicant stated that the existing CUFs for the reactor

vessel locations, calculated from fatigue analyses based on a full transient set at uprated

conditions, were unaffected by environmental effects. The highest CUF was determined as

0.731 at the core support pad attachment to vessel shell location, which is lower than the ASME

Code Section III limiting value of 1.0 and, therefore, the applicant concluded that it was

acceptable.

Surge Line Locations. Since the PBNP pressurizer surge lines were designed and constructed

to USAS B31.1, 1955 Edition, no specific fatigue analysis was performed for this piping.

However, detailed structural and fatigue analyses were subsequently performed in response to

NRC l&E Bulletin 88-11, "Pressurizer Surge Line Thermal Stratification." These evaluations

were performed to the requirements of ASME Code Section III and were based on a 40-year

design transient set, which also included the effects of thermal stratification. The summary

results of these specific analyses were presented in Westinghouse WCAP-13509, "Structural

Evaluation of the Point Beach Units 1 and 2 Pressurizer Surge Lines, Considering the Effects of

Thermal Stratification."

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The highest CUF of 0.99 was calculated at a welded attachment for a whip restraint on the

outside surface of the middle section of the Unit 1 surge line. However, this surface of the pipe

is not exposed to reactor coolant and consideration of environmental conditions, therefore, do

not apply. The fatigue usage at this location was accumulated during the period when the

piping support configuration allowed binding of the pipe within the restraint system. The

restraint was modified to prevent future binding and, therefore, the applicant concluded that no

further fatigue accumulation is expected to occur at this location.

The next highest CUF for Unit 1, and the highest CUF for Unit 2, occurred at the reducer below

the pressurizer surge nozzle. The CUF is 0.7. An environmental fatigue multiplier of 15.35 for

austenitic stainless steel was applied to the fatigue calculation result. The resulting f

environmental CUF for this location was calculated as 10.75. The environmental effects on

fatigue were therefore, evaluated using actual monitored and projected fatigue data obtained

with the EPRI FatiguePro software program. An analysis was performed and CUFs for the

operating life of the plant were computed based on this data to determine the incremental CUF

for known plant transients, including the effects of insurge/outsurge and environmental effects.

The analysis showed that the environmental CUF was below 1.0 for a 60-year operating life.

The pressurizer surge line location subject to NUREG/CR-6260 analysis is the hot leg surge

line nozzle. The evaluation at this location yielded an environmentally adjusted CUF of 0.588.

USAS B31.1 Locations. The applicant stated that, as with the older vintage Westinghouse

plants evaluated in NUREG/CR-6260, detailed ASME Code fatigue usage calculations did not

exist for the RHR tee, charging nozzle, and safety injection (accumulator) nozzle, because the

design basis for the piping is USAS B31.1, which does not require specific fatigue analysis.

The design inputs for PBNP were compared to those summarized in NUREG/CR-6260 for

these three components. The charging nozzle and safety injection nozzle were determined to

be identical in terms of materials and geometry as those presented in NUREG/CR-6260. The

RHR tee is identical in terms of material, but is larger than the RHR tee analyzed in

NUREG/CR-6260.

PBNP-specific simplified ASME Code Section III fatigue analyses were performed on the

subject locations to ensure that bounding fatigue information was used in the environmental

effects on fatigue evaluation. For the RHR tee, where it ties into the accumulator injection line,

the environmental fatigue CUF was calculated as 0.22, using a bounding environmental fatigue

multiplier of 15.35 for austenitic stainless steel. For the safety injection (accumulator) nozzle,

where the safety injection (accumulator) line ties into the RCS main loop piping, the resulting

environmental CUF was calculated as 0.02, also based on a bounding environmental fatigue

multiplier of 15.35 for austenitic stainless steel. For the CVCS normal charging nozzle, where

the CVCS charging line ties into RCS main loop piping, the resulting environmental CUF was

calculated as 0.83, based on an effective environmental fatigue multiplier of 6.99 calculated for

this location.

Pressurizer. The applicant stated that, in addition to the NUREG/CR-6260 locations, the

pressurizers were also evaluated for the effects of RCS environment on fatigue, including

insurge/outsurge transients, in accordance with Applicant Action Item 3.3.1.1-1 of the

pressurizer Westinghouse Generic Technical Report, WCAP-1 4574-A.

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The CUFs of the pressurizers were recalculated for environmental effects on fatigue using the

design transients and loads for the RSG/PUP. The calculation re-evaluated the CUFs at the

following locations:

* spray nozzle * safety and relief nozzle

* surge nozzle * instrument nozzle

* junction of the * heater well

upper head and shell

The applicant applied the methods of Appendix B of EPRI Report TR-1 003083, "Materials

Reliability Program Guidelines for Addressing Fatigue Environmental Effects in a License

Renewal Application (MRP-47)," October 2001, for performing the environmental effects

evaluations of the CUFs of these pressurizer components. The calculated CUFs for these

components are listed below:

* spray nozzle 3.2814 * safety and relief nozzle 0.1483

* surge nozzle 2.3252 * instrument nozzle 0.6293

* junction of the 0.7737 * heater well 0.2739

upper head and shell

Since the evaluation, based on the design transient set, did not result in acceptable

environmental CUFs for the surge and spray nozzles, the applicant reviewed the transients and

transient pairs for specific contributions to the calculation of these CUFs. The review indicated

that significant reductions in the CUFs are possible if adjustments are made to remove

operational transients that are not experienced or practiced at PBNP. In addition, the EPRI

FatiguePro software program was customized to monitor fatigue-critical locations in the

pressurizers spray nozzle and lower head components. Based on real plant data and projected

plant transients and cycles, including the effects of insurge/outsurge, the applicant recalculated

the environmental CUFs for the operating life of the plant, and demonstrated that the CUFs at

the spray and surge nozzles were reduced to below 1.0.

The environmental fatigue evaluation of the pressurizer's lower head components, pressurizer

spray nozzle, including insurge/outsurge, was also performed using the EPRI FatiguePro

software program to demonstrate adequate structural integrity for a projected 60-year

operational period. Environmental CUFs were conservatively determined by applying the

maximum environmental fatigue correction factor of 15.35 at the affected component locations.

On this basis, the applicant concluded that the results of the environmental fatigue evaluation

coupled with the EPRI FatiguePro real data indicated that the pressurizer subcomponents have

acceptable environmentally-adjusted CUF values, less than the allowable value of 1.0.

4.3.10.2 Staff Evaluation

Generic Safety Issue (GSI)-1 66, uAdequacy of the Fatigue Life of Metal Components," raised

concerns regarding the conservatism of the fatigue curves used in the design of the RCS

components. Although GSI-1 66 was resolved for the current 40-year design life of operating

components, the staff identified GSI-1 90, "Fatigue Evaluation of Metal Components for 60-year

4-35
Plant Life," to address license renewal. The NRC closed GSI-1 90 in December 1999,

concluding that:

The results of the probabilistic analyses, along with the sensitivity studies performed, the

iterations with industry (NEI and EPRI), and the different approaches available to the

licensees to manage the effects of aging, lead to the conclusion that no generic

regulatory action is required, and that GSI-1 90 is closed. This conclusion is based

primarily on the negligible calculated increases in core damage frequency in going from

40- to 60-year lives. However, the calculations supporting resolution of this issue, which

included consideration of environmental effects, and the nature of age-related

degradation indicate the potential for an increase in the frequency of pipe breaks as

plants continue to operate. Thus, the staff concludes that, consistent with existing

requirements in 10 CFR 54.21, licensees should address the effects of coolant

environment on component fatigue life as aging management programs are formulated

in support of license renewal.

The staff's review of LRA Section 4.3.10 identified areas in which additional information was

necessary to complete the review of the environmental effects on fatigue evaluation. The

applicant responded to the staff's RAls as discussed below.

In LRA Section 4.3.10, the applicant evaluated the component locations listed in

NUREG/CR-6260 that are applicable to an older-vintage Westinghouse plant for the effect of

the environment on the fatigue life of the components. The applicant stated that for each

location, detailed environmental fatigue calculations were performed using the appropriate Fen

relationships from NUREG/CR-6583, "Effects of LWR Coolant Environments on Fatigue Design

Curves of Carbon and Low-Alloy Steels," for carbon and alloy steels, and from

NUREG/CR-5704, -Effects of LWR Coolant Environments on Fatigue on Fatigue Design

Curves of Austenitic Stainless Steels," for stainless steel, as appropriate for the material. The

fatigue analyses were based on the transient set under full uprated conditions and the period of

extended operation. For those components that were designed to USAS B31.1, 1967 Edition,

the applicant calculated the environmental CUFs based on a simplified ASME Code Section III

fatigue analysis. The calculations showed that for the locations corresponding to those listed in

NUREG/CR-6260, none of the environmental fatigue CUFs exceeded the ASME Code

Section III Class 1 fatigue limit of 1.0 for the period of extended operation.

RAI 4.3.10-1. In RAI 4.3.10-1, dated November 17, 2004, the staff requested the applicant to

provide a description of the simplified ASME Code Section III fatigue analysis used to calculate

cumulative usage factors.

In its response, dated January 28, 2005, the applicant stated that the analysis of the charging

nozzle was based on bounding thermal transients obtained from actual plant data using an

application of the EPRI FatiguePro software and the projected number of occurrences. The

bounding event was determined to be the loss of charging and loss of letdown event with

delayed return to service. The fatigue usage was calculated for one occurrence and multiplied

by the expected number of occurrences for 60-year operation. An Fen factor was then applied

to the calculated fatigue usage'to determine the environmental fatigue CUF. This CUF was

determined to be below the ASME Code Section III Class 1 fatigue limit of 1.0. The safety

injection nozzle and the RHR tee were analyzed using design transients and design cycles in a

plant-specific ASME Code Section III Class 1 fatigue analysis of the safety injection system and

4-36
the RHR system. The 60-year environmental fatigue CUFs were determined to be well below

the ASME Code Section III Class 1 fatigue limit of 1.0.

The applicant also determined the environmental effects on the fatigue CUFs for key

pressurizer components. The environmental fatigue CUFs at the spray nozzle and the surge

nozzle were found to exceed the ASME Code Section III Class 1 fatigue limit of 1.0. The

fatigue analyses of these components were revised based on an evaluation of the actual

thermal transients experienced by these components, projected for 60-year operation. This

evaluation eliminated operational design transients from the fatigue calculations that do not

apply to the pressurizers. On this basis, the applicant showed that the environmental fatigue

CUFs were reduced below the ASME Code Section III Class 1 fatigue limit of 1.0.

The staff reviewed this procedure and found it acceptable. It conforms with current industry

practice and the NRC approach for calculating environmental effects on fatigue. The staff's

concern described in RAI 4.3.10-1 is resolved.

RAI 4.3.10-2. The applicant's evaluation for environmental effects on fatigue was based on the

environmental fatigue approach in EPRI MRP-47 methodology. The staff has not endorsed this

approach. In RAI 4.3.10-2, dated November 17, 2004, the staff requested the applicant to

provide the environmental fatigue CUFs based on the NRC methodology stated in

NUREG-1 800 Sections 4.3.2.2 and 4.3.3.2. These sections indicate that the environmental

effects on fatigue may be determined based on NUREG/CR-6583 for carbon and low-alloy

steels, and NUREG/CR-5704 for austenitic stainless steels. The staff methodology and the

EPRI methodology are similar, except for a so-called UZ7 factor, which acts to reduce the

calculated EPRI-based F*n factors.

In its response, dated January 28,2005, the applicant revised the environmental fatigue

calculations with Fen factors based on the NUREG reports, and determined that the

environmental 60-year CUF at the carbon/low-alloy steel junction of the upper head and shell

would exceed the ASME Code Section III Class 1 fatigue limit. A 60-year environmental CUF

was therefore, recalculated using real plant data obtained by using the FatiguePro fatigue

monitoring software at this location, and reduced below the ASME Code Section III Class 1

fatigue limit of 1.0.

The staff evaluated the appiicant's response and found it acceptable. It conforms with the staff

position on environmental effects on fatigue. The staff's concern described in RAI 4.3.10-2 is

resolved.

On the basis of its review, the staff found that the environmental fatigue TLAAs of components

listed in NUREG/CR 6260 for early-vintage Westinghouse plants and the pressurizer will remain

valid to the end of the period of extended operation, in accordance with the requirements of

10 CFR 54.21 (c)(1)(ii).

4.3.10.3 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

4-37
aging and the evaluation of time-limited aging analyses for the period of extended operation.

The applicant provided an FSAR supplement summary description of environmental effects on

fatigue in LRA Section Al 5.4.2. On the basis of its review, the staff concluded that the FSAR

supplement summary adequately describes the TLAA on environmental effects on fatigue and,

is therefore, acceptable.

4.3.10.4 Conclusion

The staff reviewed the applicant's TLAA on environmental effects on fatigue, as summarized in

LRA Section 4.3.10, and determined that the metal fatigue assessments at Units 1 and 2 will

continue to comply with the staff's requirements throughout the period of extended operation.

The staff concluded that the applicant's TLAA for environmental effects on fatigue 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 concluded that

the FSAR supplement contains an appropriate summary description of the TLAA on

environmental effects on fatigue for the period of extended operation, as required by

10 CFR 54.21(d).

4.3.11 Containment Liner Plate Fatigue Analysis

4.3.11.1 Summary of Technical Information In the Application

In LRA Section 4.3.11, the applicant stated that the interior of each containment is lined with a

welded steel plate liner which provides an essentially leak-tight barrier. Design criteria are

applied to the liner to assure that the specified allowed leak rate is not exceeded under

design-basis accident conditions. The following fatigue loads, as described in FSAR

Section 5.1, were considered in the design of the liner plate and are considered a TLAA for the

purposes of license renewal:

(1) Thermal cycling due to annual outdoor temperature variations. The number of cycles for

this loading is 40 for the plant life of 40 years.

(2) Thermal cycling due to containment interior temperature varying during the startup and

shutdown of the reactor system. The number of cycles for this loading is assumed to be

500.

(3) Thermal cycling due to the design-basis accident is assumed to be one cycle.

(4) Thermal cycling due to the high-temperature piping systems passing through the

penetrations. These systems are partially isolated from the liner plate penetrations by

concentric sleeves between the pipe and the liner plate. The attachment sleeves are

designed in accordance with ASME Code Section IlIl. All penetrations were reviewed for

a conservative number of cycles to be expected during the life of the plant.

Each of the above items has been evaluated for the period of extended operation.

For item (1), the number of thermal cycles due to annual outdoor temperature variations was

increased from 40 to 60 for the period of extended operation. The effect of this increase is

insignificant in comparison to the assumed 500 thermal cycles due to containment interior-,

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temperature varying during heatup and cooldown of the RCS. The 500 thermal cycles includes

a margin of 300 thermal cycles above the 200 RCS allowable design heatup and cooldown

cycles, which is sufficient to accommodate the additional 20 cycles of annual outdoor

temperature variation. Therefore, the applicant concluded that this loading condition is

considered valid for the period of extended operation as it is enveloped by item (2).

For item (2), the assumed 500 thermal cycle loading was evaluated based on the more limiting

heatup and cooldown design cycles (transients) for the major components of the RCS. The

major components of the RCS were designed to withstand 200 heatup and cooldown thermal

cycles. The originally projected number of maximum RCS design cycles envelops the projected

cycles for the period of extended operation. The actual number of RCS transients is also

monitored to confirm that the system design transients are not exceeded. Transient monitoring

was described in LRA Section B3.2, Fatigue Monitoring Program. Therefore, the applicant

concluded that the original containment liner plate fatigue analysis for 500 heatup and cooldown

cycles is considered valid for the period of extended operation.

For item (3), the assumed value for thermal cycling due to the maximum hypothetical accident

remains valid. No maximum hypothetical accident occurred and none is expected; therefore,

this assumption is considered valid for the period of extended operation.

For item (4), the applicant stated that design of the containment penetrations has been

reviewed. The liner plate (including penetration extension sleeves) incorporated the design

guidance of ASME Code Section III, 1965 Edition, Article 4, paragraphs N-412(m), N-414.5,

N-412(n), and N-41 5.1; Figures N-414, and N-415(A); and Table N-413. The containment

penetrations also conform to the applicable sections of ASA N6.2-1965, "Safety Standard for

the Design, Fabrication, and Maintenance of Steel Containment Structures for Stationary

Nuclear Power Reactors." The containment penetration head fittings were designed,

fabricated, inspected, and tested in accordance with ASME Code Section 1II, Class B, 1968

Edition and all Addenda. The main steam, feedwater, blowdown, and letdown systems are the

only piping systems penetrating the containment that could contribute significant thermal

loading on the liner plate. Due to the higher operating temperature, the main steam piping

penetrations were considered bounding and, therefore, evaluated through the period of

extended operation. ASME Code, Section III, 1965, paragraph N-415.1, states that a fatigue

analysis is not required, provided the service loading of the vessel or component meets six

specified conditions. For the penetration sleeves and the sleeve end-fittings connecting the

pressure piping to the sleeves, analyses were performed which verified that all six conditions of

paragraph N-415.1 are met for the period of extended operation.

4.3.11.2 Staff Evaluation

Containment liner plates and penetrations were evaluated for (1) thermal cycling due to annual

outdoor temperature variations at one cycle per year, (2) 500 assumed cycles of thermal cycling

due to containment interior temperature varying during the startup and shutdown of the reactor

system, (3) thermal cycling due to a design-basis accident which is assumed to be one cycle,

(4) and thermal cycling due to the high temperature piping systems passing through the

penetrations. The applicant stated that these systems are partially isolated from the liner plate

penetrations by concentric sleeves between the pipe and the liner plate. The attachment

sleeves are designed in accordance with ASME Code Section III, 1965 Edition. All penetrations

4-39
were reviewed for a conservative number of cycles to be expected during the life of the plant.

Each item was evaluated for the period of extended operation.

On the basis of its review, the staff found that the applicant had demonstrated that the fatigue

TLAAs associated with the Units 1 and 2 containment liner plate and penetrations will remain

valid for the period of extended operation, in accordance with the requirements of

10 CFR 54.21 (c)(1 )(i).

4.3.11.3 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.

The applicant provided an FSAR supplement summary description of containment liner plate

fatigue analysis in LRA Section Al 5.4.2. On the basis of its review, the staff concluded that the

FSAR supplement summary adequately describes the TLAA on containment liner plate fatigue

analysis and, is therefore, acceptable.

4.3.11.4 Conclusion

The staff reviewed the applicant's TLAA on containment liner plate fatigue analysis, as

summarized in LRA Section 4.3.11, and determined that the metal fatigue assessments at

Units 1 and 2 will continue to comply with the staff's requirements throughout the period of

extended operation. The staff concluded that the applicant's TLAA for containment liner plate

fatigue analysis complies with the staff's acceptance criterion for TLAAs 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 concluded that the FSAR supplement contains an

appropriate summary description of the TLAA on containment liner plate fatigue analysis for the

period of extended operation, as required by 10 CFR 54.21 (d).

4.3.12 Spent Fuel Pool Liner Fatigue Analysis

4.3.12.1 Summary of Technical Information In the Application

The applicant stated that the surfaces of the spent fuel pool, fuel transfer canals, and refueling

cavities are lined with stainless steel sheet material. The liner provides a leak-tight barrier for

spent fuel storage and fuel transfer operations, and consists of stainless steel sheets welded to

a system of embedments in the reinforced concrete structures. These concrete structures and

the liner are seismically designed. The liner serves no structural function; therefore, fatigue

was not a design consideration. On this basis, the applicant concluded that fatigue is not a

TLAA for the spent fuel pool liner.

4.3.12.2 Staff Evaluation

The applicant stated that the liner of the spent fuel pool serves no structural function. Metal

fatigue was, therefore, not a design consideration. Therefore, the applicant concluded that

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fatigue is not a TLAA for the spent fuel pool liner. The staff agreed that spent fuel pool liner

fatigue is not identified as a TLAA, in accordance with the definitions in 10 CFR 54.3.

4.3.12.3 FSAR Supplement

Spent fuel pool liner fatigue is not identified as a TLAA, therefore, an FSAR supplement is not

required.

4.3.12.4 Conclusion

Because the liner of the spent fuel pool serves no structural function, and metal fatigue was not

a design consideration, the staff concluded that the spent fuel liner is not identified as a TLAA in

accordance with the definitions in 10 CFR 54.3.

4.3.13 Crane Load Cycle Limit

4.3.13.1 Summary of Technical Information in the Application

The following cranes are included in license renewal scope and in NUREG-0612: containment

polar cranes, auxiliary building crane, and turbine hall crane. The load cycle limit for PBNP

cranes was identified as a TLAA.

All PBNP cranes were designed and constructed to meet the requirements -of Specification 61

of the Electric Overhead Crane Institute (EOCI-61). EOCI-61 did not require a specific fatigue

analysis. As such, there are no specific fatigue analyses for PBNP cranes.

The containment polar cranes and the turbine hall crane are used primarily during refueling

outages. The PBNP primary auxiliary building (PAB) crane is used primarily in support of

material receipt, spent fuel cask transfers, and radwaste cask transfers. Occasionally, these

cranes make lifts at, or near, their rated capacity; however, the majority of the crane lifts are

substantially less than their rated capacity. Based on conservative usage assumptions, the

above-listed cranes are expected to make 50,000 partial load lifts and less than 5,000 at, or

near, rated load lifts over a 60-year operating period. This is significantly less than the Crane

Manufacturers Association of America, Specification 70 (CMAA-70) design cycle limit for

Class "A' service cranes.

The specifications for the traveling cranes included rated overload cycle limits of roughly two

125 percent rated load lifts per year, and three 150 percent rated load lifts in the cranes',

lifetime. With the exception of the containment polar cranes, no lifts in excess of the rated load

were made. Each containment polar crane was used to support its respective unit's Steam

Generator Replacement Project. These lifts, related to the containment polar cranes, were

specifically analyzed and engineered taking into consideration the replacement trolleys, bridge

strengthening, and temporary center poles to ensure that the original design capabilities of the

cranes were not degraded. Therefore, since the major cranes are not used to make routine

over-rated load lifts, and since special one-time over-rated load maintenance lifts are addressed

as specific engineered lifts, the applicant concluded that the original specified cycle limits for

over-rated load lifts will not be exceeded during the extended period of operation.

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4.3.13.2 Staff Evaluation

The staff's review of LRA Section 4.3.13 identified an area in which additional information was

necessary to complete the review of the crane load cycle limit evaluation. The applicant

responded to the staff's RAI as discussed below.

RAI 4.3.13-1. LRA Section 4.3.13 states that the load limits of the containment polar, auxiliary

building, and turbine hall cranes are designed in accordance with CMAA-70 Class "A" service

for 20,000 to 200,000 load cycles; and based on conservative usage assumptions, the cranes

are expected to make 50,000 partial load lifts and less than 5,000 at, or near, rated load lifts for

the period of extended operation. In RAI 4.3.13-1, dated November 18, 2004, the staff

requested the applicant to provide the basis for concluding that 50,000 partial load lifts and less

than 5,000 at, or near, rated load lifts are in accordance with design of 20,000 to 200,000 load

cycles.

In its response, dated January 7, 2005, the applicant cited an earlier submittal to the NRC,

dated January 11, 1982, regarding the control of heavy loads, which is excerpted below:

CMAA Specification 70 and ANSI B30.2-1976 apply to the Containment Building,

Turbine Building and Auxiliary Building Cranes.

The Containment Building, Turbine Building and Auxiliary Building Cranes were

designed to comply with EOCI Specification 61, which was superceded by CMAA

Specification 70. The difference between these two specifications which impact the

evaluation of the safe handling of heavy loads are addressed below with respect to the

Containment and Turbine Building Cranes. The Auxiliary Building Crane will be modified

to provide adequate redundant lifting features. The modification will take into

consideration the requirements of CMAA Specification 70 and ANSI B30.2-1976 and the

guidance of Regulatory Guide 1.13.

It is to be noted that the Franklin Research Center, a division of the Franklin Institute,

conducted a comparison of the recommendations of CMAA-70 with those contained in

EOCI-61. Generally, the requirements of CMAA-70 represent the codification of good

engineering practice which should have been incorporated in cranes built to EOCI-61

specification although specific requirements were not contained in EOCI-61. The

Franklin Research Center study is addressed in "Technical Evaluation Report," NRC

Docket No. 50-334, dated September 24, 1981, performed under NRC Contract No.

NRC-03-79-118.

The applicant further stated:

CMAA-70, Article 3.3.3.1.3 provides substantial guidance with respect to fatigue failure

by indicating allowable stress ranges for various structural members in joints under

repeated loads. EOCI-61 does not address fatigue failure. The requirements of

CMAA-70 are not of consequence for the Containment Building and Turbine Building

Cranes since these cranes are not generally subjected to frequent loads at or near

design conditions (CMAA-70 provides allowable stress ranges for loading cycles in

excess of 20,000 cycles) and are not generally subjected to stress reversal

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(CMAA-70 allowable stress range is reduced to below the basic allowable stress for only

a limited number of joint configurations).

As stated in response to RAI 4.3.13-1, a rated load lift is considered as equal to or greater than

50 percent of the crane's rating. A partial load lift is less than 50 percent of the crane's rating.

The primary auxiliary building (PAB) crane is the most limiting for rated load lifts, while the

containment crane is most limiting for partial load lifts.

The conservative usage assumptions for the two cranes are:

* PPAB crane - Usage is comprised of three components: fuel cask lifts (NUHOMS),

maintenance loads, and original fuel casks (VSC-24). The estimated number of lifts is

2700, 600, and 892 respectively, totaling less than 5,000 lifts for the 60-year life of the

plant.

* containment crane - It is assumed that a total of 60 outages, with 20 days of lifting per

outage, and a total of 40 lifts per day will produce a total of less than 50,000 lifts for the

60-year life of the plant.

On the basis of its review and the RAI response discussed above, the staff determined that

fatigue failure is not likely for the containment building and PAB cranes because the applicant

provided adequate justification for concluding that 50,000 partial load lifts and less than 5000

at, or near, rated load lifts are in accordance with the design-load cycles. The staff's concern

described in RAI 4.3.13-1 is resolved.

*4.3.13.3 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.

The applicant provided an FSAR supplement summary description of crane load cycle limit in

LRA Section Al 5.4.2. On the basis of its review, the staff concluded that the FSAR supplement

summary adequately describes the TLAA on crane load cycle limit and, is therefore,

acceptable.

4.3.13.4 Conclusion

The staff reviewed the applicant's TLAA on crane load cycle limits, as summarized in LRA

Section 4.3.13, and determined that the metal fatigue assessments at Units 1 and 2 will

continue to comply with the staff's requirements throughout the period of extended operation.

