NUREG-1843

Safety Evaluation Report

Related to the License Renewal of

the Browns Ferry Nuclear Plant, 

Units 1, 2, and 3

\

Docket Nos. 50-259, 50-260, and 50-296

Tennessee Valley Authority

U.S. Nuclear Regulatory Commission

Office of Nuclear Reactor Regulation 

Washington, DC 20555-0001
 

 NUREG-1843 

 

Safety Evaluation Report

Related to the License Renewal of

the Browns Ferry Nuclear Plant,

Units 1, 2, and 3

Docket Nos. 50-259, 50-260, and 50-296

Tennessee Valley Authority

Manuscript Completed: January 2006

Date Published: April 2006

Prepared by

Y. Diaz-Sanabria and R. Subbaratnam

Division of License Renewal 

Office of Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001
THIS PAGE IS INTENTIONALLY LEFT BLANK.
iii

ABSTRACT

This safety evaluation report (SER) documents the technical review of the Browns Ferry

Nuclear Plant (BFN), Units 1, 2, and 3, license renewal application (LRA) by the staff of the U.S.

Nuclear Regulatory Commission (NRC) (the staff). By letter dated December 31, 2003,

Tennessee Valley Authority (TVA or the applicant) submitted the LRA for BFN in accordance

with Title 10, Part 54, of the Code of Federal Regulations (10 CFR Part 54). TVA is requesting

renewal of the operating licenses for BFN Units 1, 2, and 3, (Facility Operating License

Numbers DPR-33, DPR-52, and DPR-68, respectively) for a period of 20 years beyond the

current expiration dates of midnight December 20, 2013, for Unit 1; midnight June 28, 2014, for

Unit 2; and midnight July 2, 2016, for Unit 3.

The BFN units are located on the north shore of Wheeler Reservoir in Limestone County,

Alabama, at Tennessee River Mile 294. The site is approximately 30 miles west of Huntsville,

Alabama; it is also 10 miles northwest of Decatur, Alabama and 10 miles southwest of Athens,

Alabama. The NRC issued the construction permits for Units 1 and 2 on May 10, 1967; for

Unit 3 on July 31, 1968. The NRC issued the operating licenses for Unit 1 on December 20,

1973; for Unit 2 on June 28, 1974; and for Unit 3 on July 2, 1976. All of the units consist of a

Mark I boiling water reactor (BWR) with a nuclear steam supply system supplied by General

Electric Corporation. The balance of each of the plants was originally designed and constructed

by the Tennessee Valley Authority. Unit 1 licensed power output is 3293 megawatt thermal

(MWt), with a gross electrical output of approximately 1100 megawatt electric (MWe). Units 2

and 3 licensed power output is 3458 MWt, with a gross electrical output of approximately 1155

MWe. The units operated from the original licensing until 1985 when they were voluntarily shut

down by the applicant to address management and technical issues. The applicant then

implemented a comprehensive nuclear performance plan to correct the deficiencies that led to

the shutdown. This plan included changes in management, programs, processes and

procedures, as well as extensive equipment refurbishment, replacement, and modifications.

Unit 2 was subsequently restarted in 1991, and Unit 3 followed in 1995. In the early 1990s, the

applicant decided to defer restart of Unit 1. Unit 1 is currently in a shutdown status.

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

December 31, 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. SER Sections 1.5 and 1.6 summarize these items and their

resolutions. Section 6 provides the staff’s final conclusion on the review of the BFN LRA.
THIS PAGE IS INTENTIONALLY LEFT BLANK.
v

TABLE OF CONTENTS

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

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

Abbreviations .......... .......... .......... .......... .......... .......... . xv