The staff concluded that the applicant's TLAA for crane load cycle limits complies with the

staff's acceptance criterion for TLAAs 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 conclpded that

the FSAR supplement contains an appropriate summary description of the TLAA on crane load

cycle limit for the period of extended operation, as required by 10 CFR 54.21(d).

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4.4 Fracture Mechanics Analysis

4.4.1 Reactor Vessel Underclad Cracking

Reactor vessel underclad cracks were first discovered in October 1970 during examination of

the Atucha reactor vessel (RV). They were reported to exist only in SA-508, Class 2 RV

forgings manufactured to a coarse grain practice and clad by high-heat-input submerged arc

processes. The underclad cracking issue was first addressed by Westinghouse topical report

WCAP-7733, which justified the continued operation of Westinghouse plants for 32 EFPYs.

Subsequently, Westinghouse submitted WCAP-1 5338, which extended the analysis to justify

operation of Westinghouse plants for 60 calendar years of plant operation. The staff review of

WCAP-1 5338 is contained in a September 25, 2003, letter to R.A. Newton (Westinghouse

Owners Group) and concluded that LRAs should include two action items:

(1) The license renewal applicant is to verify that its plant is bounded by the WCAP-1 5338

report. Specifically, the renewal applicant is to indicate whether the number of design

cycles and transients assumed in the WCAP-1 5338 analysis bounds the number of

cycles for 60 years of operation of its RV.

(2) 10 CFR 54.21 (d) requires that an FSAR supplement for the facility contain a summary

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

evaluation of TLAA for the period of extended operation. Those applicants for license

renewal referencing the WCAP-1 5338 report for the RV components shall ensure that

the evaluation of the TLAA is summarily described in the FSAR supplement.

4.4.1.1 Summary of Technical Information In the Application

The applicant indicated that the Units 1 and 2 RVs have neither underclad reheat cracking nor

underclad cold cracking because the vessel manufacturers did not use the welding processes,

post-weld heat treating practices, or materials that contributed to the cracking conditions.

Specifically, the applicant stated that single layer cladding was applied using one-wire cladding

processes with low-heat input that did not exhibit underclad reheat cracking in evaluations of

either test samples or actual nozzle cutouts. Multiple layer cladding had preheating and

post-heating applied during the cladding processes, precluding underclad cold cracking.

4.4.1.2 Staff Evaluation

The applicant confirmed that the vessel manufacturers did not use the welding processes,

post-weld heat treating practices, or materials that contributed to the underclad cracking

conditions in other vessels. The staff agreed that reactor vessel underclad cracking is not an

applicable TLAA.

4.4.1.3 FSAR Supplement

Reactor vessel underclad cracking is not considered a TLAA at Units 1 and 2. Therefore, an

FSAR supplement summary description is not required.

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4.4.1.4 Conclusion

The staff reviewed the applicant's TLAA on reactor vessel underclad cracking, as summarized

in LRA Section 4.4.1, and concluded that underclad cracking is not an applicable TLAA for

PBNP. The staff also concluded that an FSAR supplement on reactor vessel underclad

cracking is not required.

4.4.2 Reactor Coolant Pump Flywheel Analysis

The function of the reactor coolant pump (RCP) in the reactor coolant system (RCS) of a PWR

plant is to maintain an adequate cooling flow rate by circulating a large volume of primary

coolant water at high temperature and pressure through the RCS. A concern about overspeed

of the RCP and its potential for failure led to the issuance of Regulatory Guide (RG) 1.14,

"Reactor Coolant Pump Flywheel Integrity," in 1971. The regulatory position of RG 1.14

concerning ISI calls for an in-place ultrasonic volumetric examination of the areas of higher

stress concentration at the bore and keyway at approximately 3-year intervals and a surface

examination of all exposed surfaces and complete ultrasonic volumetric examination at

approximately 10-year intervals. The flywheel inspection schedule is to coincide with the

individual plant's ISI schedule as required by ASME Code Section Xl.

In January 1996, Westinghouse submitted WCAP-1 4535, 'Topical Report on Reactor Coolant

Pump Flywheel Inspection Elimination." This report, which provides an engineering analysis

based on fracture mechanics, is intended to eliminate RCP flywheel ISI requirements for all

operating Westinghouse plants and some B&W plants. However, the NRC safety evaluation of

WCAP-14535, dated January 1996, stated, "the staff believes that even for flywheels meeting

all the design criteria of RG 1.14, as modified in this SER, inspections should not be completely

eliminated." The NRC safety evaluation states:

... the staff finds the following acceptable:

(1) Licensees who plan to submit a plant-specific application of this topical

report for flywheels made of SA 533 B material need to confirm that their

flywheels are made of SA 533 B material. Further, licensees having

Group-15 flywheels need to demonstrate that material properties of their

A516 material is equivalent to SA 533 B material, and its reference

temperature, RTNDT, is less than 30 OF.

(2) Licensees who plan to submit a plant-specific application of this topical

report for their flywheels not made of SA 533 B or A516 material need to

either demonstrate that their flywheel material properties are bounded by

those of SA 533 B material, or provide the minimum specified ultimate

tensile stress, S., the fracture toughness, Kfc, and the reference

temperature, RTNDT, for that material. For the latter, the licensees should

employ these material properties, and use the methodology in the topical

report, as extended in the two responses to the staff's RAI, to provide an

assessment to justify a change in inspection schedule for their plants.

(3) Licensees meeting either (1) or (2) above should either conduct a

qualified in-place ultrasonic examination (UT) over the volume from the

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inner bore of the flywheel to the circle of one-half the outer radius or

conduct a surface examination (MT and/or PT) of exposed surfaces

defined by the volume of the disassembled flywheels once every 10

years. The staff considers this 1 0-year inspection requirement not

burdensome when the flywheel inspection is conducted during scheduled

ISI inspection or RCP motor maintenance. This would provide an

appropriate level of defense in depth.

4.4.2.1 Summary of Technical Information in the Application

RG 1.14, Revision 1, dated August 1975, provides the staff's recommended acceptance criteria

regarding material specifications and Westinghouse Topical Report WCAP-1 4535 presents an

evaluation of the probability of failure over an extended operating period of 60 years. This

report demonstrates that the flywheel design has a high structural reliability with very high flaw

tolerance and negligible flaw crack extension over a 60-year service life. The NRC reviewed

and approved WCAP-14535-A for application with certain conditions and limitations. In the

LRA, the applicant verified the RCP flywheel material and invoked this analysis for reducing the

frequency of performing RCP flywheel inspections.

4.4.2.2 Staff Evaluation

The staff's review of LRA Section 4.4.2 identified an area in which additional information was

necessary to complete the review of the RCP Flywheel Analysis evaluation. The applicant

responded to the staff's RAI as discussed below.

RG 1.14, Revision 1, 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 is required to demonstrate that the

total number of RCP start/stop cycles projected through the end of the extended periods of

operation for each of the units will be bounded by the number of RCP start/stop cycles

assumed in the 60-year fatigue-induced crack growth analysis for the RCP flywheels (i.e.,

based on a bounding analysis of 6000 RCP start/stop cycles).

An evaluation of the probability of failure over the period of extended operation was performed

in WCAP-1 4535A, dated January 1996, for all operating Westinghouse plants and certain

B&W plants. It demonstrated that the flywheel design had a high structural reliability with very

high flaw tolerance and negligible flaw crack extension over a 60-year service life. The NRC

reviewed and approved the evaluation.

RAI 4.4.2. In RAI 4.4.2, dated November 17, 2004, the staff requested the applicant to provide

the number of RCP start/stop cycles that are assumed in the 60-year RCP flywheel fatigue

crack growth assessment for PBNP.

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In its response, dated January 25, 2005, the applicant confirmed that the conservative

estimation for the number of RCP start/stop cycles will be 500 for the 60-year extended life.

This estimated number of cycles is well below the assumed RCP cycles of 6000 in the

Westinghouse document and, therefore, PBNP RCP flywheels are bounded by the

Westinghouse analysis.

On the basis of its review and the above discussion, the staff concluded that the TLAA for RCP

flywheels, as provided in LRA Section 4.4.2, is in compliance with 10 CFR 54.21 (c)(1 )(i). The

applicant's response is acceptable and, therefore, the staff's concern described in RAI 4.4.2 is

resolved.

4.4.2.3 FSAR Supplement

As required by 10 CFR 54.21 (d), applicants for license renewal must include 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. The applicant

provided the following FSAR supplement summary description for the TLAA on fatigue-induced

crack growth of the RCP flywheels:

An evaluation of the probability of failure over the period of extended operation

was performed in WCAP-14535-A for all operating Westinghouse plants and

certain Babcock and Wilcox plants. It demonstrates that flywheel design has a

high structural reliability with a very high flaw tolerance and negligible flaw crack

extension over a 60-year service life. PBNP verified the RCP flywheel material

and invoked this analysis as the basis for reducing the frequency of performing

RCP flywheel inspections. The analysis associated with the structural integrity of

the reactor coolant pump flywheel has been evaluated and determined to remain

valid for the period of extended operation, in accordance with

10 CFR 54.21 (c)(1 )(i).

The applicant provided an FSAR supplement summary description for the RCP flywheels in

LRA Section Al 5.4.3. It provides a reference to WCAP-1 4535-A and reflects the LRA as

supplemented by letter dated January 25, 2005. On the basis of its review, the staff concluded

that the FSAR supplement summary adequately describes the TLAA on RCP flywheels and, is

therefore, acceptable.

4.4.2.4 Conclusion

The staff reviewed the applicant's TLAA on RCP Flywheel Analysis, as summarized in LRA

Section 4.4.2, and determined that the fracture mechanics analyses at Units 1 and 2 will

continue to comply with the staff's requirements throughout the period of extended operation.

The staff concluded that the applicant's TLAA for RCP Flywheel Analysis complies with the

staff's acceptance criterion for TLAAs 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 concluded that

the FSAR supplement contains an appropriate summary description of the TLAA on RCP

Flywheel Analysis for the period of extended operation, as required by 10 CFR 54.21 (d).

4-47
4.4.3 Reactor Coolant Pump Casing Analysis (ASME Code Case N-481 Analysis)

4.4.3.1 Summary of Technical Information In the Application

In LRA Section 4.4.3 the applicant stated that the ASME Section Xi Code, up to and including

the 1998 Edition, required a volumetric inspection of the RCP casing welds, and a visual

inspection of the pressure boundary components. In lieu of performing the required Section Xl

internal visual and volumetric inspections of RCP CASS casings, a fracture mechanics analysis,

supplemented by visual examinations, per the requirements of ASME Code Case N-481 was

performed for the original operating period of 40 years. This analysis is contained in the

generic industry WCAP-13045, and the PBNP-specific WCAP-14705. These analyses

incorporated the effects of thermal embrittlement, and demonstrated compliance with Code

Case N-481, requirements for the original 40-year operating license period.

The current ASME Section Xl Code applicable for PBNP is the 1998 Edition with all addenda

through 2000. The NRC approved the use of this ASME Code edition at PBNP via SER, dated

November 6, 2001. This Code does not require pump casing weld volumetric, or routine

internal visual examinations; however, it does require external surface examinations of the

casing welds, and internal visual examinations when the RCP is disassembled for other

reasons. The applicant stated that the fracture mechanics analysis would not be revised and

resubmitted to the NRC for the extended period of operation in support of applying Code Case

N-481 and, therefore, is not a TLAA.

4.4.3.2 Staff Evaluation

The staff's review of LRA Section 4.4.3 identified an area in which additional information was

necessary to complete the review of the RCP casing analysis evaluation. The applicant

responded to the staff's RAI as discussed below.

RAI 4.4.3-1. LRA Section 4.4.3 indicates that the applicant re-evaluated the fracture mechanics

analyses to ASME Code Case N-481 documented in WCAP-13045 and WCAP-14705 for the

Units 1 and 2 RCP casings and they remain valid for the 60-year extended license operating

period. The LRA indicates that these components are not susceptible to thermal aging

because they satisfy the criteria in the NRC safety evaluation for WCAP-14575-A. The LRA

also indicates that the fracture mechanics analysis would not be revised and resubmitted to the

NRC for the extended period of operation because the Code Case has been superceded by the

ASME Code and the analysis is no longer needed. In RAI 4.4.3-1, dated February 7, 2005, the

staff requested the applicant to evaluate the ASME Code Case N-481 analysis to the criteria for

TLAA in 10 CFR 54.3 to determine whether the analysis satisfies the criteria and should be

considered a TLAA. If it satisfied the TLAA criteria, the applicant was requested to identify the

changes to the analysis that result from the proposed additional 20 years of facility operation

and to provide the results of the analysis that satisfy 10 CFR 54.21 (c)(1)(i), (ii) or (iii).

4-48
In its response, dated March 4, 2005, the applicant stated the following:

The reactor coolant pump integrity analysis is not a time-limited aging analyses (TLAA)

for PBNP. As defined in 10 CFR 54.3(a), time-limited aging analyses, for the purposes

of this part, are those licensee calculations and analyses that:

* Involve systems, structures, and components within the scope of license

renewal, as delineated in §54.4(a);

* Consider the effects of aging;

* Involve time-limited assumptions defined by the current operating term, for

example, 40 years;

* Were determined to be relevant by the licensee in making a safety

determination;

* 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 §54.4(b); and

* Are contained or incorporated by reference in the CLB.

The ASME Section Xl Code, up to and including the 1998 Edition, required a volumetric

Inspection of the RCP casing welds, and a visual inspection of the pressure boundary

components. In lieu of performing the required Section Xl internal visual and volumetric

inspections of RCP cast austenitic stainless steel (CASS) casings, a fracture mechanics

analysis, supplemented by visual examinations, per the requirements of ASME Code

Case N-481 was performed for the original operating period of 40 years. This analysis

is contained in the generic industry WCAP-1 3045, and the PBNP specific WCAP-1 4705.

These analyses incorporated the effects of thermal embrittlement and demonstrated

compliance with Code Case N-481 requirements for the original 40-year operating

license period.

The current ASME Section Xl Code applicable for PBNP is the 1998 Edition of the Code

with Addenda through 2000. The NRC approved the use of this ASME Code Edition at

PBNP with an NRC safety evaluation dated November 6, 2001. This Code does not

require pump casing weld volumetric, or routine internal visual examinations; however, it

does require external surface examinations of the casing welds and internal visual

examinations when the RCP is disassembled for other reasons. Since RCP volumetric

examinations are no longer required by the ASME Section Xl Code, the fracture

mechanics analysis providing the basis for invoking Code Case N-481 is no longer

needed and is no longer a part of the CLB. Thus, the fracture mechanics analysis for

applying Code Case N-481 does not meet the six criteria for defining a TLAA per

10 CFR 54.3 and is not a TLAA for PBNP.

The generic technical report (GTR) for Class 1 Piping and Associated Pressure

Boundary Components, WCAP-14575-A, identifies that a fracture mechanics analysis

performed for the extended operating period is an acceptable means of managing

thermal aging of CASS. The NRC SER for the GTR for Class 1 Piping and Associated

Pressure Boundary Components, WCAP-1 4575-A, provides delta-ferrite and

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Molybdenum screening criteria to determine if the CASS material is susceptible to

thermal aging. The generic industry WCAP-1 3045 identifies that the delta-ferrite

content for all the PBNP Unit's RCP casing castings is less than 10%, and the

Molybdenum content is 0.20 percent. The PBNP pump casing castings are not

considered susceptible to thermal aging per the screening criteria. Thus, a RCP's

structural integrity analysis for managing thermal aging at PBNP is not necessary.

As a result of the above information, LRA Section 4.4.3, "Reactor Coolant Pump Casing

Analysis (ASME Code Case N-481 Analysis)," was deleted by the applicant from the LRA.

On the basis of its review and RAI response, the staff found deletion of LRA Section 4.4.3

acceptable. RCP casing analysis is not considered a TLAA, in accordance with the definition of

10 CFR 54.3. The staff's concern described in RAI 4.4.3-1 is resolved.

4.4.3.3 FSAR Supplement

The RCP casing is not identified as a TLAA, therefore, an FSAR supplement is not required.

Furthermore, the applicant has deleted LRA Section 4.4.3.

4.4.3.4 Conclusion

The RCP casings are not considered susceptible to thermal aging. Therefore, a structural

integrity analysis is not necessary. The staff concluded that the RCP casing analysis is not

identified as a TLAA, in accordance with the definitions of 10 CFR 54.3. Furthermore, in

response to the staff's RAI the applicant deleted LRA Section 4.4.3.

4.4.4 Reactor Coolant System Main Loop Piping Leak-Before-Break Analysis

4.4.4.1 Summary of Technical Information In the Application

The applicant stated that the original structural design basis of the PBNP Class 1 piping

systems required consideration of dynamic effects resulting from non-mechanistic

circumferential pipe breaks, and that protective measures for such breaks be incorporated into

the plant design. Subsequent to the original design, a new concern regarding asymmetric

blowdown loads was identified in 1975. These asymmetric blowdown loads could cause

pressure imbalance loads both internal and external to the RCS. According to the applicant,

the loads could cause previously unconsidered damage to the RCS equipment. The NRC

designated this an unresolved safety issue (USI) MA-2" (Asymmetric Blowdown Loads on the

RCS). Westinghouse addressed this USI on a generic basis.

The applicant stated that the NRC reviewed and approved the generic Westinghouse

leak-before-break (LBB) evaluation(s) in NRC Generic Letter (GL) 84-04. The NRC requested

that PBNP incorporate the generic LBB analysis for the RCS main loop piping to eliminate from

the design basis the consideration of dynamic effects of postulated ruptures in primary coolant

loop piping. By letter dated May 30,1985, Wisconsin Electric requested an exemption from

10 CFR 50, Appendix A, General Design Criterion (GDC) 4, based on the generic

Westinghouse LBB analysis. In 1986, the NRC revised 10 CFR 50 Appendix A, GDC 4, to.

allow the use of LBB technology for excluding from the design basis the dynamic effects of

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postulated ruptures in primary coolant loop piping in pressurized water reactors. By letter dated

May 6, 1986, the NRC stated that Wisconsin Electric's request for an exemption was not

necessary due to the revision to 10 CFR 50, Appendix A, GDC 4, and acknowledged that PBNP

was bounded by the generic Westinghouse LBB analysis and met the additional criteria

identified in NRC GL 84-04.

The applicant stated that plant-specific LBB analysis for Units 1 and 2, primary coolant loop

piping was performed by Westinghouse in 1996, and revised in 2002 and 2003. The results of

the current LBB analysis are documented in WCAP-14439, Revision 2. The report

demonstrates compliance with LBB technology for the RCS piping based on plant-specific

analysis, using the methodology and criteria of SRP Section 3.6.3. The revised LBB analysis

incorporates analysis parameters associated with power uprate conditions, and a 60-year

operating period. This revision documents RCS main loop piping geometry, loading, and

material properties used in the fracture mechanics evaluation. Since the primary loop piping

systems include cast stainless steel fittings, EOL (60-year) fracture toughness calculations

considering the effects of thermal aging were determined for each heat of material.

Based on loading, pipe geometry, and fracture toughness considerations, enveloping critical

locations were determined at which LBB crack stability evaluations were made. Through-wall

flaw sizes were identified that would cause a leak at a rate of ten times the leakage detection

subsystem capability of the plant. Large margins for such flaw sizes were demonstrated

against flaw instability. Finally, by analyzing plant-specific transients and cycles, the fatigue

crack growth for the 60 years was shown to be acceptable for the primary loop piping. The

applicant concluded that all the recommended LBB margins (margin on leak rate, margin on

flaw size, and margin on loads) were satisfied.

4.4.4.2 Staff Evaluation

The successful application of LBB to Units 1 and 2 RCS primary loop piping is described in

Technical Report WCAP-14439, Revision 2, Technical Justification for Eliminating Large

Primary Loop Pipe Rupture as the Structural Design Basis for the PBNP Nuclear Plant Units 1

and 2 for the Power Uprate and License Renewal Program," dated September 2003. This

report provides the technical basis for evaluating postulated flaw growth in the main RCS piping

under normal plus-faulted loading conditions. The LBB crack stability evaluations were

performed for enveloping critical locations. Also, for a postulated flaw, a fatigue crack growth

analysis was carried out to demonstrate that fatigue crack growth was negligible over 60 years.

The staff concluded that this LBB analysis meets the definition of a TLAA per NUREG-1800

Section 4.1.

Pursuant to 10 CFR 54.21 (c)(1)(ii), the applicant projected the analyses to the end of the period

of extended operation by reanalysis. The applicant indicated that the analyses were revised

incorporating revised analysis parameters associated with power uprate conditions and a

60-year operating period. The applicant stated that since the primary loop piping contains cast

stainless steel material, the thermal aging of the CASS material of the piping was considered

for the period of extended operation.

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

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(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),

Part 1: Alloy 82/182 Pipe Butt Welds," dated April 2001, justifies. 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 safety evaluation dated June 14, 2001.

The final industry report, 'Alloy 82/182 Pipe Butt Weld Safety Assessment for U.S. PWR Plant

Designs (MRP-1 13)," was issued in July 2004. Pending the staff's review of this report and

additional UT inspection data from piping involving Alloy 82/182 weld material from the industry,

the staff is pursuing resolution of this current operating issue pursuant to 10 CFR Part 50. The

Reactor Coolant System Alloy 600 Inspection Program is documented in SER

Section 3.0.3.2.15. Based on the discussion above and the staff's evaluation of the Reactor

Coolant System Alloy 600 Inspection Program, the staff concluded that the LBB reanalysis

adequately addresses the period of extended operation and, is therefore, acceptable.

4.4.4.3 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.

The applicant provided FSAR supplement summary description of RCS main loop piping LBB in

LRA Section Al 5.4.3. On the basis of its review, the staff concluded that the FSAR supplement

summary adequately describes the TLAA on RCS main loop piping LBB and, is therefore,

acceptable.

4.4.4.4 Conclusion

The staff reviewed the applicant's TLAA on RCS main loop piping LBB, as summarized in LRA

Section 4.4.4, and determined that the fracture mechanics analyses at Units 1 and 2 will

continue to comply with the staff's requirements throughout the period of extended operation.

The staff concluded that the applicant's TLAA for RCS main loop piping LBB 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 concluded that

the FSAR supplement contains an appropriate summary description of the TLAA on RCS main

loop piping LBB for the period of extended operation, as required by 10 CFR 54.21 (d).

4.4.5 Pressurizer Surge Line Piping Leak-Before-Break Analysis

4.4.5.1 Summary of Technical Information in the Application

The applicant stated that the LBB analysis for Units 1 and 2 pressurizer surge line piping was

performed in 1998. The results of the analysis are documented in WCAP-1 5065. The report

demonstrates compliance with LBB technology for the pressurizer surge line piping based on

plant-specific analysis. Westinghouse revised WCAP-1 5065 to include the NRC safety

evaluation dated December 15, 2000, approving the LBB analysis for the PBNP Units 1 and 2

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pressurizer surge line piping. This revision is documented in WCAP-15065-P-A, Revision 1.

The pressurizer surge line LBB analysis incorporates analysis parameters associated with

original licensed power conditions and a 40-year operating period. The LBB analysis includes

the effects of thermal stratification, as evaluated for the PBNP surge lines in WCAP-13509.

WCAP-1 5065-P-A documents pressurizer surge line piping geometry, loading, and material

properties used in the fracture mechanics evaluation. The applicant stated that the pressurizer

surge line piping does not include cast stainless steel fittings.

The applicant stated that the analysis is consistent with the criteria specified in NUREG-1 061

Volume 3, "Report of the U.S. NRC Piping Review Committee, Evaluation of Potential for Pipe

Breaks," using the modified limit load method as specified in SRP, Section 3.6.3. Based on

loading, pipe geometry, and fracture toughness considerations, enveloping critical locations

were determined at which LBB crack stability evaluations were made. Through-wall flaw sizes

were identified which would cause a leak at a rate of ten times the leakage detection subsystem

capability of the plant. Large margins for such flaw sizes were demonstrated against flaw

instability. Finally, by analyzing plant-specific transients and cycles, the fatigue crack growth for

the 40 years was shown to be acceptable for the pressurizer surge line piping. All the

recommended LBB margins (margin on leak rate, margin on flaw size, and margin on loads)

were satisfied. The pressurizer surge line LBB analysis was further evaluated to determine the

impacts of uprated power conditions and a 60-year operating period. The changes in the NSSS

design conditions due to power uprate did not result in any changes to the piping loads used in

the analysis. There are no cast piping fittings contained in the piping system; therefore, the

applicant concluded that thermal aging is not an issue for the period of extended operation.

Thermal aging of the stainless steel weld material was considered with saturated conditions

(fully aged) and, therefore, is valid for the period of extended operation. The transients and

cycles for the 60-year operating period are the same as the transients and cycles used in the

40-year operating period analysis. The impacts of changes in NSSS design conditions, and the

60-year operating period were determined to be negligible. The conclusions of the original LBB

analysis, contained in WCAP-1 5065-P-A, remained unchanged.

The applicant concluded that the pressurizer surge line LBB analysis was evaluated and

determined to remain valid for the period of extended operation, in accordance with

10 CFR 54.21 (c)(1)(i). The applicant further concluded that dynamic effects of pressurizer

surge line pipe breaks need not be considered in the structural design basis of Units 1 and 2 for

the license renewal operating period.

4.4.5.2 Staff Evaluation

The applicant identified critical locations and performed LBB crack stability evaluations based

on loading, pipe geometry, and fracture toughness considerations. The'Opplic nt corncluded

that enveloping critical locations were determined at which LBB crack stability evaluations were

made. The resultant through-wall cracks offered leak rates sufficiently large e ough to be

detected by the plant's leakage detection system without pipe breakage.

The applicant determined, by assessing plant-specific transients and cyclasth t the ¶atigue

crack growth for the 40-year operating period are acceptable for the pressurizer surge line

piping and all margins are satisfied for the 40-year operating period.

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LBB analyses were evaluated considering the effects of power uprate and a 60-year operating

period. It was indicated that there is no CASS in the pressurizer surge line, therefore, the staff

concluded that thermal aging effects are not a concern. Furthermore, the applicant

demonstrated that the transients and cycles for the 60-year period were bounded by the LBB

analysis of the 40-year period and that there were no design changes due to the power uprate.

Based on the fact that the number of cycles are bounded during the period of extended

operation, the staff concluded that pursuant to 10 CFR 54.21 (c)(1)(i), the applicant

demonstrated that the existing analyses are valid for the period of extended operation, and are

therefore, acceptable.

4.4,5.3 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.

The applicant provided FSAR supplement summary description of pressurizer surge line piping

LBB in LRA Section A15.4.3. On the basis of its review, the staff concluded that the FSAR

supplement summary adequately describes the TLAA on pressurizer surge line piping LBB and,

is therefore, acceptable.

4.4.5.4 Conclusion

The staff reviewed the applicant's TLAA on pressurizer surge line piping LBB, as summarized in

LRA Section 4.4.5, and determined that the fracture mechanics analyses at Units 1 and 2 will

continue to comply with the staff's requirements throughout the period of extended operation.

The staff concluded that the applicant's TLAA for pressurizer surge line piping LBB complies

with the staff's acceptance criterion for TLAAs 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 concluded

that the FSAR supplement contains an appropriate summary description of the TLAA on

pressurizer surge line piping LBB for the period of extended operation, as required by

10 CFR 54.21(d).

4A.6 Class 1 Accumulator Injection Line Piping Leak-Before-Break Analysis

4.4.6.1 Summary of Technical Information In the Application

The applicant stated that the LBB analysis for Units 1 and 2 accumulator injection line piping

was performed in 1998. The scope of the analysis for the accumulator injection lines included

the residual heat removal (RHR) return line, and the results are documented in WCAP-1 5107.

The report demonstrates compliance with LBB technology for the PBNP accumulator injection

line piping based on plant-specific analysis. Westinghouse revised WCAP-15107 to include the

NRC safety evaluation approving the LBB analysis for Units 1 and 2 accumulator injection line

piping in 2001. This revision is documented in WCAP-1 5107-P-A, Revision 1. The

accumulator injection line LBB analysis incorporates analysis parameters associated with

original licensed power conditions and a 40-year operating period. WCAP-1 5107-P-A

documents accumulator injection line piping geometry, loading, and material properties used in

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the fracture mechanics evaluation. The applicant stated that the accumulator injection line

piping does not include cast stainless steel fittings. The analysis is consistent with the criteria

specified in NUREG-1061 Volume 3, using the modified limit load method as specified in the

SRP, Section 3.6.3. Based on loading, pipe geometry, and fracture toughness considerations,

enveloping critical locations were determined at which LBB crack stability evaluations were

made. Through-wall flaw sizes were identified which would cause a leak at a rate of ten times

the leakage detection subsystem capability of the plant. Large margins for such flaw sizes

were demonstrated against flaw instability. Finally, by analyzing plant-specific transients and

cycles, the fatigue crack growth for the 40 years was shown to be acceptable for the

accumulator injection line piping. All the recommended LBB margins (margin on leak rate,

margin on flaw size, and margin on loads) were satisfied.

The applicant stated that the accumulator injection line LBB analysis was further evaluated to

determine the impacts of uprated power conditions and a 60-year operating period. The

changes in the NSSS design conditions due to power uprate did not result in any changes to

the piping loads used in the analysis. There are no cast piping fittings contained in the piping

system, therefore, thermal aging is not an issue for the period of extended operation. Thermal

aging of the stainless steel weld material was considered with saturated conditions (fully aged)

and, therefore, is valid for the period of extended operation. The transients and cycles for the

60-year operating period are the same as the transients and cycles used in the 40-year

operating period analysis. The impacts of changes in NSSS design conditions, and the 60-year

operating period were determined to be negligible. The applicant stated that the conclusions of

the original LBB analysis, contained in WCAP-1 5107-P-A, remained unchanged.

The accumulator injection line LBB analysis was evaluated and determined to remain

valid for the period of extended operation, in accordance with 10 CFR 54.21 (c)(1 )(i). The

applicant concluded that the dynamic effects of accumulator injection line pipe breaks need not

be considered in the structural design basis of Units 1 and 2 for the license renewal operating

period.

4.4.6.2 Staff Evaluation

LBB analysis for Units 1 and 2, WCAP-1 5107-P-A, was revised to include the staff's SER,

dated November 7, 2000, which approved the LBB for a 40-year operating period. WCAP-15107-P-A documents accumulator injection line piping geometry, loading, and material

properties used in the fracture mechanics evaluation. It was indicated that there are no CASS

fittings in the accumulator injection lines; therefore, thermal aging of these components is not a

concern for the 60-year operating period.

Critical locations were identified and LBB crack stability evaluations were performed based on

loading, pipe geometry, and fracture toughness considerations. Based on the evaluations, the

resultant through-wall cracks offered leak rates sufficiently large to be detected by the plant's

leakage detection system without pipe breakage.

Assessments of plant-specific transients and cycles determined that the fatigue crack growth

for the 40-year operating period is acceptable for the accumulator injection line piping and that

all margins are satisfied for the 40-year operating period. Furthermore, the LBB analyses were

evaluated considering the effects of power uprate and a 60-year operating period.

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It was demonstrated that transients and cycles for the 60-year period were bounded by the LBB

analysis of the 40-year period and that there were no design changes due to the power uprate.

The staff concluded that pursuant to 10 CFR 54.21 (c)(1 )(i), the applicant demonstrated that the

existing analyses are valid for the period of extended operation, and are therefore, acceptable.

4.4.6.3 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.

The applicant provided FSAR supplement summary description of Class 1 accumulator injection

line piping LBB in LRA Section Al 5.4.3. On the basis of its review, the staff concluded that the

FSAR supplement summary adequately describes the TLAA on Class 1 accumulator injection

line piping LBB and, is therefore, acceptable.

4.4.6.4 Conclusion

The staff reviewed the applicant's TLAA on Class 1 accumulator injection line piping LBB, as

summarized in LRA Section 4.4.6, and determined that the fracture mechanics analyses at

Units 1 and 2 will continue to comply with the staff's requirements throughout the period of

extended operation. The staff concluded that the applicant's TLAA for Class 1 accumulator

injection line piping LBB complies with the staff's acceptance criterion for TLAAs in

10 CFR 5421 (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 concluded that the FSAR supplement contains an

appropriate summary description of the TLAA on Class 1 accumulator injection line piping LBB

for the period of extended operation, as required by 10 CFR 54.21 (d).

4.4.7 Class I RHR Line Piping Leak-Before-Break Analysis

4.4.7. 1 Summary of Technical Information In the Application

The applicant stated that the LBB analysis for Units 1 and 2 RHR suction line piping was

performed in 1998. The results of the analysis are documented in WCAP-1 5105. The

applicant stated that the report demonstrates compliance with LBB technology for the RHR line

piping based on plant-specific analysis. Westinghouse revised WCAP-1 5105 to include the

NRC safety evaluation approving the LBB analysis for the Units 1 and 2 RHR line piping in

2001. This revision is documented in WCAP-15105-P-A, Revision 1. The RHR line LBB

analysis includes the effects of thermal stratification. The RHR line LBB analysis incorporates

analysis parameters associated with original licensed power conditions and a 40-year operating

period. WCAP-15105-P-A documents the plant-specific RHR line piping geometry, loading,

and material properties used in the fracture mechanics evaluation. The applicant stated that

the RHR line piping does not include cast stainless steel fittings.

The applicant stated that the analysis is consistent with the criteria specified in NUREG-1 061

Volume 3, using the modified limit-load method as specified in the draft SRP, Section 3.6.3.

Based on loading, pipe geometry, and fracture toughness considerations, enveloping critical

locations were determined at which LBB crack stability evaluations were made. Through-wall

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flaw sizes were identified which would cause a leak at a rate of ten times the leakage detection

subsystem capability of the plant. Large margins for such flaw sizes were demonstrated

against flaw instability. Finally, by analyzing plant-specific transients and cycles, the fatigue

crack growth for the 40 years was shown to be acceptable for the RHR line piping. All the

recommended LBB margins (margin on leak rate, margin on flaw size, and margin on loads)

were satisfied.

The applicant stated that the RHR line LBB analysis was further evaluated to determine the

impacts of uprated power conditions and a 60-year operating period. The changes in the NSSS

design conditions due to power uprate did not result in any changes to the piping loads used in

the analysis. There are no cast piping fittings contained in the piping system; therefore, thermal

aging is not an issue for the extended operating period according to the applicant. Thermal

aging of the stainless steel weld material was considered with saturated conditions (fully aged)

and, therefore, is valid for the period of extended operation. The transients and cycles for the

60-year operating period are the same as the transients and cycles used in the 40-year

operating period analysis.

The impacts of changes in NSSS design conditions and the 60-year operating period were

determined to be negligible. The conclusions of the original LBB analysis, contained in

WCAP-15105-P-A, remained unchanged. The applicant stated that the RHR line LBB analysis

was evaluated and determined to remain valid for the period of extended operation, in

accordance with 10 CFR 54.21 (c)(11)(i). The applicant concluded that dynamic effects of RHR

suction line pipe breaks need not be considered in the structural design basis of Units 1 and 2

for the license renewal operating period.

4.4.7.2 Staff Evaluation

LBB analysis for the Units 1 and 2, WCAP-1 5105-P-A, was revised to include the staff's safety

evaluation, dated December 18, 2000, which approved the LBB for a 40-year operating period.

WCAP-1 5105-P-A, Revision 1, documents Class 1 RHR line piping geometry, loading, and

material properties used in the fracture mechanics evaluation. The applicant stated that there

are no CASS fittings in the RHR lines; therefore, the staff agreed that thermal aging of these

components is not a concern for the 60-year operating period.

Critical locations were identified and LBB crack stability evaluations were performed based on

loading, pipe geometry, and fracture toughness considerations. Based on the evaluations, the

resultant through-wall cracks offered leak rates sufficiently large enough to be detected by the

plant's leakage detection system without pipe breakage.

Assessments of plant cycles and transients demonstrate that the fatigue crack growth for the

40-year operating period is acceptable for the RHR suction line piping and that all margins are

satisfied for the 40-year period. In addition, LBB analyses were evaluated considering the

effects of power uprate and a 60-year operating period.

The RHR suction line has no CASS components; therefore, the effects of thermal aging are not

a concem. It was determined that transients and cycles for the 60-year period were bounded

by the LBB analysis of the 40-year period and that there were no design changes due to the

power uprate. The staff concluded that pursuant to 10 CFR 54.21 (c)(1)(i), the applicant

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demonstrated that the existing analyses are valid for the period of extended operation, and are

therefore, acceptable.

4.4.7.3 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.

The applicant provided FSAR supplement summary description of RHR line piping LBB in LRA

Section Al 5.4.3. On the basis of its review, the staff concluded that the FSAR supplement

summary adequately describes the TLAA on RHR line piping LBB and, is therefore, acceptable.

4.4.7.4 Conclusion

The staff reviewed the applicant's TLM on RHR line piping LBB, as summarized in LRA

Section 4.4.7, and determined that the fracture mechanics analyses at Units 1 and 2 will

continue to comply with the staff's requirements throughout the period of extended operation.

The staff concluded that the applicant's TLAA for RHR line piping LBB complies with the staff's

acceptance criterion for TLAAs 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 concluded that

the FSAR supplement contains an appropriate summary description of the TLAA on RHR line

piping LBB for the period of extended operation, as required by 10 CFR 54.21 (d).

4.4.8 Component / Piping Subsurface Indication Analysis

4.4.8.1 Summary of Technical Information In the Application

In LRA Section 4.4.8, the applicant stated that fracture mechanics analyses of RV nozzle flaws

were used to justify continued serviceability of the Unit 1 RV. The fracture mechanics

methodology was invoked to justify continued serviceability for approximately a 1 0-year period.

With improvements in NDE equipment and techniques, the RV nozzle indications were

subsequently identified to be within ASME Code allowable limits, and directly acceptable.

Therefore, the applicant concluded that PBNP does not have any active TLAAs associated with

component/piping subsurface indications.

4.4.8.2 Staff Evaluation

In LRA Section 4.4.8, the applicant stated that there are no active TLAAs associated with

component/piping subsurface indications. Subsequently, in a letter dated March 4, 2005, the

applicant deleted LRA Section 4.4.8.

4.4.8.3 FSAR Supplement

Component/piping subsurface indications are not identified as a TLAA, therefore, an FSAR

supplement is not required. The applicant deleted LRA Section 4.4.8.

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4.4.8.4 Conclusion

Component/piping subsurface indications do not have active TLAAs. The staff agreed with the

applicant that component/piping subsurface indication analysis is not identified as a TLAA, in

accordance with the definitions of 10 CFR 54.3. Furthermore, the applicant deleted LRA

Section 4.4.8.

4.4.9 Reactor Vessel Head Penetration Analysis

4.4.9.1 Summary of Technical Information In the Application

As part of a review of changes in the CLB, the applicant identified the need of a new TLAA. By

letter, dated February 23, 2005, the applicant added LRA Section 4.4.9, Reactor Vessel Head

Penetration Analysis.

In LRA Section 4.4.9, the applicant stated that additional structural, fatigue, corrosion, and

fracture mechanics analyses have been performed to support the inspections of both Units 1

and 2 RPV heads Alloy 600 penetrations and inspection and repair of the Unit I RPV head

penetration No. 26. The applicant stated that the results of the analyses indicated that

continued operation of the RPV heads can only be justified through the current operating cycle

due to Alloy 600 penetrations. The RPV heads will be replaced with new heads that do not

incorporate Alloy 600 penetration material. The RPV heads will be replaced during each unit's

respective 2005 outage. The applicant stated that all analyses associated with the new RPV

heads have been evaluated for operation for the period of extended operation in accordance

with 10 CFR 54.21 (c)(1 )(i).

4.4.9.2 Staff Evaluation

Based on the information provided by the applicant, the structural, fatigue, corrosion, and

fracture mechanics analyses of the RPV heads meet the definition of TLAA as defined under

10 CFR 54.3(a). The RPV heads are within the scope of systems, structures, and components

in accordance with 10 CFR 54.4, specifically annotated under the integrity of the reactor coolant

pressure boundary. The staff agreed that with its RPV heads currently in service, the TLAA

does not support continued operation pursuant to 10 CFR 54.21 (c)(1 )(i) and (ii) due to Alloy 600

weld penetration cracking.

The applicant stated that the RPV head for each unit is scheduled for replacement in the 2005

outages. Material and design enhancements are being incorporated into the replacement

heads to enhance the corrosion resistance of the head penetration assemblies. Other design

enhancements are being incorporated to aid in disassembly/assembly efficiency. Some of the

enhancements include elimination of Alloy 600 materials, elimination of unnecessary spate

head penetrations, elimination of unnecessary joints in the CRDM housings, and an improved

penetration weld joint design. The applicant stated that the replacement heads are being

designed and manufactured to ASME Section 1II, 1998 Edition through 2000 Addenda. | Design

specification for the replacement RPV heads states that the components are designed to have

a 40-year design life. The design specification for the replacement RPV heads specify the

same design transient set that was used in the Steam Generator Replacement and Power

Uprate projects for extended EOL conditions. The conclusion was that when the replacement

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components are placed into service, the 40-year design life is adequate to reach the extended

EOL. The analyses associated with verifying the structural integrity of the reactor vessel heads

have been projected to the end of the period of extended operation, in accordance with

10 CFR 54.21 (c)(1 )(i).

The applicant's commitment to replace the RPV heads with heads having penetrations welded

with Alloy 690 material is consistent with the industry practice acceptable by the staff. In its

letter, dated January 25, 2005, the applicant stated that the RPV heads will be replaced during

each unit's upcoming refueling outages. Furthermore, the applicant stated that the replaced

RPV heads will be inspected in accordance with the requirements of NRC Order EA-03-009,

'Order Establishing Interim Inspection Requirements for Reactor Pressure Vessel Heads at

Pressurized Water Reactors," revised on February 20, 2004. Finally, the applicant stated that

NMC is actively participating with the industry through the EPRI MRP efforts to develop

long-term inspection requirements for reactor vessel closure heads and their penetrations for

U.S. PWR plants. The staff concluded that the replacement of the RPV heads along with the

commitment to monitor the new heads in accordance with the most recent MRP guidelines and

the first revised Order EA-03-009 provides the most conservative and up-to-date methodology

for inspecting PWSCC in CRDM penetrations.

In its letter, dated January 25, 2005, the applicant committed to use the interim report "PWR

Materials Reliability Project Interim Alloy 600 Safety Assessment for US PWR Plant (MRP-44),

Part 1: Alloy 82/182 Pipe Butt Welds," and its final version, as part of the basis for the Reactor

Coolant System Alloy 600 Inspection Program. The applicant also committed to submit the

Reactor Coolant System Alloy 600 Inspection Program to the NRC for staff review and approval

24 to 36 months prior to the period of extended operation. The Reactor Coolant System

Alloy 600 Inspection Program is evaluated in SER Section 3.0.3.2.15. Based on the discussion

above, the applicant demonstrated that an aging management program will be in effect to

monitor the effects of aging on the replacement heads for the period of extended operation in

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

4.4.9.3 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.

The applicant provided an FSAR supplement description of the reactor vessel head penetration

analysis in LRA Section Al 5.4.3, as modified by letter dated August 23, 2005. On the basis of

its review, the staff concluded that the FSAR supplement summary adequately describes the

TLAA on reactor vessel head penetration analysis and, is therefore, acceptable.

4.4.9.4 Conclusion

The staff reviewed the applicant's TLAA on reactor vessel head penetration analysis, as

summarized in LRA Section 4.4.9, and determined that the fracture mechanics analyses at

Units I and 2 will continue to comply with the staff's requirements throughout the period of

extended operation. The staff concluded that the applicant's TLAA for the reactor vessel head

penetration analysis complies with the staffs acceptance criterion for TLAAs in 1 0 CFR

54.21 (c)(1 )(i) and (iii), and that the safety margins established and maintained during the

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current operating term will be maintained during the period of extended operation, as required

by 10 CFR 54.21 (c)(1). The staff also concluded that the FSAR supplement contains an

appropriate summary description of the TLAA on reactor vessel head penetration analysis for

the period of extended operation, as required by 10 CFR 54.21(d).

4.5 Loss of Preload

4.5.1 Containment Tendon Loss of Prestress Analysis

4.5.1.1 Summary of Technical Information In the Application

The Units 1 and 2 containment buildings are post-tensioned, reinforced concrete structures

composed of vertical cylinder walls and a shallow dome, supported on a conventional reinforced

concrete base slab. The cylinder walls are provided with vertical tendons and horizontal hoop

tendons. The dome is provided with three groups of tendons oriented 120 degrees apart.

In the LRA, the applicant described the factors it considered for estimating the final prestress

forces in tendons, and how they were utilized in designing the containments. The applicant

also summarized the method by which it established the upper and lower limits for each group

of tendons in the two containments. Based on the applicant's projections of the tendon forces

at the end of the period of extended operation, the predicted final effective preload at the end of

60 years exceeds the minimum required preload for all containment tendons. Consequently,

the post-tensioning subsystem will continue to perform its intended function throughout the

period of extended operation.

Furthermore, the applicant stated that the analyses associated with containment tendon loss of

prestress have been projected to the end of the period of extended operation, in accordance

with the requirements of 10 CFR 54.21 (c)(1 )(ii).

In the LRA, the applicant stated that as a confirmatory measure, the containment structure

post-tensioning subsystem surveillances will continue to be performed in accordance with the

Pre-Stressed Concrete Containment Tendon Surveillance Program to verify the integrity of the

tendons. In a letter, dated February 23, 2005, the applicant withdrew this program and deleted

LRA Sections Al 5.3.1 and B3.3.

4.5.1.2 Staff Evaluation

In addition to the analysis results summarized in this TLAA, the staff reviewed applicable

aspects of LRA Section B2.1.2, ASME Section Xl, Subsections IWE and IWL Inservice

Inspection Program

The staff's review of LRA Section 4.5.1 identified areas requiring additional information to

complete the review of the containment tendon loss of prestress evaluation. The applicant

responded to the staff's RAls as discussed below.

RAI 4.5-1. The use of 10 CFR 54.21 (c)(1)(ii) and (iii) is appropriate for concrete containment

tendon prestress TLAA. However, the staff determined that it needed to assess the

plant-specific operating experience regarding the residual prestressing forces in the

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containments, and the methods used to arrive at the projected prestresses forces. Based on

the analysis performed pursuant to 10 CFR 54.21 (c)(1 )(ii), in RAI 4.5-1, dated July 27, 2004,

the staff requested the applicant to provide the following:

(1) The estimated upper and lower bound lines, and the minimum required prestressing

forces for each group of tendons for each containment.

(2) Trend lines of the projected prestressing forces for each group of tendons based on the

regression analysis of the measured prestressing forces. Also, the actual measured

prestressing forces that were used to obtain the trend lines.

(3) Plots showing comparisons of prestressing forces projected to 40 years and 60 years

with the minimum required prestress (or MRV) for each group of tendons for each

containment.

In its response, dated August 26, 2004, the applicant provided a set of tendon prestressing

plots that have been developed in accordance with RG 1.35.1 (reference Calculation

2000-0056, Tendon Prestress Acceptance Umits, Rev. 0). The plots for 60 years include the

upper and lower bound lines and the minimum required prestressing force for each group of

tendons for each of the containments per RG 1.35.1.

In response to RAI 4.5-1 items (2) and (3), the applicant provided the prestressing force plots

with the trend lines of the projected prestressing forces for each group of tendons out to 60

years. The initial plots attached to LRA Section 4.5 were based on the lift-off testing of

common tendons. This approach was not acceptable, as it was based on measurements of

one tendon in a group. The staff recommended that the applicant develop the trend lines from

all measured lift-off data, using a linear regression analysis. The applicant developed the trend

lines using linear regression analysis and utilizing all measured lift-off force data. In its

response, the applicant noted that this trend line information was based on draft calculations,

and that the information will be resubmitted; if the final approved calculation revealed a different

conclusion.

During a meeting on February 15, 2005, the staff indicated and the applicant agreed, that this

response required further clarification. In its response, a clarification letter dated

March 15, 2005, the applicant provided the corrected final plots showing the trend lines and the

actual measured prestressing forces. Figure 4.5-1, shows a plot for Unit 2 hoop tendon

reproduced for illustration purposes.

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Figure 4.5-1 Unit 2 Hoop Tendons, Projected Prestressing Force Trend

UNIT 2 HOOP TENDONS

Projected Pro-stes1n Fome Trend

700.0 

.

-- 650.0--* ____ .__ ..

600.0 - -_ _ _ _-

550.0 - - - - - - - - - - -

1 10 100

| AcL Fo/Tendon -Min. Req'd Force /endon

The staff found the process used in arriving at the tend lines to be in conformance with the

provisions of NUREG-1 800 Section 4.5.3.1.2 and, therefore, it is acceptable. The staff

recognizes that the slopes of the trend lines could change as a result of the prestressing tendon

measurements taken during future inspections. However, the applicant will evaluate the results

pursuant to IWL-3221.1 (c), and take corrective actions as stipulated in the LRA. The staff's

concerns described in RAI 4.5-1 are resolved.

RAI 4,5-2. In LRA Section A15.3.1, the applicant summarized the Prestressed Concrete

Containment Tendon Surveillance Program, as an activity related to this TLAA. The applicant's

description was qualitative. For the summary to be meaningful, at a minimum, the staff

determined that 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 program and the corresponding TLAA

results. In RAI 4.5-2, dated July 27, 2004, the staff requested the applicant to provide this

information to supplement LRA Section Al 5.3.1.

In its response, dated August 26, 2004, the applicant stated that the minimum required

prestressing forces were Interpreted to mean the "final effective stress" at 60 years as

discussed in the FSAR. The final effective stress was chosen to be the same value for 40 or 60

years. In a tabular form, the applicant provided the projected prestressing forces for each

group of tendons in each Unit, together with the corresponding minimum required prestressing

forces, as stipulated in FSAR Section 5.1.2.4. As the minimum required prestressing forces are

stated in the plant FSAR, the applicant pointed out that they were not needed in LRA

Section Al 5.3.1.

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During a meeting on February 15, 2005, the staff indicated and the applicant agreed, that this

response required further clarification. The applicant was requested to present the projected

prestressing forces at 40 and 60 years, along with the minimum required force. In its response,

a clarification letter dated March 15, 2005, the applicant provided the results of its finalized

calculations and the per tendon information. Table 4.5-1 reflects the applicant's projected

prestressing forces.

Table 4.5-1 Projected Prestressing Forces

Trend in'e Walues InsIdpsftendon trend Une- enues Val' In kip endon- '

Unit 40 years 0 years __________

Dome Hoop Vertical . Domel Hoqop VrCical

1 634.3 637.9 661.6 629.4 634.1 658

2 620.5 624.3 640.9 612 615 634.3

Minimum 607 594.2 621.2 607 594.2 621.2

Required Force

By letter dated February 23, 2005, the applicant withdrew LRA Section B3.3, "Pre-Stressed

Concrete Containment Tendon Surveillance Program," and LRA Section Al 5.3.1. The staff

found the applicant's approach acceptable, as it provides the necessary description in the

existing FSAR. The staff's concern described in RAI 4.5-2 Is resolved.

4.5.1.3 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.

The applicant provided an FSAR supplement summary description of the containment tendon

loss of prestress analysis in LRA Section Al 5.4.4. On the basis of its review, the staff

concluded that the FSAR supplement summary adequately describes the TLAA on containment

tendon loss of prestress analysis and, is therefore, acceptable.

4.5.1.4 Conclusion

The staff reviewed the applicant's TLAA on containment tendon loss of prestress analysis, as

summarized in LRA Section 4.5.1, and determined that the loss of preload analyses at Units 1

and 2 will continue to comply with the staff's requirements throughout the period of extended

operation. The staff concluded that the applicant's TLAA for containment tendon loss of

prestress analysis, 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 concluded that the FSAR supplement contains an

appropriate summary description of the TLAA on containment tendon loss of prestress analysis

for the period of extended operation, as required by 10 CFR 54.21 (d).

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4.6 Neutron Absorber

4.6.1 Spent Fuel Pool Storage Rack Boraflex

4.6.1.1 Summary of Technical Information in the Application

The application of the neutron absorber (Boraflex) in the spent fuel pool (SFP) storage racks is

based on degradation studies that assume an integrated dose expected during service for 40

years. Therefore, Boraflex is defined as a TLAA in accordance with 10 CFR 54.21 (a)(3). The

applicant credits the Boraflex Monitoring Program with providing reasonable assurance that

aging effects associated with Boraflex will be adequately managed for the period of extended

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

Currently, the Boraflex Monitoring Program consists of blackness testing conducted once every

5 years and SFP silica level measurements taken monthly in accordance with plant procedures.

In addition, criticality monitoring by analyses are performed to assure the 5-percent subcriticality

margin requirement Is maintained. Prior to the period of extended operation, this program will

be enhanced to include areal density testing, blackness testing or neutron attenuation, and SFP

silica level tracking as qualitative indicators of Boraflex degradation. The applicant will also

continue to perform criticality monitoring by analyses. These enhancements will ensure the

Boraflex Monitoring Program will be consistent with the GALL Report.

Blackness tests are used to determine gap formation, distribution, and size. Areal density tests

are conducted to determine the physical loss of boron carbide (e.g., wall thickness), while SFP

silica levels are measured as a qualitative indication of boron carbide loss. Blackness and areal

density test results are used to determine the Boraflex integrity in the SFP racks. The results of

the areal density tests and SFP silica level measurements are used to verify the SFP rack

design basis is being maintained.

4.6.1.2 Staff Evaluation

The staff's review of LRA Section 4.6.1 identified areas requiring additional information to

complete the review of the SFP rack Boraflex evaluation. The applicant responded to the

staff's RAls as discussed below.

Consistent with 10 CFR 50.21 (c)(1)(iii), the applicant'proposes to manage the aging effects

associated with the Boraflex through an aging management program. The applicant proposes

to credit the Boraflex Monitoring Program, which requires that 10 full-length Watcher-designed

Boraflex panels be tested during each surveillance. The Boraflex panels have been exposed to

the greatest number of freshly discharged fuel assemblies and consist of four panels with

accelerated exposure and six randomly selected panels. The same four panels with

accelerated exposure are tested during each scheduled surveillance.

Currently, scheduled surveillances are conducted once every 5 years and include blackness

tests and SFP silica level measurements. During the period of extended operation, the

applicant committed to enhance the program to be consistent with NUREG-1801 (i.e., areal

density tests, blackness tests or neutron attenuation, SFP silica level measurements, and

criticality monitoring by analysis).

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RAI 4.6.1-1. The surveillance frequency of once every 5 years for the blackness testing was

approved in an NRC letter dated February 21, 1990. Based on industry operating experience

indicating the varying degree to which the Boraflex panels degrade, the staff requested a

justification for continuing the 5-year frequency for areal density testing into the period of

extended operation. In RAI 4.6.1-1, dated March 29, 2005, the staff requested the applicant to

provide the most recent blackness test and SFP silica level measurements, and use this data to

demonstrate the current rate of degradation will not exceed the acceptance criteria.

During conversations with the staff, the applicant committed to enhance the Boraflex Monitoring

Program. In addition, the applicant agreed to provide the requested data to the Region IlIl staff

for their review at their AMRIAMP onsite inspection during the weeks of March 7 and 21, 2005.

The applicant's data and the Boraflex Monitoring Program enhancements are expected to

ensure that the neutron absorbing material will continue to perform its intended function during

the period of extended operation. This was identified as confirmatory item (CI) 4.6.1-1.1.

The staff also requested the applicant provide justification for the 5-year frequency for areal

density testing. During conversations with the staff, the applicant committed to perform areal

density and blackness tests on certain accelerated Boraflex panels once every 2 years during

the period of extended operation. This was identified as confirmatory item (Cl) 4.6.1-1.2.

In response to Cis 4.6.1-1.1 and 4.6.1-1.2, by letter dated April 1, 2005, the applicant

committed to create a new procedure to schedule and perform blackness testing and areal

density testing every 2-years during the period of extended operation on certain accelerated

Boraflex panels. These actions are consistent with the recommendations in the August 2001

Boraflex degradation analyses reviewed by the Region IlIl staff during the March 2005

inspection and as documented in its inspection report dated May 2, 2005. The staff found the

applicant's response to RAI 4.6.1-1 and its commitment acceptable because these actions

ensure that the neutron absorbing material will continue to perform its intended function in

maintaining SFP subcriticality. The staff's concerns are resolved; and therefore, CIs 4.6.1-1.1

and 4.6.1-1.2 are closed.

RAI 4.6.1-2. The applicant indicated that a predictive code, uEPRI RACKLIFE or its equivalent,"

will be used to determine which panels will be subjected to full-length testing (i.e., blackness

testing, neutron attenuation, and areal density testing) and to trend and analyze SFP silica level

measurement results. The input to the predictive code includes areal density and SFP silica

level measurements. The staff is unclear on the ability of the predictive code to project panel

degradation if the first areal density test is completed after the beginning of the period of

extended operation. Therefore, in RAI 4.6.1-2, dated March 29, 2005, the staff requested the

applicant to provide justification regarding the ability of the predictive code to accurately project

the condition of the panels to ensure the degradation does not exceed the acceptance criteria

with one set of data. In addition, if this justification cannot be made, the staff requested the

applicant commit to conducting a baseline areal density test prior to entering the period of

extended operation.

During conversations with the staff, the applicant committed to perform a baseline areal density

inspection of the Boraflex panels prior to entering the period of extended operation for

predictive code purposes. The applicant will revise its response to reflect this statement. This

was identified as confirmatory item (Cl) 4.6.1-2.

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In its response to Cl 4.6.1-2, by letter dated April 1, 2005, the applicant committed to perform a

baseline areal density inspection of the Boraflex panels prior to entering the period of extended

operation to support the use of a predictive code for projecting the condition of the panels

between surveillance tests. In addition, the applicant committed to perform an evaluation within

its corrective action program should silica sampling and areal density trend to a value less than

the acceptance criteria. The corrective actions also include an increase in the frequency of

blackness testing and areal density testing. The staff found the applicant's response to

RAI 4.6.1-2 and its associated commitments acceptable because these actions ensure that the

predictive code will have the appropriate data for projecting the degradation of Boraflex into the

period of extended operation without exceeding the acceptance criteria. The staff's concern is

resolved and, therefore, Cl 4.6.1-2 is closed.

RAI 4.6.1-3. For the acceptance criteria element, the applicant states that this element is

consistent with NUREG-1 801. The applicant committed to making appropriate changes to the

program if any of the test results indicate that program improvements should be made.

However, the staff found this discussion insufficient for ensuring adequate management of

Boraflex degradation. In RAI 4.6.1-3, dated March 29, 2005, the staff requested the applicant

to provide more information regarding the Boraflex Monitoring Program's acceptance criteria

(i.e., when the number of panels to be inspected should be expanded and when the

surveillance frequency should be decreased). Additionally, the staff requested the applicant to

provide a discussion regarding what specific corrective actions will be taken if trends indicate

the acceptance criteria may not be met.

During conversations with the staff, the applicant committed to complete an evaluation, within

its corrective action program, and increase the frequency of blackness and areal density testing

if the silica sample and the areal density trend to a value less than the acceptance criteria. The

applicant committed to provide specific details of the corrective actions that will take place if the

acceptance criteria cannot be maintained. The applicant's enhancements to the program and

corrective actions are expected to ensure continued material performance. The applicant will

revise its response to reflect these statements. This was identified as confirmatory item

(Cl) 4.6.1-3.

In response to Cl 4.6.1-3, by letter dated April 1, 2005, the applicant committed to complete an

evaluation within its corrective action program if silica sampling and areal density trend to a

value less than the acceptance criteria. In addition, the frequency of blackness testing and

areal density testing will be increased. Specifically, corrective actions will be initiated if the test

results find that the 5-percent subcriticality margin cannot be maintained because of current or

projected future Boraflex degradation. These corrective actions may include, but are not limited

to, reanalysis, and repair and/or replacement of the neutron absorbing material. The staff

found the applicant's response to RAI 4.6.1-3 acceptable because the corrective actions ensure

continued material performance, consistent with the acceptance criteria, into the period of

extended operation. The staff's concerns are resolved and, therefore, Cl 4.6.1-3 is closed.

The staff concluded that there is reasonable assurance that the Boraflex Monitoring Program

credited by the Neutron Absorber TLAA, with the stated enhancements and commitments, will

adequately manage the aging effects of the Boraflex panels in the SFP racks in accordance

with the CLB during the period of extended operation.

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4.6.1.3 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.

The applicant provided an FSAR supplement summary description of SFP storage rack

Boraflex in LRA Section Al 5.4.5. On the basis of its review, the staff concluded the FSAR

supplement summary adequately describes the TLAA on SFP storage rack Boraflex and, is

therefore, acceptable.

4.6.1.4 Conclusion

The staff reviewed the applicant's TLAA on SFP pool storage rack Boraflex, as summarized in

LRA Section 4.6, and determined the neutron absorber at Units 1 and 2 will continue to comply

with the staff's requirements throughout the period of extended operation. The staff concluded

that the applicant's TLAA for SFP storage rack Boraflex complies with the staff's acceptance

criterion for TLAAs in 10 CFR 54.21 (c)(1 )(iii), and 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 concluded the FSAR supplement

contains an appropriate summary description of the TLAA on SFP storage rack Boraflex for the

period of extended operation, as required by 10 CFR 54.21(d).

4.7 Wear

4.7.1 Bottom Mounted Instrumentation Thimble Tube Wear

4.7.1.1 Summary of Technical Information In the Application

LRA Section 4.7.1 states that IN 87-44, Supplement 1, "Thimble Tube Thinning in

Westinghouse Reactors," thimble tubes have experienced thinning as a result of flow-induced

vibration. Thimble tube wear degrades the reactor coolant system pressure boundary and

could create a non-isolable leak of reactor coolant. Therefore, the staff requested that

licensees perform the actions described in NRC Bulletin No. 88-09, "Thimble Tube Thinning in

Westinghouse Reactors." In response to this bulletin, PBNP established a program for

inspection and assessment of thimble tube thinning, which was accepted by NRC in a letter to

Wisconsin Electric dated November 22, 1989.

The applicant stated that the original thimble tubes for both Units were replaced during the

1984 -1985 time frame. It was necessary to replace these tubes due to internal blockages and

deposits. Subsequent to the original replacement, five Unit 1 thimble tubes were replaced due

to vibration damage. No through wall in-core thimble tube leakage has ever been experienced

at PBNP.

The thimble tubes are inspected in accordance with the Thimble Tube Inspection Program.

The program determines the frequency of inspection by calculating wear rates based on

historical inspection data. Any tubes determined to be below acceptance criteria as projected

to the next inspection period are repositioned, replaced, or plugged. The Thimble Tube

Inspection Program is described in LRA Section B2.1.23.

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The thimble tubes have proven to be short-lived components that are replaceable on condition.

The Thimble Tube Inspection Program is designed to adequately monitor thimble tube condition

to ensure that the thimble tubes are capable of performing their intended function. The

applicant concluded that thimble tube wear is not a TLAA.

4.7.1.2 Staff Evaluation

LRA Section 4.7.1 states that thimble tubes are short-lived and are replaceable on condition.

The staff agreed with the applicant that thimble tube wear Is not a TLAA. However, the

applicant credits the Thimble Tube Inspection Program to monitor thimble tube condition to

ensure they perform their intended function. The staff's evaluation of the Thimble Tube

Inspection Program is documented in SER Section 3.0.3.3.4.

4.7.1.3 FSAR Supplement

Thimble tube wear is not identified as a TLAA, therefore, an FSAR supplement is not required.

4.7.1.4 Conclusion

Thimble tubes are short-lived components that are replaceable on condition. The staff agreed

with the applicant that thimble tube wear is not an applicable TLAA.

4.7.2 Containment Accident Recirculation Heat Exchanger Tube Wear

4.7.2.1 Summary of Technical Information In the Application

LRA Section 4.7.2, states that PBNP has not experienced containment accident recirculation

fan heat exchanger tube wear. In addition, there are no specific design analyses of vibration

and/or fatigue associated with the containment accident recirculation fan heat exchangers.

Therefore, the applicant concluded that the containment accident recirculation heat exchanger

tube wear is not a TLAA.

4.7.2.2 Staff Evaluation

LRA Section 4.7.2, stated that the containment accident recirculation heat exchanger tube wear

Is not a TLAA. Subsequently, by letter dated March 4, 2005, the applicant deleted LRA

Section 4.7.2.

4.7.2.3 FSAR Supplement

Containment accident recirculation heat exchanger tube wear is not identified as a TLAA,

therefore, an FSAR supplement is not required. Furthermore, the applicant deleted LRA

Section 4.7.2.

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4.7.2.4 Conclusion

PBNP has not experienced containment accident recirculation heat exchanger tube wear. The

staff agreed with the applicant that containment accident recirculation heat exchanger tube

wear is not an applicable TLAA. Furthermore, the applicant deleted LRA Section 4.7.2.

4.8 Environmental Qualification

The 10 CFR 50.49 environmental qualification (EQ) program was identified as a TLAA for the

purpose 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 environment. Harsh environments within the plant

are defined as 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 for which the failure 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 is to provide a list of EQ TLAAs in the LRA.

The applicant will demonstrate that one of the following is true for each type of EQ equipment:

* the analyses remain valid for the period of extended operation;

* the analyses were projected to the end of the period of extended operation; and

* the effect of aging on the intended function(s) will be adequately managed for the period

of extended operation.

4.8.1 Environmental Qualification of Electrical Equipment

The staff established nuclear station EQ requirements in 10 CFR 50 Appendix A Criterion 4 and

10 CFR 50.49. Section 49 of 10 CFR, Part 50, specifically requires that an EQ program be

established to demonstrate that certain electrical components located in harsh" plant

environments are qualified to perform their safety function in those environments after the

effects of in-service aging. Harsh environments are defined as those areas of the plant that

could be subject to the environmental effects of a LOCA, HELB, or post-LOCA radiation. The

effects of significant aging mechanisms are required by 10 CFR 50.49 to be addressed as part

of an EQ program. For the purpose of license renewal, only those components with a qualified

life of 40 years or greater would be TLAAs.

The staff reviewed LRA Section 4.8 where the applicant described the technical bases and

justification for its EQ program to adequately manage the effects of aging on the intended

function(s) of electrical components for the period of extended operation. The staff reviewed

this section to determine whether the applicant demonstrated the effects of aging on the

intended function(s) of the electrical equipment will be adequately managed through the EQ

program, together with other programs and processes, during the period of extended operation

as required by 10 CFR 54.21 (c)(1)(iii).

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4.8.1.1 Summary of Technical Information in the Application

In LRA Section 4.8, the applicant stated that its EQ program was established to demonstrate

that certain electrical components are qualified to perform safety functions in the harsh

environment following a design-basis accident. Elements of the proof of qualification involve

the original 40-year license period. Therefore, 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 EQ program longer than the original

40-year license period.

Qualified service lives for the EQ components were established and are tracked 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 EQ program has provisions for the components to be

re-evaluated for longer service (ie., refurbished, requalified, or replaced). Therefore, the

TLAAs will be managed by an aging management program (AMP) in accordance with

10 CFR 54.21 (c)(1)(iii). The applicant also included a list of EQ packages in LRA Table 4.8-1.

The EQ program manages thermal, radiation, and cyclical aging of components through the

use of aging evaluations based on 10 CFR 50.49(f) qualification methods. As required by

10 CFR 50.49, EQ components not qualified for the current license term are to be refurbished,

replaced, or have their qualification extended prior to reaching the aging limits established in

the evaluation. Aging evaluations for EQ components that specify a qualification of at least 40

years are considered TLAAs for license renewal. The EQ program ensures these EQ

components are maintained within the bounds of their qualification bases. All equipment

qualification summary sheets (EQSS) in the EQ program are considered to be TLAAs for

license renewal due to thermal, radiation, and/or cyclic aging, except for EQSS related to

lubricants. Lubricants are periodically checked and replaced and, therefore, are not considered

to be TLAAs.

The reanalysis of an aging evaluation may be performed to extend the qualification by reducing

margin or excess conservatism incorporated in the prior evaluation. Reanalysis of an aging

evaluation to extend the qualification of a component may be performed as the part of the EQ

program. While a component life-limiting condition may be due to thermal, radiation, or cyclical

aging, the vast majority of component aging limits are based on thermal conditions.

Conservatism may exist in aging evaluation parameters, such as the assumed ambient

temperature of the component, unrealistically low activation energy, or in the application of a

component as de-energized instead of energized. As discussed below, the important attributes

of reanalysis will include analytical methods, data collection and conservative reduction

methods, underlying assumptions, acceptance criteria, and corrective actions (if acceptance

criteria are not met).

Analytical Methods. The analytical models used in the reanalysis of an aging evaluation are the

same as those applied during the first evaluation. The applicant stated that the Arrhenius

methodology is an acceptable thermal model for performing an aging evaluation. The analytical

method used for a radiation aging evaluation involves a demonstration of qualification for the

total integrated dose (i.e., normal radiation dose for the projected installed life plus

accident-radiation dose). For license renewal, one acceptable method of establishing the

60-year normal radiation dose is to multiply the 40-year normal radiation dose by 1.5 (ie., 60

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years/40 years). The result is added to the accident-radiation dose to obtain the total integrated

dose for the component. For cyclical aging, a similar approach may be used. Other models

may be justified on a case-by-case basis.

Data Collection and Reduction Methods. Reducing excess conservatism in the component

service conditions (e.g., temperature, radiation, cycles) used in the prior aging evaluation is the

chief method used for a reanalysis. Temperature data used in an aging evaluation are to be

conservative and based on plant design temperatures or on actual plant temperature data.

Plant temperature data can be obtained in several ways, including monitors used for technical

specification compliance, other installed monitors, measurements made by plant operators

during rounds, and temperature sensors on large motors (while the motor is not running). A

representative number of temperature measurements are conservatively evaluated to establish

the temperatures used in an aging evaluation. Plant temperature data may be used in an aging

evaluation in different ways, such as: (1) directly applying the plant temperature data, or

(2) using the plant temperature data to demonstrate conservatism when using plant design

temperatures. Any changes to material activation energy values as part of a reanalysis are

justified on a case-specific basis. Similar methods of reducing excess conservatism in the

component service conditions from prior aging evaluations may be used for radiation and

cyclical aging.

Underivina Assumptions. EQ component aging evaluations contain sufficient conservatism to

account for most environmental changes due to plant modifications and events. When

unexpected adverse conditions are identified during operational or maintenance activities that

affect the normal operating environment of a qualified component, the affected EQ component

is evaluated and appropriate corrective actions are taken that may include changes to the

qualification bases and conclusions.

Acceptance Criteria and Corrective Actions. The reanalysis of an aging evaluation could extend

the qualification of a component. If the qualification cannot be extended by reanalysis, the

component is maintained, replaced, or requalified prior to exceeding the period for which the

current qualification remains valid. A reanalysis is performed in a timely manner (ie., sufficient

time must be available to maintain, replace, or requalify the component if the reanalysis is

unsuccessful).

The Cable Condition Monitoring Program is a new program that was established specifically for

license renewal. This program manages aging of conductor insulation materials on cables and

connectors, and other electrical insulation materials that are installed in adverse localized

environments caused by heat, radiation, or moisture. The program requires visual inspection of

a representative sample of accessible electrical cables and connections in adverse localized

environments once every 10 years for evidence of jacket surface degradation. The scope of

this program includes accessible non-EQ electrical cables and connectors, including l&C circuit

cables. Although the scope of this program is aimed at non-EQ electrical cables and

connectors, it is equally applicable to EQ electrical cables, since no distinction is made as to

whether the cables being inspected are EQ or non-EQ.

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4.8.1.2 Staff Evaluation

The staff reviewed LRA Section 4.8 to determine whether the applicant submitted adequate

information to meet the requirement of 10 CFR 54.21 (c)(1). For the electrical equipment

identified in the LRA Table 4.8-1, the applicant used 10 CFR 54.21 (c)(1 )(iii) in its TLAA

evaluation to demonstrate 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 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' qualification focused on how the EQ

program manages aging effects to meet requirements delineated in 10 CFR 50.49.

The applicant's EQ program activities establish, demonstrate, and document the level of

qualification, qualified configuration, maintenance, surveillance, and replacement requirements

necessary to meet 10 CFR 50.49. Qualified life is determined for equipment within the scope of

the EQ program and appropriate actions (i.e., replacement or refurbishment), are taken prior to

or at-the end of qualified life of the equipment so that aging limits or acceptable margins are not

exceeded.

4.8.1.3 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 TLAAs for the period of extended operation. The applicant

provided FSAR supplement summary description of EQ in LRA Section A15.4.6. On the basis

of its review, the staff concluded the FSAR supplement summary adequately describes the

TLAA on EQ and, is therefore, acceptable.

4.8.1.4 Conclusion

The staff reviewed the applicant's TLAA on EQ, as summarized in LRA Section 4.8, and

determined the EQ analyses will continue to comply with the staff's requirements throughout the

period of extended operation. The staff concluded the applicant's TLAA for EQ complies with

the staff's acceptance criterion for TLAAs in 10 CFR 54.21 (c)(1 )(iii), and the safety margins established and maintained during the current operating term will be maintained during the

period of extended operation. The staff also concluded the FSAR supplement contains an

appropriate summary description of the TLAA on EQ for the period of extended operation, as

required by 10 CFR 54.21 (d).

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4.9 Conclusion for Time-limited Aging Analyses

The staff reviewed the information in LRA Section 4, "lime-Limited Aging Analysis." On the

basis of its review, the staff concluded that the applicant provided an adequate list of TLAAs, as

defined in 10 CFR 54.3. Furthermore, the staff concluded the applicant 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

also reviewed the FSAR supplement for the TLAAs and found that the FSAR supplement

contains descriptions of the TLAAs sufficient to satisfy the requirements of 10 CFR 54.21 (d). In

addition, the staff concluded that the applicant is in compliance with 10 CFR 54.21 (c)(2) in that

no plant-specific exemptions are in effect that are based on TLAAs.

With regard to these matters, the staff concluded that there is reasonable assurance that the

activities authorized by the renewed licenses will continue to be conducted in accordance with

the CLB, and that any changes made to the CLB to comply with 10 CFR 54.29(a) are in accord

with the Act and NRC regulations.

4-74
SECTION 5

REVIEW BY THE ADVISORY COMMITTEE ON REACTOR

SAFEGUARDS

The NRC staff issued its safety evaluation report (SER) with open items (Ols) related to the

renewal of operating licenses for Point Beach Nuclear Plant (PBNP), Units 1 and 2, on

May 2, 2005. On May 31, 2005, the applicant presented its license renewal application (LRA),

and the staff presented its review findings to the Advisory Committee on Reactor Safeguards

(ACRS) Plant License Renewal Subcommittee. In addition, both the applicant and the staff also

presented in front of the ACRS Full Committee during its 523rd meeting, held on

June 1-3, 2005.

In its interim report, letter dated June 9, 2005, the ACRS presented its findings to

Mr. Luis A. Reyes, NRC Executive Director for Operations. The staff responded to the ACRS's

concerns by letter dated July 15, 2005. A copy of both letters is provided on the following

pages of this SER.

The staff reviewed the applicant's comments on the SER with Ols and completed its review of

the LRA. The staff's evaluation is documented in an SER that was issued by letter dated

October 1, 2005.

During the 527r meeting of the ACRS, held on November 3-5, 2005, the Full Committee

completed its review of the PBNP LRA and the staff's SER. The ACRS documented its findings

in a letter to the Commission dated November 18, 2005. A copy of this letter is also provided

on the following pages of this SER.

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5-2
June 9, 2005

Mr. Luis A. Reyes

Executive Director for Operations

U.S. Nuclear Regulatory Commission

Washington, DC 2005-0001

SUBJECT: INTERIM REPORT ON THE SAFETY ASPECTS OF THE LICENSE RENEWAL

APPLICATION FOR THE POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2

Dear Mr. Reyes:

During the 5231 meeting of the Advisory Committee on Reactor Safeguards, June 1-3, 2005,

we reviewed the license renewal application for the Point Beach Nuclear Plant (PBNP), Units 1

and 2, and the associated Safety Evaluation Report (SER) with open items prepared by the

NRC staff. Our Plant License Renewal Subcommittee also reviewed this matter on

May 31, 2005. During these reviews, we had the benefit of discussions with representatives of

the NRC staff, including Region IlIl personnel, and the Nuclear Management Company, LLC;

We also had the benefit of the documents referenced.

We recognize that the license renewal rule does not include specific consideration of current

operating performance. However, aspects of current performance may affect the development

of license renewal programs and commitments as well as the effectiveness of the implemented

programs.

The Confirmatory Action Letter (CAL) issued to the PBNP on April 21, 2004 will remain open

until improvements are demonstrated in the areas of human performance, engineering design

control, the engineering/operations interface, emergency preparedness, and the Corrective

Action Program (CAP).

An adequate CAP is a key element In the successful implementation of the aging management

programs critical to license renewal. A review of the events leading to the issuance of the CAL

leads to the conclusion that the applicant's CAP has been in a degraded condition for a long

time. The Region IlIl staff stated that the problems are not in the design of the program but in

its implementation. The inspections have also identified other weaknesses in the area of

human performance. Errors in engineering calculations have been identified and are being

corrected, but this work is not yet complete. These errors may have an impact on long-lived

passive components.

It often takes a long time to successfully implement improvements in human performance, and

we note that the current operating license for Unit 1 expires on October 5, 2010. The March 2,

2005 Annual Assessment Letter to the PBNP notes that some improvements in the human

5-3
performance area have been observed. However, problems continue to be identified in the

CAP, and the PBNP remains in the Multiple/Repetitive Degraded Cornerstone column of the

Reactor Oversight Process Action Matrix. The resources needed to address the CAL compete

with the effective development, tracking, and implementation of license renewal programs and

commitments.

In support of its final SER, the staff normally audits and inspects only a fraction of the license

renewal programs and commitments. In the case of the PBNP, the staff should take additional

actions to increase confidence that the requirements of the license renewal rule have been met

and that there is reasonable assurance that aging degradation can be adequately managed.

These actions may include, for example, an expanded inspection of license renewal

commitments and a focused review of the effectiveness of the CAP before the PBNP enters the

period of extended operation. We would like to hear about such planned actions during our

review of the final SER.

Sincerely,

IR~t

Graham B. Wallis

Chairman

References

(1) Nuclear Management Company, LLC, "Application for Renewed Operating Licenses

Point Beach Nuclear Plant Units 1 & 2," February 2004

(2) U.S. Nuclear Regulatory Commission, "Safety Evaluation Report Related to the License

Renewal of the Point Beach Nuclear Plant, Units 1 and 2," May 2005

(3) Letter from J. Caldwell, Regional Administrator, to G. Van Middlesworth, Site Vice

President, Point Beach Nuclear Plant, Nuclear Management Company, LLC,

"Confirmatory Action Letter," April 21, 2004

(4) Letter from J. Caldwell, Regional Administrator, to D. Koehl, Site Vice President, Point

Beach Nuclear Plant, Nuclear Management Company, LLC, "Annual Assessment Letter

- Point Beach Nuclear Plant (Report 05000266/200501; 05000301/200501),"

March 2, 2005

(5) Letter from J. Dyer, Regional Administrator, to M. Wamer, Site Vice President,

Kewaunee and Point Beach Nuclear Plants, Nuclear Management Company, LLC,

"Point Beach Special Inspection - NRC Inspection Report 50-266/01-17(DRS);

50-301/01-17(DRS), Preliminary Red Finding," April 3, 2002

and Preliminary Red Finding - Auxiliary Feedwater Orifice Plugging Issue; NRC

Inspection Report 50-266/02-15(DRP); 50-301/02-15(DRP)," April 2, 2003

5-4
(6) Letter from J. Caldwell, Regional Administrator, to A. Cayia, Site Vice President, Point

Beach Nuclear Plant, Nuclear Management Company, LLC, "Point Beach Nuclear Plant,

Units 1 and 2 Final Significance Determination for a Red Finding and Notice of Violation

(NRC Inspection Report No. 50-266/02-15(DRP); 50-301/02-15(DRP)),"

December 11, 2003

(7) Letter from G. Van Middlesworth, Site Vice President, Point Beach Nuclear Plant,

Nuclear Management Company, LLC, to U.S. Nuclear Regulatory Commission

Document Control Desk, "Commitments in Response to 95003 Supplemental

Inspection," March 22, 2004

(8) Pacific Northwest National Laboratory, "Audit and Review Report for Plant Aging

Management Reviews and Programs, Point Beach Nuclear Plant Units 1 and 2,"

April 11, 2005

(9) U.S. Nuclear Regulatory Commission, "Point Beach Nuclear Plant, Units 1 and 2 NRC

License Renewal Scoping, Screening, and Aging Management Inspection Report

05000266/2005005 (DRS); 05000301/2005005 (DRS)," May 2, 2005

5-5
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5-6
July 15, 2005

Dr. Graham B. Wallis, Chairman

Advisory Committee on Reactor Safeguards

U.S. Nuclear Regulatory Commission

Washington, D.C. 20555

SUBJECT: RESPONSE TO ADVISORY COMMITTEE ON REACTOR SAFEGUARDS

INTERIM REPORT ON THE SAFETY ASPECTS OF THE LICENSE RENEWAL

APPLICATION FOR THE POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2

Dear Dr. Wallis:

In your letter dated June 9, 2005, you summarized the results of the interim review by the

Advisory Committee on Reactor Safeguards (ACRS) of the Nuclear Management Company's

(NMC's) license renewal application for Point Beach Nuclear Plant (PBNP), Units 1 and 2, and

the associated safety evaluation report (SER) with open items prepared by the U.S. Nuclear

Regulatory Commission (NRC) staff. The Committee believes the staff should take additional

actions to increase confidence that the requirements of the license renewal rule have been met

and that there is reasonable assurance that aging degradation can be adequately managed.

As you recognize in your letter, the license renewal rule requires current performance issues to

be addressed within the context of Title 10, Part 50, of the Code of Federal Regulations

(10 CFR Part 50). Section 54.30(a) states that if there is not reasonable assurance during the

current license term that licensed activities will be conducted in accordance with the current

licensing basis (CLB), the licensee must take measures under its current license to ensure that

intended functions will be maintained in accordance with the CLB throughout the term of its

current license. Section 54.30(b) states that compliance with Section 54.30(a) is not within the

scope of the license renewal review. Results from actions taken to resolve a current license

problem becomes part of the CLB and will be carried forward into the period of extended

operation. In the first quarter of 2003, PBNP entered the Multiple/Repetitive Degraded

Comerstone column of the Reactor Oversight Process (ROP) Action Matrix. NRC actions

under the ROP are described in the enclosure to this letter.

With regard to the license renewal process, the staff's SER with open items issued on

May 2, 2005, contains five open items. The open items are being resolved and will be

documented in the final SER. During the past year, the staff has performed several onsite

audits and inspections to ensure the applicant is addressing all items required by the license

renewal rule. The NRC staff audited all aging management programs credited in the PBNP

license renewal application. Additionally, the Region III staff performed its combined scoping,

screening, and aging management inspection which identified no findings. During this effort,

the Region IlIl staff inspected 18 out of 26 aging management programs credited in the license

renewal application. The remaining programs are evaluated through standard baseline

Inspections. The inspection team verified that the applicant meets the requirements of the

license renewal rule and has implemented license renewal programs and activities consistent

with its application. During this inspection, NMC was in the process of modifying the scoping

methodology and expanding the non-safety-related component scope. Therefore, in

5-7
Dr. G. Wallis -2-

August 2005, the Region IlIl staff will perform a followup inspection under Inspection Procedure

(IP) 71002. This inspection will focus on the One-Time Inspection Program, non-safety-related

component scoping, license renewal commitments, and recently implemented actions.

The staff understands the Committee's concern about NMC's ability to implement its aging

management programs and LRA commitments. If the license is renewed, the staff will conduct

License Renewal Application (LRA) post-approval site inspection for license renewal in

accordance with IP 71003 before the period of extended operation begins. During this

inspection the staff will verify: (1) that all license renewal programs and activities have been

implemented in accordance with the license renewal rule, (2) that outstanding commitments

have been met, and (3) that the FSAR supplement contains the required summary description

of aging management programs and activities.

The staff recognizes the ACRS's commitment to safety and appreciates the Committee's

continued efforts in support of the license renewal process.

Sincerely,

)/R

Luis A. Reyes

Executive Director

for Operations

Enclosure: As stated

cc: Chairman Diaz

Commissioner Merrifield

Commissioner Jaczko

Commissioner Lyons

SECY

5-8
NRC ACTIONS UNDER THE REACTOR OVERSIGHT PROCESS

FOR THE POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2

In the first quarter of 2003, the Point Beach Nuclear Plant (PBNP), Units 1 and 2, entered the

Multiple/Repetitive Degraded Cornerstone column (Column IV) of the Reactor Oversight

Process (ROP) Action Matrix. The Region IlIl staff conducted a three-phase supplemental

inspection, in accordance with Inspection Procedure (IP) 95003, to review the licensee's

corrective actions. As stated in the NRC confirmatory action letter (CAL) dated April 21, 2004,

the NRC must determine that performance improvements have actually been made before

closing the inspection findings. In making this determination the NRC has considered: (1) plant

events and findings that may reveal similar performance weaknesses, (2) performance

indicators, (3) the implementation of the licensee's performance improvement plan, and (4) the

results of supplemental inspections. Nuclear Management Company (NMC) developed an

improvement plan (entitled Excellence Plan) and submitted a commitment letter dated

March 22, 2004, focusing on performance issues. NMC committed to make sustained

improvement to address issues in: (1) human performance, (2) engineering design control,

(3) the engineering/operations interface, (4) emergency preparedness, and (5) the corrective

action program (CAP).

Since then, the Region IlIl staff has been assessing and documenting PBNP's performance on a

quarterly basis. In the first 2005 quarterly report, as in the annual assessment letter dated

March 2, 2005, the Region Ill staff concluded that PBNP is operating in a manner that

preserves the public health and safety. NMC has been providing its CAL action step completion

reports to the NRC during periodic public meetings, and the Region IlIl staff will continue to

monitor improvement in all areas listed in the CAL. During June 2005, the Region IlIl staff

performed two CAL special inspections. These inspections evaluated the licensee's actions in

the areas of human performance and emergency preparedness. The Region IlIl staff will also

perform two CAL special inspections in the next few months. A team inspection of engineering

effectiveness and the engineering/operations interface will be conducted during the weeks of

July 26, 2005 and August 8, 2005. An expanded problem identification and resolution (PI&R)

inspection of the licensee's CAP will be conducted during the weeks of September 12, 2005

and September 26, 2005. Both inspection teams will include more inspectors than the standard

baseline inspections and will be supplemented by inspectors from outside the region.

The Committee commented that an adequate CAP is a key element in the successful

implementation of the aging management programs critical to license renewal. NRC has

established measures to evaluate CAP effectiveness during biennial PI&R baseline inspections.

Items entered in the licensee's CAP are reviewed daily by the resident inspectors and assessed

for immediate or future followup and potential trends. For PBNP, in addition to the inspections

described previously, the staff will perform at least two PI&R inspections (in CY07 and CY09)

before the plant enters the period of extended operation. During these inspections, the staff will

evaluate the licensee's ability to identify and correct problems, including those related to license

renewal. Consistent with Inspection Manual Chapter (MC) 0305, after the original red findings

have been closed out, the Region IlIl office may take actions, such as periodic senior

management site visits, to ensure appropriate oversight of the licensee's improvement

initiatives. The MC prescribes up to 200 hours of direct inspection activity to review selected

performance areas when the licensee has been removed from Column IV. Once this happens,

the Region IlIl staff plans to expend at least 100 hours of that allowance on special reviews of

the licensee's CAP. Although problems have been identified in the licensee's CAP, inspections

to date have shown that the licensee's program is adequate.

ENCLOSURE

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5-10
November 18, 2005

The Honorable Nils J. Diaz

Chairman

U. S. Nuclear Regulatory Commission

Washington, DC 20555-0001

SUBJECT: REPORT ON THE SAFETY ASPECTS OF THE LICENSE RENEWAL

APPLICATION FOR THE POINT BEACH NUCLEAR PLANT UNITS 1 AND 2

Dear Chairman Diaz:

During the 527" meeting of the Advisory Committee on Reactor Safeguards, November 3-5,

2005, we completed our review of the license renewal application for the Point Beach Nuclear

Plant (PBNP) Units 1 and 2, and the final Safety Evaluation Report (SER) prepared by the NRC

staff. We issued an interim report on the safety aspects of this application and the draft SER

on June 9, 2005. Our Plant License Renewal Subcommittee also reviewed this matter during a

meeting on May 31, 2005. During these reviews, we had the benefit of discussions with

representatives of the NRC staff and the Nuclear Management Company, LLC (NMC). We also

had the benefit of the documents referenced. This report fulfills the requirements of 10 CFR

54.25 that the ACRS review and report on all license renewal applications.

RECOMMENDATIONS

(1) With the inclusion of the conditions in Recommendation 2, the NMC application for

license renewal of PBNP Units 1 and 2 should be approved.

(2) The staff should expand the scope of its post-approval site inspection to verify that all

license renewal programs have been implemented and commitments have been met. In

addition, the staff should review the effectiveness of the PBNP corrective action

program (CAP) before PBNP enters the period of extended operation.

BACKGROUND AND DISCUSSION

The PBNP Units I and 2 are two-loop Westinghouse pressurized water reactors housed in dry

ambient containments. Originally, each unit was licensed at a power level of 1519 MWt. Each

unit has undergone a low-pressure turbine modification and measurement uncertainty

recapture power uprate to increase the power level to 1540 MWt. NMC has requested renewal

of the operating licenses of Units 1 and 2 for 20 years beyond their current license terms, which

expire on October 5, 2010, and March 8, 2013, respectively.

In the final SER, the staff documents its review of the license renewal application and other

information submitted by the applicant and obtained througt the audits and inspections at the

plant site. The staff reviewed the completeness of the applicarnt'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).

5-11
-2-

The PBNP application demonstrates consistency with, or documents deviations from, the

approaches specified in the Generic Aging Lessons Learned Report. The staff questioned the

applicant's approach to identifying nonsafety-related components whose failure could affect

safety-related components. The applicant modified its scoping methodology to address the

staff's questions. An inspection completed on August 17, 2005 confirmed that this methodology

has been appropriately implemented. In the final SER, the staff concludes that the scoping and

screening processes implemented by the applicant have successfully identified SSCs within the

scope of license renewal and subject to an aging management review. We agree with this

conclusion.

The applicant performed a comprehensive aging management review of all SSCs within the

scope of license renewal. In the application, the applicant describes 26 aging management

programs for license renewal, including existing, enhanced, and new programs. The draft SER

identified 5 open items and 15 confirmatory items. The final SER describes the resolution of

these items. We agree with the resolution of these items and with the staff's conclusion that

the applicant's proposed aging management programs are adequate.

One of the open items relates to plant-specific operating experience of the two units. Containment liner corrosion due to borated water leakage has been identified in both units. The

applicant has committed to performing augmented inspections in accordance with ASME

Section Xl Subsection IWE to monitor the extent of corrosion. The Boric Acid Corrosion

Program is also credited with assessing and managing loss of material in the containment liner.

The augmented inspection program does not include specific criteria for evaluation, repair, or

replacement. At the staff's request, the applicant has agreed to include in the acceptance criteria element of the aging management program, `ASME Section Xl, Subsections IWE and

IWL Inservice Inspection Program," an appropriate discussion of the evaluation, repair or

replacement criteria, and reexamination requirements necessary to ensure leak-tightness and

structural integrity of the liner.

The applicant identified and reevaluated systems and components requiring TLAAs for 20 more

years of operation. The upper shelf energy for both vessels and the reference temperature for

pressurized thermal shock (PTS) for the Unit 2 vessel failed to meet the screening criteria.

To address the low upper shelf energy, the applicant performed equivalent margin analyses allowed by 10 CFR Part 50, Appendix G. These analyses yielded acceptable results through the end of the period of extended operation. The staff performed independent analyses to

confirm the applicants conclusion.

The intermediate-to-lower shell circumferential weld of the Unit 2 vessel is projected to exceed

the PTS screening criterion in 2017. Consistent with the requirements of 10 CFR

54.21 (c)(1 )(iii), the applicant has chosen to manage the effects of aging of this weld during the

period of extended operation. The applicant's commitments for PTS include implementing a

low-low leakage fuel management pattem, using hafnium absorber assemblies, and

documenting a flux reduction plan. This documentation will include any required safety

analyses supporting continued operation. Other options the applicant may pursue include a

more refined analysis of PTS or thermal annealing of the reactor pressure vessel.

In our June 9, 2005 interim report on the PBNP application, we expressed concern with the

effectiveness of the PBNP CAP and the applicant's ability to effectively implement license

renewal programs and meet commitments. We were concerned that the resources needed to

address the staff's April 21, 2004 Confirmatory Action Letter to PBNP would compete with the

effective development, tracking, and implementation of license renewal programs and

commitments. We recommended that, prior to the units entering the period of extended

operation, the staff take additional actions to increase confidence that the requirements of the

license renewal rule have been met. We suggested, for example, an expanded inspection of

license renewal commitments and a focused review of the effectiveness of the CAP. The

PBNP remains in the Multiple/Repetitive Degraded Cornerstone column of the Reactor

Oversight Process Action Matrix, and there are still weaknesses in the CAP.

5-12
-3-

In its July 15, 2005 response to the Committee, the staff described the inspections being

conducted at PBNP to verify that license renewal programs and commitments are appropriate

and consistent with the rule. However, detailed development and implementation of many of

these programs and commitments will occur after the license is renewed and prior to the license

renewal period. The staff plans to perform a post-approval site inspection in accordance with

Inspection Procedure 71003 before the period of extended operation begins.

Inspection Procedure 71003 is the standard inspection that the staff performs prior to the period

of extended operation. This inspection evaluates only a sample of the license renewal

commitments and programs. In light of the applicant's weakness in managing commitments, as

discussed in our interim report, the staff should expand the scope of the post-approval site

inspection to verify that all license renewal programs have been implemented and commitments

have been met. In addition, before PBNP enters the period of extended operation, the staff

should review the effectiveness of the CAP. These actions are necessary to ensure that there

is reasonable assurance that aging degradation can be adequately managed.

With a commitment to perform the expanded inspections described above, the application for

renewal of the operating licenses of the PBNP Units 1 and 2 should be approved.

Sincerely,

/RA/

Graham B. Wallis

Chairman

References:

1. Nuclear Management Company, LLC, "Application for Renewed Operating Licenses

Point Beach Nuclear Plant Units 1 & 2," February 2004.

2. U.S. Nuclear Regulatory Commission, "Safety Evaluation Report Related to the License

Renewal of the Point Beach Nuclear Plant, Units 1 and 2," May 2005.

3. U.S. Nuclear Regulatory Commission, "Safety Evaluation Report Related to the License

Renewal of the Point Beach Nuclear Plant, Units 1 and 2," October 2005.

4. Letter from Graham B. Wallis, Chairman, ACRS, to Luis A. Reyes, Executive Director

for Operations, NRC; "Interim Report on the Safety Aspects of the License Renewal

Application for the Point Beach Nuclear Plant, Units I and 2," June 9, 2005.

5. Pacific Northwest National Laboratory, 'Audit and Review Report for Plant Aging

Management Reviews and Programs, Point Beach Nuclear Plant Units 1 and 2,"

April 11, 2005.

6. U.S. Nuclear Regulatory Commission, "Point Beach Nuclear Plant, Units 1 and 2 NRC

License Renewal Scoping, Screening, and Aging Management Inspection Report

05000266/2005005 (DRS); 05000301/2005005 (DRS)," May 2, 2005.

7. U.S. Nuclear Regulatory Commission, "Point Beach Nuclear Plant, Units 1 and 2 NRC

License Renewal Followup Inspection Report 05000266/2005015 (DRS);

05000301/2005015 (DRS)," September 9, 2005.

B. U.S. Nuclear Regulatory Commission, "Point Beach Nuclear Plant, Units 1 and 2 NRC

Special Inspection Report 05000266/2005011; 05000301/2005011," September 23,

2005.

9. U.S. Nuclear Regulatory Commission, "Point Beach Nuclear Plant, Units 1 and 2 NRC

Special Emergency Preparedness Inspection Report 05000266/2005009 (DRS);

05000301/2005009 (DRS)," August 2, 2005.

5-13
-4-

10. Letter from J. Dyer, Regional Administrator, to M. Warner, Site Vice President,

Kewaunee and Point Beach Nuclear Plants, Nuclear Management Company, LLC,

"Point Beach Special Inspection - NRC Inspection Report 50-266/01-17(DRS); 50-

301/01-17(DRS), Preliminary Red Finding," April 3, 2002.

11. Letter from J. Dyer, Regional Administrator, to M. Warner, Site Vice President,

Kewaunee and Point Beach Nuclear Plants, Nuclear Management Company, LLC,

'Point Beach Nuclear Plant Final Significance Determination for a Red Finding and

Notice of Violation NRC Special Inspection Report No. 50-266/01-17(DRS; 50-301/01-

17(DRS)," July 12, 2002.

12. Letter from J. Dyer, Regional Administrator, to A. Cayia, Site Vice President, Point

Beach Nuclear Power Plant, Nuclear Management Company, LLC, "Point Beach

Nuclear Plant Special Inspections: Resolution of Auxiliary Feedwater Old Design Issue

and Preliminary Red Finding - Auxiliary Feedwater Orifice Plugging Issue; NRC

Inspection Report 50-266/02-15(DRP); 50-301/02-15(DRP)," April 2, 2003.

13. Letter from J. Caldwell, Regional Administrator, to A. Cayla, Site Vice President, Point

Beach Nuclear Plant, Nuclear Management Company, LLC, "Point Beach Nuclear Plant,

Units 1 and 2 Final Significance Determination for a Red Finding and Notice of Violation

(NRC Inspection Report No. 50-266102-15(DRP); 50-301/02-15(DRP))," December 11,

2003.

14. Letter from G. Van Middlesworth, Site Vice President, Point Beach Nuclear Plant,

Nuclear Management Company, LLC, to U.S. Nuclear Regulatory Commission

Document Control Desk, "Commitments in Response to 95003 Supplemental

Inspection," March 22, 2004.

15. Letter from J. Caldwell, Regional Administrator, to G. Van Middlesworth, Site Vice

President, Point Beach Nuclear Plant, Nuclear Management Company, LLC,

"Confirmatory Action Letter," April 21, 2004.

16. Letter from J. Caldwell, Regional Administrator, to D. Koehl, Site Vice President, Point

Beach Nuclear Plant, Nuclear Management Company, LLC, "Annual Assessment Letter

- Point Beach Nuclear Plant (Report 05000266/200501; 05000301/200501)," March 2,

2005.

17. Letter from D. Koehl, Site Vice-President, Point Beach Nuclear Plant, Nuclear

Management Company, LLC, to U.S. Nuclear Regulatory Commission Document

Control Desk, "License Renewal Application Revised Information," September 10, 2004.

18. Memorandum from L. Reyes, EDO, to Chairman Diaz, Commissioner McGaffican, and

Commissioner Merrifield, "Pressurized Thermal Shock Analyses for Renewal of Certain

Nuclear Power Plant Operating Licenses," May 27, 2004.

5-14
SECTION 6

CONCLUSION

The staff of the U.S. Nuclear Regulatory Commission (NRC or the Commission) reviewed the

license renewal application for the Point Beach Nuclear Plant, Units 1 and 2, in accordance with

the 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 concluded that

the requirements of 10 CFR 54.29(a) have been met and that all open items and confirmatory

items have been resolved.

The staff notes that any requirements of 10 CFR Part 51, Subpart A, are documented in

NUREG-1437, Supplement 23, "Generic Environmental Impact Statement for License Renewal

of Nuclear Plants: Regarding Point Beach Nuclear Plant, Units 1 and 2, Final Report," dated

August 12, 2005.

6-1
APPENDIX A

COMMITMENTS FOR LICENSE

RENEWALS OF PBNP Units 1 and 2

During the review of the Point Beach Nuclear Plant Units 1 and 2 LRA, the applicant made

commitments related to aging management programs (AMPs) to manage aging effects of

structures and components (SCs) prior to the period of extended operation. The following table

lists these commitments, along with the implementation schedules and the sources of the

commitment.

A-1
1 A License Renewal flag for each component will be maintained

as part of the equipment information database

HPrior to Period of

Extended Operation

LRA Section 1.0,

NRC 2004-0016

2 R-ISI Program inspections of piping welds less than 4-inch NPS Continue as Part of RH-ISI LRA

will include volumetric examinations for non-socket welds and Section 2.1.1.3.8, 3.1 surface examination for socket welds. and Table 3.1.0-1,

NRC 2004-0016

3 All concrete/grout at Point Beach that is within the scope of Prior to Period of LRA Section 3.0.1.9, license renewal, will be managed for aging. Extended Operation NRC 2004-0016

4 Point Beach will continue to monitor and participate in industry Prior to Period of LRA

initiatives with regard to baffle/former and barrel/former bolt Extended Operation Sections 3.1.2.2.3.3, performance to support aging management for the Unit 1 3.1.2.2.8 and

bolting. Table 3.1.0-2,

NRC 2004-0016

5 PBNP will continue to participate in industry investigations of Prior to Period of LRA

aging effects applicable to reactor vessel internals. Aging Extended Operation Sections 3.1.2.2.6

management activities or surveillance techniques resulting from and 3.1.2.2.9, these initiatives will be incorporated, as required, as NRC 2004-0016

enhancements to the Reactor Vessel Intemals Program.

6 PBNP will incorporate applicable results of industry initiatives Prior to Period of LRA

related to void swelling in the Reactor Vessel Intemals Program. Extended Operation Section 3.1.2.2.6 and

Table 3.1.1,

NRC 2004-0016

A-3
Plant process control procedures (design control,

repair/replacement, and welding) will be revised to ensure that

repair or replacement of Class 1 piping components within the

scope of LBB analysis (welded connections or CASS) would

require a new LBB analysis based on replacement process

and/or material properties.

Prior to Period of

Extended Operation

LRA Table 3.1.0-1,

NRC 2004-0016

PBNP will implement the NRC-approved industry activities Prior to Period of LRA Table 3.1.0-2,

resulting from the MRP, as appropriate, to manage any Extended Operation NRC 2004-0016

applicable aging effects identified through the EPRI MRP effort

(RVI Related). _i

9 The Periodic Surveillance and Preventive Maintenance Program

will be used to replace the program designated bolting.

Prior to Period of

Extended Operation

LRA Tables 3.1.2-1

through 3.1.2-6,

Tables 3.2.2-1

through 3.2.2-4,

Tables 3.3.3-1

through 3.3.3-16,

Tables 3.4.2-1

through 3.4.2-3, and

Tables 3.5.2-1

through 3.5.2-14,

NRC 2004-0016

10 The integrity of the RPV will be directly validated with the testing When Fluence Levels LRA Section 4.1.2,

of the capsule installed on Unit 2 in 2002, should extended Reach Those Anticipated NRC 2004-0016

operation be considered. for End of the Renewed

License Period

11 Capsule A2 (Unit 1) will be removed at a target EOLE fluence of Removal at Fluence LRA Secion 4.2,

3.7 x 1019 n/cm2 . Described NRC 2004-0016

A-4
tv C m , ~" Itment" ,I~, ImplementtitonSchedled

Source

12 The upper shelf energy evaluation will be revised prior to

entering Into the extended period of operation.

1

Prior to Period of

Extended Operation

LRA Section 4.2,

NRC 2004-0016

13 Implement an enhanced ASME Section XI, Subsections IWB, Prior to Period of LRA Appendix A and

IWC, and IWD Inservice Inspection Program. Extended Operation Appendix B2.1.1,

NRC 2004-0016

14 Implement an enhanced ASME Section XI, Subsections IWE Prior to Period of LRA Appendix A and

and IWL Inservice Inspection Program. Extended Operation Appendix B2.1.2,

NRC 2004-0016

15 Implement an enhanced ASME Section XI, Subsections IWF Prior to Period of LRA Appendix A and

Inservice Inspection Program. Extended Operation Appendix B2.1.3,

NRC 2004-0016

16 Implement an enhanced Bolting Integrity Program. Prior to Period of LRA Appendix A and

Extended Operation Appendix B2.1.4,

NRC 2004-0016

17 Implement an enhanced Boraflex Monitoring Program. Prior to Period of LRA Appendix A and

Extended Operation Appendix B2.1.5,

NRC 2004-0016

18 Implement an enhanced Boric Acid Corrosion Program. Prior to Period of LRA Appendix A and

Extended Operation Appendix B2.1.6,

NRC 2004-0016

19 Develop and implement a Buried Services Monitoring Program. Prior to Period of LRA Appendix A and

Extended Operation Appendix B2.1.7,

NRC 2004-0016

A-5
_ _ I__ 8II I II 1 A I _ Pj If ...No. 'ht'em K, C<.mi. men. . f. d.* . . . mp.....ementat.............on.. Sout ,rd..ce

20 Develop and implement a Cable Condition Monitoring Program. Prior to Period of LRA Appendix A and

Extended Operation Appendix B2.1.8,

NRC 2004-0016

21 Implement an enhanced Closed-Cycle Cooling Water System Prior to Period of LRA Appendix A and

Surveillance Program. Extended Operation Appendix B2.1.9,

NRC 2004-0016

22 Implement an enhanced Fire Protection Program. Prior to Period of LRA Appendix A and

Extended Operation Appendix B2.1.10,

NRC 2004-0016

23 Implement an enhanced Flow-Accelerated Corrosion Program. Prior to Period of LRA Appendix A and

Extended Operation Appendix B2.1.11,

NRC 2004-0016

24 Implement an enhanced Fuel Oil Chemistry Control Program. Prior to Period of LRA Appendix A and

Extended Operation Appendix B2.1.12,

NRC 2004-0016

25 Develop and implement a One-Time Inspection Program. Prior to Period of LRA Appendix A and

Extended Operation Appendix B2.1.13,

NRC 2004-0016

26 Implement an enhanced Open-Cycle Cooling (Service) Water Prior to Period of LRA Appendix A and

System Surveillance Program. Extended Operation Appendix B2.1.14,

NRC 2004-0016

27 Implement an enhanced Periodic Surveillance and Preventive Prior to Period of LRA Appendix A and

Maintenance Program. Extended Operation Appendix B2.1.15,

NRC 2004-0016

A-6
Item If

X g * , 28. 

28

Commitment Imptementaton

: I Schedule A

.'b''; ':' Source

,, . In S.!.....2e, ; all.' ,. , , ,., ,: . E , .. ... I - 1,16 I,;~ 

Develop and implement a Reactor Coolant System Alloy 600

Inspection Program.

Prior to the Period of

Extended Operation and

Consistent with

Commitments Made in

Response to NRC

Bulletin 2002-02 and

Requirements of NRC

Order EA-03-009

LRA Appendix A and

Appendix B2.1.16,

NRC 2004-0016,

NRC 2005-0056

29 Implement an enhanced Reactor Vessel Internals Program. Prior to Period of LRA Appendix A and

Extended Operation Appendix B2.1.17,

NRC 2004-0016

30 Implement an enhanced Reactor Vessel Surveillance Program. Implementation Prior to LRA Appendix A and

Need to Assess Condition Appendix B2.1 .18,

of Surveillance Capsule NRC 2004-0016

31 Implement an enhanced Steam Generator Integrity Program. Prior to Period of LRA Appendix A and

Extended Operation Appendix B2.1.19,

NRC 2004-0016

32 Implement an enhanced Structures Monitoring Program. Prior to Period of LRA Table 3.5.0-1

Extended Operation Line 8, and

Appendix B2.1.20,

NRC 2004-0016

33 Implement an enhanced Systems Monitoring Program. Prior to Period of LRA Appendix A and

Extended Operation Appendix B2.1.21,

NRC 2004-0016

A-7
34 Develop and implement a Tank Internal Inspection Program. Prior to Period of LRA Appendix A and

Extended Operation Appendix B2.1.22,

NRC 2004-0016

35 Implement an enhanced Thimble Tube Inspection Program. Prior to Period of LRA Appendix A and

Extended Operation Appendix B2.1.23,

NRC 2004-0016

36 Implement an enhanced Water Chemistry Control Program. Prior to Period of LRA Appendix A and

Extended Operation Appendix B2.1.24,

NRC 2004-0016

37 Implement an enhanced EQ Program. Prior to Period of LRA Appendix A and

Extended Operation Appendix 83.1,

NRC 2004-0016

38 Implement an enhanced Fatigue Monitoring Program. Prior to Period of LRA Appendix A,

Extended Operation Table 3.1.0-2 Line 11

and Appendix B3.2,

NRC 2004-0016

39 A Reactor Vessel Intemals Program will be submitted to the Two Years Prior to NRC 2004-0071

NRC for review and approval. Entering Period of

Extended Operation

40 Scoping, Screening and Aging Management Review results COMPLETED NRC 2004-0083 and

from the recent Auxiliary Feedwater System area modifications NRC 2005-0020

will be provided as part of the LRA annual update of current

licensing basis

41 Two penetrations in the Unit 2 Containment will be opened and COMPLETED NRC 2004-0086

inspected during the spring 2005 refueling outage.

A-8
42 The Structures Monitoring Program will be enhanced to conduct

and document a structural condition survey of the reactor vessel

sump area.

Prior to Period of

Extended Operation

I NRC 2004-0086

43 Final tendon stress and trend calculation results will be provided COMPLETED NRC 2004-0086

if the results are different than those provided in this response.

44 The Structures Monitoring Program will be updated as part of COMPLETED NRC 2004-0086

the LRA annual updated to include wood as a material to be NRC 2005-0020

inspected.

45 As part of LRA Section B.2.1.13, "One Time Inspection Prior to Period of NRC 2004-0101

Program," a one-time visual inspection and hardness Extended Operation

measurement will be performed on accessible locations of a

select set of components of each material type (i.e., cast iron

and brass) to determine whether selective leaching has

occurred and whether the resulting loss of strength and/or

material will affect the intended functions of these components

during the period of extended operation. =

46 PBNP will continue to implement the low-low leakage loading Ongoing NRC 2004-0111

fuel management pattern to minimize the limiting weld fluence.

In addition, PBNP will continue operation with Hafnium absorber Existing Program

assemblies in service until the resolution of the Unit 2

intermediate-to-lower shell girth weld PTS issue via an

alternative analysis methodology.

A-9
"Mk, '' g v MLX'_ *Qmm  

_', " , '!- _ 411, , X_-11A'1 I , fi-, -,A I_ n I 1, 111MOU - I I , I"  I I I -1 61 iW E A" ,M411 0 M , n go ANEW WIN , I W '11 6"M ON ' _', "ft"O , ' `16fi!gag ft'

al,! ',~ ''i.''i'L',AV> 

N , ,=' ' v S, 'd0;^'ff 0'0- umm 

-

~ent 

- d S '_ _ _ _ _ _ _ _ _ _ _ _ _ _ ~' Sourcoe '

47 Documentation of a flux reduction program and other options, December 31, 2006 NRC 2004-0111

as necessary, allowed by 10 CFR 50.61 (b) for the Unit 2

Reactor Pressure Vessel intermediate-to-lower shell girth weld Existing Program

will be completed within one year of receipt of the extended

license. Documentation within this time frame will support

submittal of any required safety analysis at least three years

prior to the time frame that RT. 8 for Unit 2 is projected to

exceed the screening criteria.

48 If acceptable PTS results cannot be provided prior to EOL with March 8, 2013 NRC 2004-0111

alternate analysis techniques, the PBNP flux reduction program

will evaluate the feasibility and practicality of pursuing additional Existing Program

aggressive flux reduction measures prior to EOL, such as the

insertion of part length shielded fuel assemblies.

49 NMC will add line items to LRA Table 3.3.2-2 to include COMPLETED NRC 2004-0135

stainless steel under the Component Type, "Piping and Fittings"

to address the flexible tubing as part of the LRA annual update

50 As part of the Steam Generator Integrity Program, visual Per Steam Generator NRC 2005-0006

inspections of accessible areas to verify the integrity of steam Integrity Program

generator secondary-side components will be performed at least

every six years, with one steam generator being inspected

every three years on an alternating basis. Any indications of

degradation or unacceptable conditions will be evaluated

through the corrective action program, including the extent of

condition.

51 NMC will monitor on-going Industry activities related to failure Prior to Period of NRC 2005-0002

mechanisms for small-bore piping, and will evaluate changes to Extended Operation

PBNP inspection activities based on industry recommendations.

A-10
lINt S MBU

4:'

X -;

Impbeirnteit lWn

I I Schedule -

Soure '

4 I

52 NMC will use the interim report "PWR Materials Reliability

Project Interim Alloy 600 Safety Assessment for US PWR Plants

(MRP-44), Part 1: Alloy 821182 Pipe Butt Welds," and its final

version as part of the basis for the Reactor Coolant System

Alloy 600 Inspection Program.

October 8, 2008 NRC 2005-0002

53 NMC will submit the Reactor Coolant System Alloy 600 October 8, 2008 NRC 2005-0002

Inspection Program 24 - 36 months prior to the period of

extended operation for staff review and approval to determine if

the program demonstrates the ability to manage the effects of

aging per 10 CFR 54.21 (a)(3).

54 NMC will remove the "Exposure Duration" discussion from LRA COMPLETED NRC 2005-0001

Section 2.1.2.1.2 and will summarize the response to RAI 2.1.1

in the "Components Qualified/Designed for Environment"

discussion as part of the LRA annual update.

55 As part of the Cable Condition Monitoring Program, a Prior to Period of NRC 2005-0026

representative sample of in-scope, inaccessible non-EQ Extended Operation

medium-voltage cables not designed for submergence subject

to significant moisture and significant voltage will be tested prior

to the end of the current license period and once every ten

years during the period of extended license. This sample will

include the most susceptible cables and be representative of all

cable types and manufacturers. The basis for this

representative sample will be documented.

Significant moisture is defined as periodic exposure that lasts

more than a few days (i.e., cable in standing water) which is

consistent with NUREG-1801, Section XI.E3. _

A-1I
56

I I .b - W I I IS I. "I I : 1 ^: : , 7 .: I .IiI, ,,: I I ., 2 .: I If I r I I i - 11 Z- 1 11 I -h I x- - f' . I; I I I

Periodic visual inspections of the bus duct will be performed as

part of the Periodic Surveillance and Preventive Maintenance

Program to inspect for signs of insulation cracking, corrosion,

debris, excessive dust buildup, evidence of moisture and water

intrusion, or discoloration of insulation.

Prior to Period of

Extended Operation

NRC 2005-0026

57 Enhancements will be made to the Structural Monitoring Prior to Period of NRC 2005-0026

Program to include the primary shield and reactor vessel Extended Operation

support areas.

58 A susceptible location in the Fire Protection System (i.e., Prior to Period of NRC 2005-0026

uncoated/unwrapped piping) will be scheduled to be inspected Extended Operation

once prior to the period of extended operation and at least every

10 years during the period of extended operation. Based upon

findings from these Fire Protection System inspections,

additional inspection locations could include coated and/or

uncoated buried piping in the Fire Protection System, Service

Water System and Fuel Oil System.

59 NMC will conduct eddy current inspections under the One-Time Prior to Period of NRC 2005-0037

Inspection Program of the tubing of one RHR heat exchanger or Extended Operation

replace the RHR heat exchanger tube bundles prior to the

period of extended operation if eddy current testing of the tubing

of at least one RHR heat exchanger is not completed.

A-12
60 As part of the Bolting Integrity Program, maintenance

instructions will be revised as necessary to clearly state that

lubricants containing molybdenum disuffide should not be used

unless evaluated on a case-by-case basis with consideration

given for the potential of stress corrosion cracking (SCC).

Prior to Period of

Extended Operation

NRC 2005-0037

NMC will continue to use locking devices per the design codes,

standards and specifications applicable to PBNP.

NMC will continue to follow the requirements of 10CFR 50.55a

or request relief, as necessary, regarding the qualification and

certification of NDE personnel.

NMC will clarify that the prohibition against reuse of any bolt or

nut tightened by the turn-of-nut method only applies to

component support bolting installed in accordance with

American Institute of Steel Construction (AISC) or similar design

specifications in which the turn-of-nut method may result in the

bolting material being stressed beyond yield.

61 NMC will provide the One-Time Inspection Program COMPLETED NRC 2005-0037,

methodology for NRC review to detail the sample size selection Inspection Report

criteria and specific component identification criteria within that 0500266/2005015

sample. (DRS),

0500301/2005015

(DRS)

A-13
. )-

62 All systems within the scope of license renewal containing Prior to the period of NRC 2005-0037

components requiring an aging management review and that extended operation

credit the Systems Monitoring Program for managing the effects

of aging on the external surfaces of the components will be

walked down at a minimum frequency of once per operating

cycle, within the limits of accessibility.

A supervisory review will be performed and documented to

ensure that the accessible portions of each system are walked

down at a minimum frequency of once per operating cycle.

Those portions of a system that are considered inaccessible will

be evaluated to ensure that accessible portions of the system

that are walked down contain the same material(s) and the

same or more severe environment(s) as those portions that are

considered inaccessible.

When an unacceptable condition or situation is identified in an

accessible portion of a system, an extent of condition evaluation

will be performed to determine whether the same condition or

situation is applicable to other accessible or inaccessible

portions of the system.

A-14
63 If degradation is detected by the Flow-Accelerated Corrosion

Program such that wall thickness is less than or equal to 87.5

percent of nominal wall thickness for safety-related piping additional examinations will be performed in adjacent areas to

bound the thinning. For both safety-related and

nonsafety-related piping, additional examinations will be

performed in adjacent areas to bound the thinning if the

remaining service life, based on the code minimum allowable

wall thickness, is less than one operating cycle. The sample

size will also be expanded for nonsafety-related piping if

degradation is detected such that the wall thickness is less than

or equal to 60 percent of nominal wall thickness. This covers

situations where the code minimum allowable wall thickness

may be less than 60 percent of nominal wall thickness for

nonsafety-related piping.

-te: . .-Sg - hbM, itj 6 .

Prior to the period of

extended operation

NRC 2005-0037

NRC 2005-0044

As part of the Periodic Surveillance and Preventive Maintenance

Program, records of deferrals, cancellations, and frequency changes for callups credited for License Renewal as aging

management or replacement activities will be retained in an

auditable and retrievable form.

Prior to the period of

extended operation

NRC 2005-0037

A-15
65

I % , G i I > ' -g In ". ILL f.i:.S.; ti..U.r.+sYRbemroi<xw+wtCertain accelerated Boraflex panels will be areal density and

blackness tested every two years during the period of extended

operation.

Prior to Period of

Extended Operation

NRC 2005-0038

The first Boraflex areal density testing of the Boraflex panels will

be performed prior to the period of extended operation.

A new procedure to schedule and perform Boraflex areal

density and blackness testing will be created.

If silica sampling and trending indicates a boron areal density

depletion trend to a value less than the acceptance criteria (ie.,

maintaining the 5 percent subcriticality margin) prior to the next

scheduled test, then an evaluation will be performed within the

corrective action program and the frequency of blackness and

areal density testing increased.

Corrective actions will be taken to ensure that the 5 percent

subcriticality margin of the spent fuel racks in the SFP is

maintained during the period of extended operation. Corrective

actions will be initiated if the test results find that the 5 percent

subcriticality margin cannot be maintained because of current or

projected future degradation. Corrective actions may include,

but are not necessarily limited to, the following:

(1) Re-analysis

(2) Repair and/or Replacement .1. a

A-16
66

' CmmtmentMS.

As a part of the ASME Section Xl, Subsections IWB, IWC, and

IWD Inservice Inspection Program, the requirements of Code

Case N-616 will be supplemented by a VT-2 visual examination

performed each outage for Class 1 systems and each

inspection period for Class 2 and 3 systems with the insulation

removed from the bolted connections. The connections are not

pressurized during these examinations.

Prior to the Period of

Extended Operation

NRC 2005-0071

67 NMC will use enhanced volumetric examination to detect and Prior to the Period of NRC 2005-0044

size cracks or a plant- or component-specific flaw tolerance Extended Operation

evaluation to demonstrate that cast austenitic stainless steel

(CASS) primary loop elbows potentially susceptible to thermal

embrittlement have adequate fracture toughness.

68 NMC will age manage the steam generator (SG) feedrings, Prior to the Period of NRC 2005-0044

J-nozzles, and feedring supports using the Water Chemistry Extended Operation

Control Program and the Steam Generator Integrity Program.

69 The Structures Monitoring Program will examine below-grade Prior to the Period of NRC 2005-0044

concrete when it is exposed by excavation for signs of Extended Operation

degradation from aggressive chemical attack or corrosion of

embedded steel, during the period of extended operation.

Periodic monitoring of ground water chemistry (pH, chlorides,

sulfates) will continue to be performed during the period of

extended operation to ensure the environment remains

non-aggressive. The frequency of monitoring ground water

chemistry (pH, chlorides, sulfates) will be at least once every 5

years.

A-17
70 The following aging management programs will be revised to

credit the One-Time Inspection Program to identify selective

leaching of susceptible components:

* Open-Cycle Cooling (Service) Water System

Surveillance Program

* Fire Protection Program

* Systems Monitoring Program

* Periodic Surveillance and Preventive Maintenance

Program

* Structures Monitoring Program

Prior to the Period of

Extended Operation

NRC 2005-0056

71 An evaluation, repair or replacement requirement discussion will Prior to the Period of NRC 2005-0086

be included in the Acceptance Criteria element of the ASME Extended Operation

Section Xl, Subsections IWE and IWL Inservice Inspection

Program of the LRA prior to the period of extended operation. If

localized area thickness of the containment liner base metal is

reduced by 50% or more of the nominal plate thickness, then

every attempt should be made to correct by repair or

replacement. If the repair or replacement option is impractical,

an acceptance by engineering evaluation option may be

pursued. _

72 If localized area thickness of the base metal is reduced by Prior to the Period of NRC 2005-0086

approximately 50% or more of the nominal plate thickness, then Extended Operation

the reexaminations required by IWE 2420(b) will be continued in

the succeeding inspection periods and the provisions of

IWE-2420(c) will not be applied.

A-18
APPENDIX B

CHRONOLOGY

This appendix contains a chronological listing of the routine licensing correspondence between

the U.S. Nuclear Regulatory Commission (NRC) staff and the Nuclear Management Company,

LLC (NMC), and other correspondence regarding the staff's reviews of the Point Beach Nuclear

Plant Units 1 and 2 (PBNP), Docket Numbers 50-266 and 50-301, license renewal application

(LRA).

February 25, 2004

February 25, 2004

February 25, 2004

February 25, 2004

February 26, 2004

March 1, 2004

March 2, 2004

March 19, 2004

March 24, 2004

April 7, 2004

April 15,2004

April 15, 2004

PBNP Transmittal of Application for Renewed Operating Licenses,

including Environmental Report (Accession No. ML040580023)

PBNP Application for Renewed Operating Licenses, including FSAR

Supplement (Accession No. ML040580024)

PBNP Transmittal of License Renewal Drawings to Aid in Review of the

LRA (Accession No. ML040630451)

PBNP Applicant's Environmental Report - Operating License Renewal

Stage (Accession No. ML040580025)

Notice of March 9, 2004 Meeting Between NRC and NMC to Discuss the

LRA for PBNP (Accession No. ML040570714)

NRC Press Release-04-029: NRC Announces Availability of License

Renewal Application for Point Beach Nuclear Power Plant (Accession No.

ML0406111048)

Receipt and Availability of LRA for PBNP (Accession No. ML040640628)

Notice of March 31, 2004 Public Information Session for NRC to Describe

Its License Renewal Process (Accession No. ML04079021 1)

NRC Press Release-111-04-014: Public Meeting March 31 On License

Renewal Application for Point Beach Nuclear Power Plant (Accession No.

ML040840575)-

Determination of Acceptability and Sufficiency for Docketing, Proposed

Review Schedule, and Opportunity for a Hearing Regarding the

Applications from NMC for Renewal of the Operating Licenses for PBNP

(TAC Nos. MC2099 and MC2100) (Accession No. ML040980219)

Summary of March 9, 2004 Meeting with NMC Regarding the PBNP LRA

(Letter) (Accession No. ML041280264)

Summary of March 9, 2004 Meeting with NMC Regarding the PBNP LRA

(Enclosure) (Accession No. ML041180131)

B-1
April 16, 2004

April 22, 2004

April 22, 2004

May 5, 2004

May 5, 2004

May 17, 2004

May 21, 2004

May 26, 2004

May 26, 2004

June 3, 2004

June 4, 2004

June 8, 2004

June 15, 2004

June 15, 2004

June 29, 2004

NRC Press Release-04-042: NRC Announces Opportunity for Hearing

on Application to Renew Operating Licenses for PBNP, Units 1 and 2

(Accession No. ML041070354)

Summary of March 31, 2004 Public Meeting Regarding the LRA for

PBNP - Slides (Enclosure 3) (Accession No. ML041180238)

Summary of March 31, 2004 Public Meeting Regarding the LRA for

PBNP - Letter and Enclosures 1 through 2 (Accession No.

ML041170437)

PBNP License Renewal Review (Accession No. ML041270559)

PBNP License Renewal Review (Accession No. ML041270553)

NRC Review of PBNP LRA (Accession No. ML041410580)

NRC review of PBNP LRA (Accession No. ML041450239)

Questions and Responses - Summary of May 3, 2004 Telephone

Conference Between NRC and NMC Concerning Receipt of Aging

Management Program Post-Audit Requests for Additional Information

Pertaining to the PBNP LRA (TAC Nos. MC2049 and MC2050)

(Accession No. ML0411610159)

Summary of May 3,2004 Telephone Conference Between NRC and

NMC Concerning Receipt of Aging Management Program Post-Audit

Requests for Additional Information Pertaining to the PBNP LRA (TAC

Nos. MC2049 and MC2050) (Accession No. ML041610149)

Audit and Review Plan for Plant Aging Management Reviews and

Programs - PBNP (Accession No. ML041550860)

Notice of June 24, 2004 Meeting with NMC on License Renewal Scoping

and Screening Methodology Audit for PBNP (Accession No.

ML041 560474)

NRC Press Release-04-037: NRC to Hold Public Meeting June 15,2004

on Proposed License Renewal of PBNP, Units 1 and 2 (Accession No.

ML04116000585)

Transcript of June 15, 2004 Public Meeting on Point Beach License

Renewal (Accession No. ML041900071)

Transcript of June 15, 2004 Public Meeting on PBNP License Renewal

(Accession No. ML041830450)

Audit and Review Plan for Plant Aging Management Reviews and

Programs at PBNP (Accession No. ML041880324)

B-2
June 29, 2004

July 1, 2004

July 8, 2004

July 12, 2004

July 12, 2004

July 22, 2004

July 27, 2004

July 30, 2004

August 5, 2004

August 19,2004

August 26, 2004

August 30, 2004

August 31, 2004

September 10, 2004

September 10, 2004

Notice of July 15, 2004 Exit Meeting with NMC on License Renewal

Audits of Aging Management Programs and Reviews for PBNP

(Accession No. ML041810419)

Scoping Comments for Proposed Operating License Renewal for PBNP

(Accession No. ML041910394)

Summary of Public Scoping Meetings to Support Review of the PBNP

LRA (TAC Nos. MC2049 and MC2050) (Accession No. ML041960112)

NMC PBNP LRA Clarifications (TAC Nos. MC2099 and MC21 00)

(Accession No. ML042030310)

NMC PBNP LRA Clarifications (TAC Nos. MC2099 and MC2100)

(Accession No. ML041960159)

Notice of August 3, 2004 Meeting Between NRC and NMC to Discuss the

LRA for PBNP (Accession No. ML042040430)

NRC Request for Additional Information for the Review of the PBNP LRA

(TAC Nos. MC2099 and MC21 00) (Accession No. ML042110308)

NRC Request for Additional Information for the Review of the PBNP LRA

(TAC Nos. MC2099 and MC21 00) (Accession No. ML042150431)

Summary of Telephone Conference Held on June 24, 2004 Between

NRC and NMC Concerning Draft Requests for Additional Information

Pertaining to the PBNP LRA (Accession No. ML042260399)

Summary of Telephone -Conference Held on July'15, 2004 Between NRC

and NMC Concerning Draft Requests for Additional Information

Pertaining to the PBNP LRA (Accession No. ML042320653)

NMC Response to NRC Request for Additional Information Regarding

Sections 3.5 and 4.5 of the PBNP LRA (TAG Nos. MC2099 and MC21 00)

(Accession No. ML042510486)

NMC Response to NRC Request for Additional Information Regarding the

PBNP LRA (TAC Nos. MC2099 and MC2100) (Accession No.

ML042530053)

NMC Response to NRC Request for Additional Information Regarding the

PBNP LRA (TAC Nos. MC2099 and MC21 00) (Accession No.

ML042530218)

NMC PBNP LRA Revised Information (TAC Nos. MC2099 and MC2100)

(Accession No. ML042660308)

NRC Request for Additional Information for the Review of the PBNP LRA

(Accession No. ML042570040)

B-3
September 14, 2004

September 16, 2004

September 17, 2004

September 23, 2004

September 23, 2004

September 30, 2004

October 8, 2004

October 15, 2004

October 19, 2004

October 21, 2004

October 25, 2004

November 10, 2004

November 12, 2004

Summary of August 3, 2004 Meeting With NMC Regarding the PBNP

LRA Concerning Reactor Vessel Integrity Evaluations (Accession No.

ML042590062)

NRC Request for Additional Information for the Review of the PBNP LRA

(TAC Nos. MC2099 and MC21 00) (Accession No. ML042610283)

Summary of September 2, 2004 Telephone Conference with NMC

Regarding Draft Requests for Additional Information Pertaining to the

PBNP LRA (Accession No. ML042640263)

NRC Request for Additional Information for the Review of the PBNP LRA

(Accession No. ML042680140)

NRC Audit Trip Report on Point Beach License Renewal Scoping and

Screening Methodology Audit From June 21-24, 2004 (Accession No.

ML042660542)

NRC Audit Trip Report Regarding the PBNP LRA (TAC Nos. MC2099

and MC2100) (Accession No. ML042730603)

NMC Response to NRC Request for Additional Information Regarding the

PBNP LRA (TAC Nos. MC2099 and MC2100) (Accession No.

ML042940439)

NMC Response to NRC Request for Additional Information Regarding the

PBNP LRA (TAC Nos. MC2099 and MC21 00) (Accession No.

ML042990534)

Notice of October 28, 2004 Meeting with NMC to Discuss the Responses

to Requests for Additional Information in the License Renewal review for

PBNP (Accession No. ML042930124)

Summary of August 19, 2004 Telephone Conference Between NRC and

NMC Concerning Draft Requests for Additional Information Pertaining to

the PBNP LRA (TAC Nos. MC2099 and MC2100) (Accession No.

ML042990506)

NMC Response to NRC Request for Additional Information Regarding the

PBNP LRA (TAC Nos. MC2099 and MC2100) (Accession No.

ML043080122)

NRC Request for Additional Information for the Review of the PBNP LRA

(Accession No. ML043170663)

Summary of September 13, 2004 Telephone Conference Between NRC

and NMC Regarding Draft Requests for Additional Information Pertaining

to the PBNP LRA (Accession No. ML043170664)

B-4
November 16, 2004

November 16, 2004

November 16, 2004

November 17,2004

November 17, 2004

November 17, 2004

November 17, 2004

November 17, 2004

November 17, 2004

November 17,2004

November 18,2004

November 18, 2004

November 18,2004

November 18, 2004

November 22, 2004

NRC Request for Additional Information for the Review of the PBNP LRA

(Accession No. ML043270609)

Summary of October 26, 2004 Telephone Conference Between NRC and

NMC Concerning Draft Requests for Additional Information Pertaining to

the PBNP LRA (Accession No. ML043270587)

NRC Request for Additional Information for the Review of the PBNP LRA

(Accession No. ML043270539)

Summary of October 27, 2004 Telephone Conference Between NRC and

NMC Concerning Draft Requests for Additional Information Pertaining to

the PBNP LRA (Accession No. ML043270654)

NRC Request for Additional Information for the Review of the PBNP LRA

(Accession No. ML043270653)

Summary of November 17,2004 Between NRC and NMC Concerning

Draft Requests for Additional Information Pertaining to the PBNP LRA

(Accession No. ML043270652)

NRC Request for Additional Information for the Review of the PBNP LRA

(Accession No. ML043270651)

NRC Request for Additional Information for the Review of the PBNP LRA

(Accession No. ML043270650)

NRC Request for Additional Information for the Review of the PBNP LRA

(Accession No. ML043270647)

NRC Request for Additional Information for the Review of the PBNP LRA

(Accession No. ML043270644)

NRC Request for Additional Information for the Review of the PBNP LRA

(Accession No. ML043280582).

NRC Request for Additional Information for the Review of the PBNP LRA

(Accession No. ML043280552)

NRC Request for Additional Information for the Review of the PBNP LRA

(Accession No. ML043280488)

Summary of November 5, 2004 Telephone Conference Between NRC

and NMC Concerning Draft Requests for Additional Information

Pertaining to the PBNP LRA (Accession No. ML043270656)

Summary of October 28, 2004 Telephone Conference with NRC and

NMC Concerning Draft Requests for Additional Information Pertaining to

the PBNP LRA (Accession No. ML043280684)

B-5
December 14, 2004

December 16,2004

December 17,2004

December 17, 2004

December 17, 2004

December 20, 2004

December 21, 2004

December 21, 2004

December 21, 2004

December 21, 2004

December 22, 2004

December 22, 2004

January 6, 2005

NMC Response to NRC Request for Additional Information Regarding the

PBNP LRA (TAC Nos. MC2099 and MC21 00) (Accession No.

ML043570457)

Summary of December 15, 2004 Telephone Conference Between NRC

and NMC Concerning Draft Requests For Additional Information

Pertaining to the PBNP LRA (Accession No. ML050060167)

Summary of December 16, 2004 Telephone Conference Between NRC

and NMC Concerning Draft Requests for Additional Information

Pertaining to the PBNP LRA (Accession No. ML050060298)

NMC Response to NRC Request for Additional Information Regarding the

PBNP LRA (TAC Nos. MC2099 and MC21 00) (Accession No.

ML043620366)

NRC Request for Additional Information for the Review of the PBNP LRA

(Accession No. ML043560416)

Summary of December 17,2004 Telephone Conversation Between NRC

and NMC Concerning Draft Requests for Additional Information

Pertaining to the PBNP LRA (Accession No. ML050060357)

NMC Response to NRC Request for Additional Information Regarding the

PBNP LRA (TAC Nos. MC2099 and MC21 00) (Accession No.

ML043640289)

NRC Request for Additional Information for the Review of the PBNP LRA

(Accession No. ML043570510)

Summary of December 16, 2004 Telephone Conversation Between NRC

and NMC Concerning Draft Requests for Additional Information

Pertaining to the PBNP LRA (Accession No. ML043570282)

Summary of October 28, 2004 Telephone Conference Between NRC and

NMC Conceming Draft Requests for Additional Information Pertaining to

the PBNP LRA (Accession No. ML043570259)

NMC Response to NRC Request for Additional Information Regarding the

PBNP LRA (TAC Nos. MC2099 and MC2100) (Accession No.

ML050040178)

Summary of November 5, 2004 Telephone Conference Between NRC

and NMC Concerning Draft Requests for Additional Information

Pertaining to the PBNP LRA (Accession No. ML043570455)

NMC Response to NRC Request for Additional Information Regarding the

PBNP LRA (TAC Nos. MC2099 and MC21 00) (Accession No.

ML050180203)

B-6
January 7, 2005

January 10, 2005

January 10, 2005

January 12, 2005

January 13, 2005

January 17, 2005

January 19,2005

January 19,2005

January 19, 2005

January 19, 2005

January 19, 2005

January 19, 2005

January 19, 2005

NMC Response to NRC Request for Additional Information Regarding the

PBNP LRA (TAC Nos. MC2099 and MC2100) (Accession No.

ML050180271)

Summary of January 5, 2005 Telephone Conference Between NRC and

NMC Concerning Draft Requests for Additional Information Pertaining to

the PBNP LRA (Accession No. ML050130192)

NRC Request for Additional Information for the Review of the PBNP LRA

(Accession No. ML050110469)

NRC Request for Additional Information for the Review of the PBNP LRA

(Accession No. ML050130356)

NUREG-1 437, Supplement 23, Generic Environmental Impact Statement

for License Renewal of Nuclear Plants Regarding Point Beach Nuclear

Plant Units 1 and 2, Draft Report for Comment (Accession No.

ML050130187)

NMC Response to NRC Request for Additional Information Regarding the

PBNP LRA (TAC Nos. MC2099 and MC21 00) (Accession No.

ML050540591)

Summary of January 10, 2005 Telephone Conference Between NRC and

NMC Concerning Requests for Additional Information Pertaining to the

PBNP LRA (Accession No. ML050270046)

Summary of January 14, 2005 Telephone Conference Between NRC and

NMC Concerning Requests for Additional Information Pertaining to the

PBNP LRA (Accession No. ML050270037)

Summary of January 10, 2005 Telephone Conference Between NRC and

NMC Concerning Requests for Additional Information Pertaining to the

PBNP LRA (Accession No. ML050260699)

Summary of January 10, 2005 Telephone Conference Between NRC and

NMC Concerning Requests for Additional Information Pertaining to the

PBNP LRA (Accession No. ML050260636)

Summary of January 5, 2005 Telephone Conference Between NRC and

NMC Concerning Requests for Additional Information Pertaining to the

PBNP LRA (Accession No. ML050260585)

Summary of January 10, 2005 Telephone Conference Between NRC and

NMC Concerning Requests for Additional Information Pertaining to the

PBNP LRA (Accession No. ML050260473)

Summary of January 10, 2005 Telephone Conference Between NRC and

NMC Concerning Requests for Additional Information Pertaining to the

PBNP LRA (Accession No. ML050260435)

B-7
January 19, 2005

January 19,2005

January 19,2005

January 19, 2005

January 19,2005

January 19, 2005

January 19, 2005

January 19, 2005

January 19,2005

January 21, 2005

January 25,2005

January 25,2005

Summary of January 10,2005 Telephone Conference Between NRC and

NMC Concerning Requests for Additional Information Pertaining to the

PBNP LRA (Accession No. ML050260421)

Summary of January 10, 2005 Telephone Conference Between NRC and

NMC Concerning Requests for Additional Information Pertaining to the

PBNP LRA (Accession No. ML050260391)

Summary of January 10,2005 Telephone Conference Between NRC and

NMC Concerning Requests for Additional Information Pertaining to the

PBNP LRA (Accession No. ML050260359)

Summary of January 10, 2005 Telephone Conference Between NRC and

NMC Concerning Requests for Additional Information Pertaining to the

PBNP LRA (Accession No. ML050260353)

Summary of January 10, 2005 Telephone Conference Between NRC and

NMC Concerning Requests for Additional Information Pertaining to the

PBNP LRA (Accession No. ML050260319)

Summary of January 10, 2005 Telephone Conference Between NRC and

NMC Concerning Requests for Additional Information Pertaining to the

PBNP LRA (Accession No. ML050260303)

Summary of January 10, 2005 Telephone Conference Between NRC and

NMC Concerning Requests for Additional Information Pertaining to the

PBNP LRA (Accession No. ML050260247)

Summary of January 10, 2005 Telephone Conference Between NRC and

NMC Concerning Requests for Additional Information Pertaining to the

PBNP LRA (Accession No. ML050260237)

Summary of January 10, 2005 Telephone Conference Between NRC and

NMC Concerning Requests for Additional Information Pertaining to the

PBNP LRA (Accession No. ML050250436)

NMC Response to NRC Request for Additional Information Regarding the

PBNP LRA (TAC Nos. MC2099 and MC2100) (Accession No.

ML050330400)

NMC Response to NRC Request for Additional Information Regarding the

PBNP LRA (TAC Nos. MC2099 and MC2100) (Accession No.

ML050340201)

NMC Response to NRC Request for Additional Information Regarding the

PBNP LRA (TAC Nos. MC2099 and MC2100) (Accession No.

ML050340198)

B-8
January 25, 2005

January 25, 2005

January 26, 2005

January 26, 2005

January 28, 2005

January 28, 2005

January 31, 2005

February 4, 2005

February 7, 2005

February 7, 2005

February 23, 2005

February 23, 2005

February 25, 2005

March 3, 2005

March 4, 2005

NMC Response to NRC Request for Additional Information Regarding the

PBNP LRA (TAC Nos. MC2099 and MC2100) (Accession No.

ML050340169)

Summary of January 5, 2005 Telephone;Conference Between NRC and

NMC Concerning Requests for Additional Information Pertaining to the

PBNP LRA (Accession No. ML050270121)

NMC Response to NRC Request for Additional Information Regarding the

PBNP LRA (TAC Nos. MC2099 and MC2100) (Accession No.

ML050340166)

NRC Request for Additional Information for Review of the PBNP LRA

(Accession No. ML050260697)

NMC Response to NRC Request for Additional Information Regarding the

PBNP LRA (TAC Nos. MC2099 and MC21 00) and Request for

Withholding of Proprietary Information from Public Disclosure (Accession

No. ML050400483)

NMC Response to NRC Request for Additional Information Regarding the

PBNP LRA (TAC Nos. MC2099 and MC2100) (Accession No.

ML0504001 09)

NMC Response to NRC Request for Additional Information Regarding the

PBNP LRA (Accession No. ML050400134)

Notice of February 15, 2004 Meeting Between NRC and NMC To Discuss

the LRA for PBNP (Accession No. ML050350245)

NRC Confirmation of Information Verbally Provided to NRC Regarding

the PBNP LRA (TAC Nos. MC2099 and MC2100) (Accession No.

ML050460279)

NRC Request for Additional Information for the Review of the PBNP LRA

(Accession No. ML050380148)

NRC Request for Additional Information for Review of the PBNP LRA

(Accession No. ML050540542)

NMC Amendment to the PBNP LRA (Accession No. ML050610283)

NMC Response to Request for Additional Information Regarding the

PBNP LRA (Accession No. ML050670488)

Summary of February 15,2005 Meeting Between NRC and NMC to

Discuss PBNP LRA (Accession No. ML050620498)

NMC Information Regarding the PBNP LRA (TAC Nos. MC2099 and

MC2100) (Accession No. ML050740128)

B-9
March 4, 2005

March 15,2005

March 15,2005

March 24,2005

March 24, 2005

March 29, 2005

March 30, 2005

March 31, 2005

April 1, 2005

April 8,2005

April 11, 2005

April 15, 2005

April29, 2005

April 29, 2005

May 2, 2005

NMC Response to Request for Additional Information Regarding the

PBNP LRA (TAC Nos. MC2099 and MC21 00) (Accession No.

ML050740122)

NMC Clarification to Information Regarding the PBNP LRA (TAC Nos.

MC2099 and MC21 00) (Accession No. ML050840432)

NMC Response to Request for Additional Information Regarding the

PBNP LRA (TAC Nos. MC2099 and MC2100) (Accession No.

ML050840431)

Public Meeting to Discuss the NRC's License Renewal Inspection at

PBNP (Accession No. ML050840198)

Notice of Significant Licensee Meeting with NMC to Discuss Results of

Scoping, Screening and Aging Management License Renewal Inspection

at PBNP (Accession No. ML050840175)

NRC Request for Additional Information for the Review of the PBNP LRA

(Accession No. ML050880194)

NRC Request for Additional Information for the Review of the PBNP LRA

(TAC Nos. MC2099 and MC21 00) (Accession No. ML050890003)

NRC Request for Additional Information for the Review of the PBNP LRA

(TAC Nos. MC2099 and MC2100) (Accession No. ML050910217)

NMC Response to Request for Additional Information Regarding the

PBNP LRA (Accession No. ML051020357)

Clarification to Information Regarding the PBNP LRA (Accession No.

ML051090337)

Audit and Review Report for Plant Aging Management Reviews and

Programs, PBNP, Units 1 and 2, Revision 1 (Accession No.

ML051020288)

Summary of March 31, 2005 Telephone Conference Between NRC and

NMC Regarding to PBNP LRA (Accession No. ML051050312)

NMC Response to Request for Additional Information Regarding the

PBNP LRA (Accession No. ML051300349)

Clarification to Information Regarding the PBNP LRA (Accession No.

ML051300355)

Letter from NRC to D. Koehl Regarding the SER with Open Items

Related to License Renewal at PBNP, Units 1 and 2 (Accession No.

ML051230024)

B-10
May 2, 2005

May 2, 2005

May 25, 2005

May 31, 2005

June 9, 2005

June 9, 2005

June 10, 2005

June 13, 2005

June 16, 2005

June 16, 2005

June 29, 2005

June 29, 2005

July 5, 2005

July 7, 2005

Draft Safety Evaluation Report related to PBNP, Units 1 and 2 (Accession

No. ML051190124)

Point Beach Nuclear Plant, Units 1 and 2, NRC License Renewal

Scoping, Screening, and Aging Management Inspection Report

(05000266/2005005 (DRS), 05000301/2005005(DRS)) (Accession No.

ML051220260)

NRC Press Release-05-084: NRC Advisory Committee on Reactor

Safeguards to Meet on June 1-3 in Rockville, Maryland (Accession No.

ML051450211)

Transcript of Advisory Committee on Reactor Safeguards Plant License

Renewal Subcommittee meeting, May 31, 2005 in Rockville, Maryland

(Accession No. ML051710223)

Letter from Graham B. Wallis, ACRS, to Luis A. Reyes, EDO,

Regarding the Interim Report on the Safety Aspects of the PBNP LRA

(G20050428) (Accession No. ML051680321)

NMC Response to Request for Additional Information Regarding the

PBNP LRA (Accession No. ML051680493)

NMC Response to SER with Open Items Regarding the PBNP LRA

(Accession No. ML051720463)

Summary of March 3, 2005 Telephone Conference between NRC and

NMC (Accession No. ML051650002)

Summary of May 26, 2005 Telephone Conference Between the NRC and

NMC Regarding Open and Confirmatory Items (Accession No.

ML-051680050)

Summary of May 28, 2005 Telephone Conference Between the NRC and

NMC Regarding Draft Requests for Additional Information for PBNP

(Accession No. ML051680452) -

Final Update Information Regarding the PBNP LRA (Accession No.

ML051890055)

Clarification to Information Regarding PBNP LRA (Accession No.

ML051 890064)

NNMC Response to Request for Additional Information Regarding the

PBNP LRA (Accession No. ML051940355)

Certification of the Minutes of the Plant License Renewal Subcommittee

Meeting on the PBNP LRA, May 31, 2005 in Rockville, Maryland

(Accession No. ML052150202)

B-i 1
July 8, 2005

July 15, 2005

July 15,2005

July 19, 2005

July 27, 2005

August 12, 2005

August 23, 2005

September 9, 2005

September 23, 2005

September 27, 2005

October 1, 2005

November 18, 2005

Clarification to Information Regarding the PBNP LRA (Accession No.

ML052020233)

Letter from Luis A. Reyes, EDO, to Graham B. Wallis, ACRS, Regarding

the Response to Interim Report on the Safety Aspects of the PBNP LRA

(G20050428) (Accession No. ML051860393)

Enclosure to response to Advisory Committee on Reactor Safeguards,

NRC Action, Under the Reactor Oversight Process for the PBNP, Units 1

and 2 (G20050428) (Accession No. ML051860398)

Clarification to Information Regarding the PBNP LRA (TAC Nos. MC2099

and MC21 00) (Accession No. ML052080144)

Summary of June 30, 2005 and July 8,2005, Telephone Conferences

Between NRC and NMC Regarding Confirmatory Items (Accession No.

ML052100254)

NUREG-1437 Supplement 23, Generic Environmental Impact Statement

for License Renewal of Nuclear Plants, Supplement 23 Regarding Point

Beach Nuclear Plant, Units 1 and 2, Final Report (Accession No.

ML052230490)

Additional Information Regarding the PBNP LRA (TAC Nos. MC2099 and

MC2100) (Accession No. ML052440350)

Point Beach Nuclear Plant, Units 1 and 2, NRC License Renewal

Followup Inspection Report (05000266/2005015 (DRS),

05000301/2005015(DRS)) (Accession No. ML0525602640)

Docketing of Additional Information Pertaining to LRA of the PBNP, Units

1 and 2 (Accession Package No. ML052630524)

Summary of August 10, 2005 Telephone Conference Between NRC and

NMC Concerning Comments to the PBNP, Units 1 and 2, Draft Safety

Evaluation Report (Accession No. ML052700508)

Letter from Mr. P.T. Kuo, NRC, to Mr. Dennis L. Koehl, NMC, regarding

the Safety Evaluation Report (SER) Related to the License Renewal of

Point Beach Nuclear Plant, Units 1 and 2 (TAC Nos. MC2099 and

MC2100) (Accession No. ML052760238)

Letter from Dr. Graham B. Wallis, ACRS, to the Honorable Nils J. Diaz,

NRC Chairman, regarding the Report on the Safety Aspects of the

License Renewal Application for the Point Beach Nuclear Plant Units 1

and 2 (Accession No. ML053250548)

B-12
APPENDIX C

REQUESTS FOR ADDITIONAL INFORMATION

' Section I dGeneDiscussion i

Section 2: Scoping and Sredeni Wethodogy for Identifying StructuCresandponents

Subject to rtoAg etnetew.andI nt Results

2.1 Scoping and Screening Methodology

RAI 2.1-1 November 16, 2004 January 31, 2005

March 15, 2005

April 29, 2005

July 19, 2005

RAI 2.1-2 November 16, 2004 January 31, 2005

RAI 2.1-3 November 16, 2004 January 31, 2005

March 15, 2005

2.2 Plant Level Scoping Results

2.3 Scoping and Screening Results: Mechanical Systems

2.3.1 Reactor Vessel, Internals, and Reactor Coolant System

2.3.1.1 Class 1 Piping/Components System -

RAI 2.3.1.1-1, November 17,2004 December 21, 2004

2.3.1.2 Reactor Vessel

RAI 2.3.1.2-1 November 17, 2004 December21, 2004

2.3.1.3 Reactor Vessel Internals

2.3.1.4 Pressurizer

RAI 2.3.1.4-1 - - November 17, 2004 December?1, 2004

RAI 2.3.1.4-2 November 17, 2004 1Pcember , 2004

2.3.1.5 Steam Generators

2.3.1.6 Non-Class 1 RCS Component Systems -

2.3.2 Engineered Safety Features

C-1
equ4br F Mditionalinfo(

2.3.2.1 Safety Injection System

2.3.2.2 Containment Spray System

2.3.2.3 Residual Heat Removal System

2.3.2.4 Containment Isolation Components Systems

2.3.3 Auxiliary Systems

2.3.3.1 Chemical and Volume Control System

2.3.3.2 Component Cooling Water System

RAI 2.3.3.2-1 November 10,2004 December 14, 2004

2.3.3.3 Spent Fuel Cooling System

RAI 2.3.3.3-1 November 10, 2004 December 14, 2004

RAI 2.3.3.3-2 j November 10, 2004 December 14, 2004

2.3.3.4 Waste Disposal System

RAI 2.3.3.4-1 November 16, 2004 December 22, 2004

RAI 2.3.3.4-2 November 16,2004 December 22,2004

RAI 2.3.3.4-3 November 16,2004 December 22, 2004

RAI 2.3.34-4 -November 16,2004 December 22,2004

2.3.3.5 Service Water System

RAI 2.3.3.5-1 November 10,2004 December 14,2004

RAI 2.3.3.5-2 November 10,2004 December 14,2004

RAI 2.3.3.5-3 November 10,2004 December 14,2004

RAI 2.3.3.5-4 November 10, 2004 December 14,2004

RAI 2.3.3.5-5 November 10, 2004 December 14, 2004

2.3.3.6 Fire Protection System

RAI 2.3.3.6-1 September 10, 2004 October 8,2004

RAI 2.3.3.6-2 September 10, 2004 October 8, 2004

RAI 2.3.3.6-3 September 10, 2004 October 8, 2004

RAI 2.3.3.6-4 September 10, 2004 October 8, 2004

RAI 2.3.3.6-5 September 10, 2004 October 8, 2004

C-2
14 MR M olun0at~ {RM ~sos a&

vow v.

RAI 2.3.3.6-6 September 10, 2004 October 8,2004

RAI 2.3.3.6-7 September 10,2004 October 8, 2004

RAI 2.3.3.6-8 September 10, 2004 October 8, 2004

RAI 2.3.3.6-9 September 10, 2004 October 8, 2004

RAI 2.3.3.6-10 September 10, 2004 October 8,2004

RAI 2.3.3.6-11 September 10, 2004 October 8, 2004

RAI 2.3.3.6-12 September 10, 2004 October 8, 2004

RAI 2.3.3.6-13 September 10, 2004 October 8, 2004

2.3.3.7 Heating Steam System -Within Scope of License Renewal for Criterion 2 Only

RAI 2.3.3.7-1 November 10, 2004 December 14, 2004

2.3.3.8 Emergency Power System

RAI 2.3.3.8-1 November 16,2004 December 22, 2004

RAI 2.3.3.8-2- November 16,2004 December 22,2004

RAI 2.3.3.8-3 November 16,2004 December 22,2004

February 7, 2005

RAI 2.3.3.8-4 November 16, 2004 December 22, 2004

RAI 2.3.3.8-5 November 16,2004 December 22,2004

2.3.3.9 Containment Ventilation System i

RAI 2.3.3.9 November 17, 2004 | December 17,2004

2.3.3.10 Essential Ventilation System

RAI 2.3.3.10 November 17,2004 December 17,2004

RAI 2.3.3.10-1 December 17, 2004 January 17,2005

2.3.3.11 Treated Water System - Within Scope of License Renewal for Criterion 2 Only

RAI 2.3.3.1-1 November 10, 2004 December 14, 2004

RAI 2.3.3.11-2 November 10, 2004 December 14,2004

2.3.3.12 Circulating Water System - Within Scope of License Renewal for Criterion 2 Only

RAI 2.3.3.12-1 J November 10, 2004 December 14, 2004

RAI 2.3.3.12-2 November 10, 2004 December 14, 2004

C-3
M~ ~ QII -- ~~ques~forA~iditlpWiAW 4MmtonMy 1sOcpaR4 I po-~Dt

2.3.3.13 Fuel Handling System

2.3.3.14 Plant Sampling System

2.3.3.15 Plant Air System

RAI 2.3.3.15-1 November 16,2004 December 22,2004

RAI 2.3.3.15-2 November 16, 2004 December 22, 2004

RAI 2.3.3.15-3 November 16,2004 December 22, 2004

2.3.3.16 Containment Hydrogen Detectors and Recombiner System

2.3.4 Steam and Power Conversion System

2.3.4.1 Main and Auxiliary Steam System

2.3.4.2 Feedwater and Condensate System

RAI 2.3.4.2-1 November 16,2004 December 22,2004

RAI 2.3.4.2-2 November 16, 2004 December 22, 2004

RAI 2.3.4.2-3 November 16,2004 December 22,2004

RAI 2.3.4.2-4 January 10,2005 January 26, 2005

March 15, 2005

2.3.4.3 Auxiliary Feedwater System

RAI 2.3.4.3-1 November 16, 2004 December 22, 2004

RAI 2.3.4.3-2 November 16, 2004 December 22, 2004

RAI 2.3.4.3-3 November 16, 2004 December 22, 2004

2.4 Scoping and Screening Results: Containments, Structures, and Component Supports

RAI 2.4-1 January 26, 2005 February 25, 2005

RAI 2.4-2 January 26, 2005 February 25, 2005

June 10, 2005

June 29, 2005

RAI 2.4-3 January 26, 2005 February 25, 2005

RAI 2.4-4 January 26, 2005 February 25, 2005

RAI 2.4-5 January 26, 2005 February 25, 2005

RAI 2.4-6 January 26,2005 February 25,2005

C-4
onari. Da

RAI 2.4-7 January 26, 2005 February 25, 2005

RAI 2.4-8 January 26, 2005 February 25, 2005

RAI 2.4-9 January 26, 2005 February 25, 2005

RAI 2.4-10 January 26, 2005 February 25, 2005

RAI 2.4-11 January 26, 2005 February 25, 2005

RAI 2.4-12 January 26, 2005 February 25, 2005

RAI 2.4.11-1 September 10, 2004 October 8, 2004

2.5 Scoping and Screening Results: Electrical and Instrumentation and Controls

RAI 2.5.1 - November 18, 2004 January 25, 2005

:lSecd 3: A Management Review eu

3.1 Aging Management of Reactor Coolant System

RAI 3.1.2-1 November 17, 2004 January 25, 2005

RAI 3.1.2-2 November 17,2004 January 25, 2005

RAI 3.1.2-3 November 17,2004 January 25, 2005

RAI 3.1.2-4 November 17,2004 January 25, 2005

RAI 3.1.2-5 November 17,2004 January 25, 2005

RAI 3.1-1 November 18, 2004 January 6, 2005

RAI 3.1-2 November 18,2004 January 6, 2005

RAI 3.1-3 November 18, 2004 January 6, 2005

RAI 3.1-4 November 18, 2004 January 6, 2005

RAI 3.1-5 November 18, 2004 January 6, 2005

RAI 3.1-6 November 18, 2004 January 6, 2005

RAI 3.1.1-1 March 30, 2005 June 9,2005

RAI 3.1.1-2 March 30, 2005 June 9, 2005

3.2 Aging Management of Engineered Safety Features

RAI 3.2-1 July 30, 2004 August 30, 2004

RAI 3.2-2 July 30, 2004 August 30, 2004

C-5
3.3 Aging Management of Auxiliary Systems

RAI 3.3-1 November 18, 2004 January 7, 2005

RAI 3.3-2 November 18,2004 January 7,2005

RAI 3.3-3 November 18, 2004 January 7, 2005

RAI 3.3-4 November 18, 2004 January 7, 2005

RAI 3.3-5 November 18, 2004 January 7, 2005

RAI 3.3-6 November 18, 2004 January 7, 2005

March 15, 2005

RAI 3.3-7 March 31, 2005 April 29,2005

June 10, 2005

RAI 3.3.2.1.6-1 September 10, 2004 October 8, 2004

._ March 15, 2005

3.4 Aging Management of Steam and Power Conversion System

RAI 3.4-1 J July 30, 2004 August 30, 2004

RAI 3.4-2 l July 30, 2004 August 30, 2004

3.5 Aging Management of Containments, Structures, and Component Supports

RAI 3.5-1 July 27, 2004 August 26,2004

RAI 3.5-2 July 27, 2004 August 26,2004

RAI 3.5-3 July 27, 2004 August 26, 2004

RAI 3.5-4 July 27, 2004 August 26, 2004

March 15,2005

June 10, 2005

._ July 8, 2005

RAI 3.5-5 July 27, 2004 August 26, 2004

March 15,2005

RAI 3.5-6 July 27, 2004 August 26, 2004

RAI 3.5-7 July 27, 2004 August 26,2004

RAI 3.5-8 July 27, 2004 August 26, 2004

C-6
RAI 3.5-9 July 27, 2004 August 26, 2004

RAI 3.5-10 July 27, 2004 August 26, 2004

RAI 3.5-11 July 27, 2004 August 26, 2004

RAI 3.5-12 March 30, 2005 June 9, 2005

RAI 3.5-13 March 30, 2005 June 9, 2005

RAI 3.5-14 March 31, 2005 April 29,2005

3.6 Aging Management of Electrical and Instrumentation and Controls

RAI 3.6.2.1.1 November 18, 2004 January 25, 2005

RAI 3.6.2.1.2 November 18, 2004 January 25, 2005

RAI 3.6.2.1.3 November 18, 2004 January 25, 2005

March 15, 2005

RAI 3.6.2.1.4 November 18, 2004 January 25, 2005

RAI 3.6.2.1.5 November 18,2004 January 25, 2005

RAI 3.6.2.1.6 November 18, 2004 January 25, 2005

RAI 3.6.2.-1.7 November 18, 2004 January 25, 2005

Sei7a ona4: Time Lited g Analysi

4.1 Identification of Time-Limited Aging Analyses

RAI 4.1.1-1 JNovember 17, 2004 January 25,2005

RAI 4.1.1-2 | November 17, 2004 January 25, 2005

4.2 Reactor Vessel Irradiation Embrittlement

RAI 4.2-1 September 23, 2004 September 10, 2004

October 25, 2004

RAI 4.2-2 September 23, 2004 September 10, 2004

October 25, 2004

4.3 Metal Fatigue

4.3.1 Reactor Vessel Structural Integrity

RAI 4.3.1 November 17, 2004 January 28, 2005

C-7
4.3.2 Reactor Vessel Internals Structural Integrity

RAI 4.3.2.1 November 17,2004 | January 28,2005

RAI 4.3.2.2 November 17, 2004 January 28, 2005

4.3.3 Control Rod Drive Mechanism Structural Integrity

RAI 4.3.3 November 17, 2004 l January 28, 2005

4.3.4 Steam Generator Structural Integrity :

RAI 4.3.4.1 November 17,2004 January 28,2005

RAI 4.3.4.2 November 17, 2004 January 28,2005

RAI 4.3.4.3 November 17,2004 January 28,2005

4.3.5 Pressurizer Structural Integrity

RAI 4.3.5.1 November 17, 2004 January 28, 2005

RAI 4.3.5.2 November 17, 2004 January 28, 2005

RAI 4.3.5.3 November 17, 2004 January 28, 2005

RAI 4.3.5.4 November 17,2004 January 28,2005

RAI 4.3.5.5 November 17, 2004 January 28,2005

4.3.6 Reactor Coolant Pump Structural Integrity

4.3.7 Pressurizer Surge Line Structural Integrity

RAI 4.3.7 November 17, 2004 January 28,2005

4.3.8 Pressurizer Spray Header Piping Structural Integrity

RAI 4.3.8 lNovember 17,2004 lJanuary 28,2005

4.3.9 USAS B31.1 Piping Structural Integrity

4.3.10 Environmental Effects on Fatigue

RAI 4.3.10.1 November 17, 2004 January 28,2005

RAI 4.3.10.2 November 17, 2004 January 28,2005

4.3.11 Containment Liner Plate Fatigue Analysis

4.3.12 Spent Fuel Pool Liner Fatigue Analysis

4.3.13 Crane Load Cycle Limits

RAI 4.3.13-1 November 18, 2004 | January 7,2005

C-8
Q giBRAM

- ~ otAM Date *

4.4 Fracture Mechanics Analysis

4.4.1 Reactor Vessel Underclad Cracking

4.4.2 Reactor Coolant Pump Flywheel Analysis

RAI 4.4.2 1November 17, 2004 January 25, 2005

4.4.3 Reactor Coolant Pump Casing Analysis (ASME Code Case N-481 Analysis)

Section withdrawn March 4, 2005

4.4.4 Reactor Coolant System Main Loop Piping Leak-Before-Break Analysis

4.4.5 Pressurizer Surge Line Piping Leak-Before-Break Analysis

4.4.6 Class I Accumulator Injection Line Piping Leak-Before-Break Analysis

4.4.7 Class 1 RHR Line Piping Leak-Before-Break Analysis.

4.4.8 Component/Piping Subsurface Indication Analysis

Section withdrawn FMarch 4, 2005

4.5 Loss of Preload

RAI 4.5-1 July 27, 2004 August 26, 2004

_____ _____ ____ March 15, 2005

RAI 4.5-2 July 27, 2004 August 26, 2004

March 15,2005

4.6 Neutron Absorber________

RAI 4.6.1 -1 March 29, 2005 April 1, 2005

RAI 4.6.1-2 March 29, 2005 April 1, 2005

RAI 4.6.1-3 March 29, 2005 April 1, 2005

4.7 Wear

4.7.1 Bottomn Mounted Instrumentation Thimble Tube Wear

4.7.2 Containment Accident Recirculation Heat Exchanger Tube Wear

Section withdrawn March 4, 2005

4.8 Environmental Qualification

Appendix B; Aging Management Programs and Activities

B.1.1 Overview

C-9
| B.1.2 Method of Discussion

B.1.3 Quality Assurance Program and Administrative Controls

B.1.4 Operating Experience

B. 1.5 Aging Management Programs

B.1.6 Time Limited Aging Analyses Aging Management Programs

B.2 Aging Management Programs Correlation

B.2.1 Aging Management Programs Details

RAI B.2.1 March 30,2005 July 5, 2005

B.2.1.1 ASME Section Xl, Subsections IWB, IWC, and IWD Inservice Inspection Program

B.2.1.2 ASME Section Xl, Subsections IWE & IWL Inservice Inspection Program

B.2.1.3 ASME Section Xl, Subsections IWF Inservice Inspection Program

B.2.1.4 Bolting Integrity Program

RAI B.2.1.4-1 February 7,2005 March 4,2005

RAI B.2.1.4-2 February 7,2005 March 4, 2005

April 8,2005

July 19,2005

RAI B.2.1.4-3 February 7,2005 March 4,2005

RAI B.2.1.4-4 February 7,2005 March 4,2005

RAI B.2.1.4-5 February 7, 2005 March 4,2005

RAI B.2.1.4-6 February 23,2005 March 15,2005

B.2.1.5 Boraflex Monitoring Program

RAI B.2.1.5-1 February 23,2005 March 15,2005

RAI B.2.1.5-2 February 23,2005 March 15,2005

RAI B.2.1.5-3 February 23,2005 March 15,2005

RAI B.2.1.5-4 February 23, 2005 March 15,2005

B.2.1.6 Boric Acid Corrosion Program

RAI B.2.1.6-1 November 17,2004 January 25, 2005

C-b10
Reqde¶r Additions nizn

B.2.1.7 Buried Services Monitoring Program

RAI B.2.1.7-1 November 18,2004 January 6,2005

March 15,2005

RAI B.2.1.7-2 November 18,2004 January 6,2005

RAI B.2.1.7-3 November 18, 2004 January 6,2005

B.2.1.8 Cable Condition Monitoring Program

,RAI B.2.1.8-1 December 21, 2004 January 21, 2005

March 15,2005

B.2.1.9 Closed-Cycle Cooling Water System Surveillance Program

B.2.1.10 Fire Protection Program

B.2.1.11 Flow-Accelerated Corrosion Program

RAI B.2.1.11-1 March 30, 2005 April 8,2005

June 9, 2005

B.2.1.12 Fuel Oil Chemistry Control Program

B.2.1.13 One-Time Inspection Program

RAI B.2.1.13-1 I September 16,2004 October 15,2004

B.2.1.14 Open-Cycle Cooling (Service) Water System Surveillance Program

B.2.1 .15 Periodical Surveillance and Preventive Maintenance Program

B.2.1.16 Reactor Coolant System Alloy 600 Inspection Program

RAI 2.1.16-1 November 17,2004 January 25, 2005

RAI 2.1.16-2 November 17,2004 January 25,2005

B.2.1.17 Reactor Vessel Internals Program

B.2.1.18 Reactor Vessel Surveillance Program

RAI B2.1.18-1 November 17,2004 January 25,2005

B.2.1.19 Steam Generator Integrity Program

B.2.1.20 Structures Monitoring Program

5.2.1.21 Systems Monitoring Program

C-11
tti g m- l a r e 6 ~eqe;oWd i ioU(4) 4tsiac& t~ asaIIn 4~c4 Po~& Ie 4

B.2.1.22 Tank Internal Inspection Program

RAI B.2.1.22-1 November 18, 2004 January 6, 2005

RAI B.2.1.22-2 November 18, 2004 January 6,2005

RAI B.2.1.22-3 November 18, 2004 January 6, 2005

RAI B.2.1.22-4 November 18, 2004 January 6,2005

B.2.1.23 Thimble Tube Inspection Program

RAI B.2.1.23-1 November 17,2004 January 25,2005

B.2.1.24 Water Chemistry Control Program

B.3 TLAA Support Activities

B.3.1 Environmental Qualification Program

B.3.2 Fatigue Monitoring Program

B.3.3 Pre-Stressed Concrete Containment Tendon Surveillance Program

RAI B.3.3-1 January 12, 2005 January 28,2005

March 15,2005

RAI B.3.3-2 January 12,2005 January 28, 2005

March 15,2005

RAI B.3.3-3 January 12,2005 January 28,2005

March 15,2005

RAI B.3.3-4 January 12,2005 January 28, 2005

March 15,2005

Section withdrawn March 15,2005

C-12
APPENDIX D

PRINCIPAL CONTRIBUTORS

'NAME R ESPONSIBILT

F. Akstulewicz Management Oversight

H. Ashar Structural Engineering

J. Ayala SER Support

W. Bateman Management Oversight

S. Black Management Oversight

B. Boger Management Oversight

J. Calvo Management Oversight

T. Chan Management Oversight

K. Chang GALL Audit and Review

T. Cheng Mechanical Engineering

H. Chernoff Project Management

S. Coffin Management Oversight

K. Cozens GALL Audit and Review

R. Denning Management Oversight

Y. Diaz SER Support

B. Elliot Material Engineering

G. Galletti Quality Assurance

A. Gill Electrical Engineering

J. Hannon Management Oversight

M. Hartman Mechanical Engineering

A. Hodgdon Legal Counsel

K. Hsu GALL Audit and Report

G. Imbro Management Oversight

N. lqbal - Mechanical Engineering

D-1
NAME RESOSIBIUTY S 

R. Jenkins Management Oversight

D. Jeng Mechanical Engineering

S. Jones Management Oversight

T. Koshy Electrical Engineering

P. Kuo Management Oversight

C. Lauron Material Engineering

A. Lee Mechanical Engineering

S. Lee Management Oversight

C. Li Plant Systems

M. Li SER Support

Y. Li Mechanical Engineering

M. Untz GALL Audit and Review

P. Lougheed Region IlI Inspection

L. Lund Management Oversight

J. Ma Mechanical Engineering

K. Manoly Management Oversight

D. Matthews Management Oversight

M. Mayfield Management Oversight

R. McIntyre Quality Assurance

L. Miller Materials Engineering

M. Mitchell Management Oversight

M. Morgan Project Manager

M. Murphy Mechanical Engineering

B. Poole Legal Counsel

J. Pulsipher Containment Systems

J. Rajan Mechanical Engineering

J. Raval Mechanical Engineering

N. Ray Nuclear Engineering

D-2
NAME RESPONSIIBILITYW.-

M. Razzaque Mechanical Engineering

D. Reddy Mechanical Engineering

V. Rodriguez Project Manager

D. Solorio Management Oversight

T. Steingass Materials Engineering

J. Strnisha Mechanical Engineering

G. Suber Project Manager

F. Talbot Quality Assurance

D. Terao Management Oversight

D. Thatcher Management Oversight

L. Tran GALL Audit and Review

M. Tschiltz Management Oversight

S. West Management Oversight

S. Weerakkody Management Oversight

CONTRACTORS

CONTtRACTOR tECHNICALAREA

Legin Group, Inc. SER Support

Pacific Northwest National Containment Systems/Plant

Laboratory Systems/GALL Audit

D-3
APPENDIX E

REFERENCES

This appendix contains a listing of references used in preparation of the Safety Evaluation

Report prepared during the review of the license renewal application for Point Beach Nuclear

Plant Units 1 and 2, Docket Numbers 50-266 and 50-301 respectively.

Section 2 References

(1) NUREG-1 800, "Standard Review Plan for Review of License Renewal Applications for

Nuclear Power Plants," April 2001

(2) NEI 95-10, Industry Guideline for Implementing the Requirements of 10 CFR Part 54 -

The License Renewal Rule, Revision 3," August 2001

(3) NUREG-1 801, -Generic Aging Lessons Learned Report (GALL)," April 2001

(4) Nuclear Management Company, LLC, License Renewal Application for PBNP Units 1

and 2, February 25, 2004

(5) LR-TR-517-IMPLAN, Rev.0, "Implementation Plan for License Renewal,"

January 7, 2004

(6) LR-TR-505-QAPELE, Rev.0, "Evaluation of Quality Assurance Program Elements for

License Renewal," December 18, 2003

(7) 2002 Informal Self-Assessment of the License Renewal Project for PBNP, Rev.3,

December 18,2003

(8) Nuclear Oversight Observation Report No. 2002-003-3-006, "Status of License Renewal

Application Project," September 30, 2002

(9) Nuclear Oversight Observation Report No. 2003-002-3-036, "License Renewal Project,"

June 18,2003

(10) Plant Operations Review Committee Meeting Notes, PORC 2004, February 9, 2004

(11) Plant Operations Review Committee Meeting Notes, PORC 2004-008,

February 16,2004

(12) Change Management Plan CMP No. 2004-01, Rev.0, "PBNP Implementation of a

Renewed License," January 15, 2004

(13) NP 7.7.9, Rev.3, "Facilities Monitoring Program," June 18, 2003

(14) Facilities Monitoring Program Annual Report - 2002, January 31, 2003

(15) Facilities Monitoring Program Annual Report - 2003, January 30, 2004

E-1
(16) Followup Action Item Reports 15, 16, and 17, Supplement, Facilities Monitoring

Program, April 11, 2002

(17) Followup Action Item Report 18, Supplement, Facilities Monitoring Program,

April 12, 2002

(18) Followup Action Item Report 22, Facilities Monitoring Program, May 1, 2002

(19) LR-TR-508, Rev.1, "Integrated Plant Assessment Methodology Report"

(20) LR-TR-514, Rev.0, uCriterion 2 Scoping Methodology and Results"

(21) LRPP 1-1, "License Renewal Project," Revision 8, April 23, 2004

(22) LRPP 2-1, "Scoping and Screening for License Renewal," Revision 4,

December 16, 2003

(23) LRPP 2-2, "Mechanical Aging Management Review for License Renewal," Rev. 4,

July 30, 2002

(24) LRPP 2-3, "Civil Aging Management Review for License Renewal," Revision 4,

July 30,2004

(25) LRPP 2-4, "Electrical Aging Management Review for License Renewal," Revision 4,

July 30,2002

(26) LRPP 2-5, "Time Limited Aging Analysis for License Renewal," Revision 2,

March 28, 2002

(27) Design Basis Document (DBD)-07, "Main Steam and Steam Dump System," Revision 3,

May 17,2004

(28) PBNP Technical Specification 3.7.1 and 3.7.3

(29) LR-SCOPE-616, License Renewal Scoping Report, "Main and Auxiliary Steam,"

Revision 1, October 22, 2003

(30) LR-SCRN-716, License Renewal Screening Report, "Main and Auxiliary Steam,"

Revision 0, August 6, 2003

(31) License Renewal Drawings, "Main and Reheat Steam System," LR-M-2201, Sheets 1

and 3, LR-M-201, Sheets 1 and 3

(32) License Renewal Drawings, "Radwaste Steam Supply," LR-PBM-227

(33) Design Basis Document (DBD)-1 6, "Emergency Diesel Generator System," Revision 4,

April 30,2004

(34) Design Basis Document (DBD)-1 8, "13.8 KVAC," Revision 2, May 22, 2003

E-2
(35) Technical Specification 3.3.4, 3.8.1, 3.8.2, and 3.8.3

(36) LR-SCOPE-631, Revision 0, License Report Scoping Report, "Emergency Power,"

June 11, 2003

(37) LR-SCRN-722, License Renewal Screening Report, "Emergency Power," Revision 1,

October 22, 2003

(38) License Renewal Drawings, "Emergency Power System," LR-M-209, Sheets 12, 14, and

15, LR-M-219, Sheets 1, 2, and 3, LR-M-226, Sheets 1 and 2, MKW-6090F03001,

Sheet 1, MKW-6090F04001, Sheet 1, and Figures 12.2.3,12.2.4,12.2.5,12.2.6 (GT

TM)

(39) 10 CFR Part 54, "Requirements for Renewal of Operating Licenses for Nuclear Power

Plants"

(40) Nuclear Energy Institute (Alan Nelson) letter to the NRC (Christopher I. Grimes),

March 19,2002

(41) 10 CFR 50.63, Loss of All Altemating Current Power

Section 3 References

(42) NRC Order EA-03-009, "Issuance of Order Establishing Interim Inspection

Requirements for Reactor Pressure Vessel Heads at Pressurized Water Reactors,"

February 11, 2003

(43) NRC Order EA-03-009, "The First Revised NRC Order EA-03-009," February 20,2004

(44) NRC Bulletin BL 2002-01, "Reactor Pressure Vessel Head Degradation and Reactor

Coolant Pressure Boundary Integrity," March 18, 2002

(45) NRC Bulletin BL 2003-02, "Leakage From Reactor Pressure Vessel Lower Head

Penetrations and Reactor Coolant Pressure Boundary Integrity," August 21, 2003

(46) NRC Bulletin 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," May 28,2004

(47) NRC Generic Letter GL 88-05, "Boric Acid Corrosion of Carbon Steel Reactor Pressure

Boundary Components in PWR Plants," March 17,1988

(48) NRC Regulatory Issue Summary 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

(49) NUREG-1 800, "Standard Review Plan for Review for License Renewal Applications for

Nuclear Power Plants," July 2001

(50) NUREG 1801, "Generic Aging Lessons Learned (GALL) Report," July 2001

E-3
(51) NUREG/CR-5576, "Survey of Boric Acid Corrosion of Carbon Steel Components in

Nuclear Plants," June 1990

(52) Nuclear Management Company, LLC, Letter No. NRC 2004-0071, License Renewal

Application Clarifications Point Beach Nuclear Plant, Units 1 and 2, July 12, 2004

(53) Westinghouse Document, WCAP-14577, Revision 1, "License Renewal Evaluation:

Aging Management for Reactor Internals," October 2000

(54) 10 CFR 50.60, Acceptance Criteria for Fracture Prevention Measures for Light Water

Nuclear Power Reactors for Normal Operations

(55) 10 CFR 50.61, Fracture Toughness Requirements for Protection Against Pressurized

Thermal Shock Events

(56) 10 CFR Part 50, Appendix G, Fracture Toughness Requirements

(57) 10 CFR Part 50, Appendix H, Reactor Vessel Material Surveillance Program

Requirements

(58) NRC Generic Letter GL 92-01, Revision 1, Supplement 1, 'Reactor Vessel Structural

Integrity," May 19, 1995

(59) NRC Regulatory Guide RG 1.99, Revision 2, "Radiation Embrittlement of Reactor

Vessel Materials," May 1988

(60) NRC Regulatory Guide RG 1.190, "Calculational and Dosimetry Methods for

Determining Pressure Vessel Neutron Fluence," March 2001

(61) American Society for Testing and Materials (ASTM) Procedures

(62) ASTM Designation El 85-82, "Standard Practice for Conducting Surveillance Tests for

Light-Water Cooled Nuclear Power Reactor Vessels," 1982

(63) EPRI NP-5769, "Degradation and Failure of Bolting in Nuclear Power Plants," April 1988

(64) EPRI TR-1 04213, "Bolted Joint Maintenance & Applications Guide," December 1995

(65) NEI 95-10, Revision 3, "Industry Guideline for Implementing the Requirements of

10 CFR Part 54 - The License Renewal Rule," March 2001

(66) Nuclear Management Company, LLC, License Renewal Application for PBNP Units 1

and 2, February 25, 2004

(67) NUREG-1 800, "Standard Review Plan for Review of License Renewal Applications for

Nuclear Power Plants," April 2001

(68) NEI 95-10, Revision 3, "Industry Guideline for Implementing the Requirements of

10 CFR Part 54 - The License Renewal Rule," March 2001

E-4
NRC Regulations In TItle 10, Code of Federal Regulations (10 CFR)

(69) 10 CFR 50.60, Acceptance Criteria for Fracture Prevention Measures for Light Water

Nuclear Power Reactor for Normal Operation

(70) 10 CFR 50.61, Fracture Toughness Requirements for Protection Against Pressurized

Thermal Shock Events

(71) 10 CFR Part 50, Appendix G, Fracture Toughness Requirements

(72) 10 CFR 50.59, Changes, Tests, and Experiments

NRC Generic Communications

(73) Generic Letter (GL) 96-03, "Relocation of the Pressure Temperature Limit Curves and

Low Temperature Overpressure Protection System Limits," January 31, 1996

NRC Regulatory Guides

(74) Regulatory Guide 1.190, "Calculational and Dosimetry Methods for Determining

Pressure Vessel Neutron Fluence," March 2001

(75) Regulatory Guide 1.99, Revision 2, "Radiation Embrittlement of Reactor Vessel

Materials," May 1988

Miscellaneous References

(76) WCAP-7733, "Reactor Vessel Weld Cladding - Base Metal Interaction," July 1971

(77) WCAP-15338-A, -A Review of Cracking Associated with Weld Deposited Cladding in

Operating PWR Plants," October 2002

E-5
NRC FORM 335 U.S. NUCLEAR REGULATORY COMMISSION 1. REPORT NUMBER

(9-20W4) (Assigned by NRC, Add Vol., Supp., Rev., NRCMD 3.7 and Addendum Numbers, It any.)

BIBLIOGRAPHIC DATA SHEET

(See hstXtions on Xh reverse) NUREG-1839

2. TITLE AND SUBTITLE 3. DATE REPORT PUBLISHED

Safety Evaluation Report Related to the Ucense Renewal of Point Beach Nuclear Plant, Units 1 MONTH YEAR

and 2I December 2005

4. FIN OR GRANT NUMBER

5. AUTHOR(S) 6. TYPE OF REPORT

Veronica Rodriguez

7. PERIOD COVERED (Inclusive Dates)

Feb 25, 2004 -Oct 1, 2005

8. PERFORMING ORGANIZATION - NAME AND ADDRESS (If NRC, provide Division. Oftc or Region, U.S. Nuclearf sgulatoy Commission, and mailing address; Itcontractor.

provide name and madirg address.)

Division of Ucense Renewal

Office of Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001

9. SPONSORING ORGANIZATION - NAME AND ADDRESS (IfNRC, te Sme as above;' icontractor, provide NRCDivision, OireorRegion, U.S. NudearRegulatoryCommission,

and maiing address.)

Same as above

10. SUPPLEMENTARY NOTES

Docket numbers 50-301, 50-266.

11. ABSTRACT 20 waords or less)

This safety evaluation report (SER) documents the technical review of the Point Beach Nuclear Plant (PBNP) Units 1 and 2

license renewal application (LRA) by the staff of the U.S. Nuclear Regulatory Commission (NRC) (the staff). By letter dated

February 25, 2004, Nuclear Management Company, LLC (NMC or the applicant) submitted the LRA for PBNP in accordance

with Title 10, Part 54, of the Code of Federal Regulations (10 CFR Part 54). NMC is requesting renewal of the operating licenses for PBNP Units 1 and 2 (Facility Operating Ucense Numbers DPR-24 and DPR-27, respectively) for a period of 20

years beyond the current expiration dates of midnight, October 5, 2010, for Unit 1 and midnight, March 8, 2013, for Unit 2.

The PBNP units are located about 30 miles SE of Green Bay and about 90 miles NNE of Milwaukee in east central

Wisconsin (Manitowoc County) on the west shore of Lake Michigan. The NRC issued the construction permit for PBNP Unit 1

on July 19, 1967, and for Unit 2 on July 25, 1968. The operating licenses were issued by the NRC on October 5,1970, for Unit

1 and March 8,1973 for Unit 2. The PBNP consists of two Westinghouse pressurized light-water moderated and cooled system units originally designed to generate 1518.5 megawatt thermal (MWt), or approximately 523.8 megawatt electric (MWe). Each

unit has undergone a low pressure turbine retrofit modification which increases the unit design output to 537,960 kWe. In 2003,

a measurement uncertainty recapture power uprate was performed increasing each unit's rated thermal power level to 1540

MWt.

This SER presents the status of the staff's review of Information submitted to the NRC through August 23, 2005, the cutoff

date for consideration in the SER. The staff identified open items and confirmatory items that had to be resolved before the staff

could make a final determination on the application. Sections 1.5 and 1.6 of this report summarize these items and their

resolutions. Section 6 presents the staffs final conclusion on the review of the PBNP application.

12. KEY WORDS/DESCRIPTORS (List w.i orphmss at wil ssist esearchers h oatige he spot) 13. AVAILABILITY STATEMENT

10 CFR 54 unlimited

Part 54 14. SECURITY CLASSIFICATION

license renewal (This Page) Point Beach unclassified

PBNP (hs Repor)

scoping and screening unclassified

aging management time-limited aging analysis 15. NUMBER OF PAGES

TLAA

safety evaluation report 16. PRICE

SER

NR FO. .59204)PiNTDO EYC AE

NRC FORM 335 (9-2004) PRiNTED ON REcycLED PAPER
I IN

SPrinted~

on recycled

paper

Federal Recycling Program