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

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

1.2 License Renewal Background .......... .......... .......... ........ 1-3

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

1.2.2 Environmental Review .......... .......... .......... ....... 1-5

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

1.3.1 Operating Experience for BFN Unit 1 in Satisfying the Intent of the License

Renewal Rule .......... .......... .......... .......... ... 1-5

1.3.1.1 Regulatory Framework .......... .......... ......... 1-5

1.3.1.2 Collective Operating Experience of the Three BFN Units ... 1-6

1.3.1.3 Corrective Action Program (CAP) Applicability .......... . 1-7

1.3.1.4 Aging Mechanism Similarities Between Units after Layup and

Recovery .......... .......... .......... .......... . 1-7

1.3.1.5 Plant Upgrades .......... .......... .......... ..... 1-8

1.3.1.6 Inspections/Programs Expanded to Proactively Prevent Age

Related Wear .......... .......... .......... ....... 1-8

1.3.2 License Renewal at Currently Licensed Power Level .......... ... 1-10

1.3.3 Integration of Unit 1 Restart Modification .......... .......... . . 1-10

1.3.4 Other Regulatory Requirements .......... .......... ......... 1-11

1.4 Interim Staff Guidance .......... .......... .......... .......... ... 1-12

1.5 Summary of Open Items .......... .......... .......... .......... . . 1-15

1.6 Summary of Confirmatory Items .......... .......... .......... ...... 1-17

1.7 Summary of Proposed License Conditions .......... .......... ........ 1-18

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

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

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

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

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

2.1.2.2 Screening Methodology .......... .......... ......... 2-5

2.1.3 Staff Evaluation .......... .......... .......... .......... . . 2-6

2.1.3.1 Scoping Methodology .......... .......... .......... 2-7

2.1.3.2 Screening Methodology .......... .......... ........ 2-24

2.1.4 Conclusion .......... .......... .......... .......... ..... 2-27

2.2 Plant-Level Scoping Results .......... .......... .......... ......... 2-28

2.2.1 Introduction .......... .......... .......... .......... .... 2-28

2.2.2 Summary of Technical Information in the Application .......... ... 2-28

2.2.3 Staff Evaluation .......... .......... .......... .......... . 2-28

2.2.4 Conclusion .......... .......... .......... .......... ..... 2-30
vi

2.3 Scoping and Screening Results: Mechanical Systems .......... ......... 2-31

2.3.1 Reactor Coolant Systems .......... .......... .......... ... 2-37

2.3.1.1 Reactor Vessel .......... .......... .......... .... 2-37

2.3.1.2 Reactor Vessel Internals .......... .......... ....... 2-39

2.3.1.3 Reactor Vessel Vents and Drains System .......... .... 2-42

2.3.1.4 Reactor Recirculation System .......... .......... ... 2-43

2.3.2 Engineered Safety Features .......... .......... .......... . 2-45

2.3.2.1 Containment System .......... .......... .......... 2-46

2.3.2.2 Standby Gas Treatment System .......... .......... . 2-49

2.3.2.3 High Pressure Coolant Injection System .......... ..... 2-51

2.3.2.4 Residual Heat Removal System .......... .......... . 2-53

2.3.2.5 Core Spray System .......... .......... .......... . 2-54

2.3.2.6 Containment Inerting System .......... .......... ... 2-56

2.3.2.7 Containment Atmosphere Dilution System .......... ... 2-58

2.3.3 Auxiliary Systems .......... .......... .......... .......... 2-60

2.3.3.1 Auxiliary Boiler System .......... .......... ........ 2-61

2.3.3.2 Fuel Oil System .......... .......... .......... .... 2-62

2.3.3.3 Residual Heat Removal Service Water System .......... 2-64

2.3.3.4 Raw Cooling Water System .......... .......... ..... 2-66

2.3.3.5 Raw Service Water System .......... .......... ..... 2-68

2.3.3.6 High Pressure Fire Protection System .......... ....... 2-70

2.3.3.7 Potable Water System .......... .......... ......... 2-75

2.3.3.8 Ventilation System .......... .......... .......... . . 2-76

2.3.3.9 Heating, Ventilation, and Air Conditioning System ........ 2-78

2.3.3.10 Control Air System .......... .......... .......... . 2-81

2.3.3.11 Service Air System .......... .......... .......... 2-82

2.3.3.12 CO2 System .......... .......... .......... ...... 2-84

2.3.3.13 Station Drainage System .......... .......... ...... 2-86

2.3.3.14 Sampling and Water Quality System .......... ....... 2-88

2.3.3.15 Building Heat System .......... .......... ........ 2-90

2.3.3.16 Raw Water Chemical Treatment System .......... .... 2-92

2.3.3.17 Demineralizer Backwash Air System .......... ....... 2-93

2.3.3.18 Standby Liquid Control System .......... .......... . 2-94

2.3.3.19 Off-Gas System .......... .......... .......... ... 2-96

2.3.3.20 Emergency Equipment Cooling Water System ......... 2-98

2.3.3.21 Reactor Water Cleanup System .......... ......... 2-100

2.3.3.22 Reactor Building Closed Cooling Water System ....... 2-105

2.3.3.23 Reactor Core Isolation Cooling System .......... .... 2-109

2.3.3.24 Auxiliary Decay Heat Removal System .......... .... 2-111

2.3.3.25 Radioactive Waste Treatment System .......... ..... 2-112

2.3.3.26 Fuel Pool Cooling and Cleanup System .......... ... 2-114

2.3.3.27 Fuel Handling and Storage System .......... ....... 2-116

2.3.3.28 Diesel Generator System .......... .......... ..... 2-118

2.3.3.29 Control Rod Drive System .......... .......... .... 2-120

2.3.3.30 Diesel Generator Starting Air System .......... ..... 2-121

2.3.3.31 Radiation Monitoring System .......... .......... . . 2-123

2.3.3.32 Neutron Monitoring System .......... .......... ... 2-125

2.3.3.33 Traversing In-Core Probe System .......... ........ 2-127

2.3.3.34 Cranes System .......... .......... .......... . . 2-128
vii

2.3.4 Steam and Power Conversion Systems .......... .......... . . 2-130

2.3.4.1 Main Steam System .......... .......... ......... 2-130

2.3.4.2 Condensate and Demineralized Water System ......... 2-134

2.3.4.3 Feedwater System .......... .......... .......... . 2-136

2.3.4.4 Heater Drains and Vents System .......... .......... 2-137

2.3.4.5 Turbine Drains and Miscellaneous Piping System ....... 2-140

2.3.4.6 Condenser Circulating Water System .......... ...... 2-142

2.3.4.7 Gland Seal Water System .......... .......... ..... 2-144

2.4 Scoping and Screening Results: Structures .......... .......... ...... 2-146

2.4.1 Boiling Water Reactor Containment Structures .......... ...... 2-147

2.4.1.1 Primary Containment Structure .......... .......... . 2-147

2.4.2 Class 1 Group 2 Structures .......... .......... .......... . 2-156

2.4.2.1 Reactor Buildings .......... .......... .......... . 2-157

2.4.2.2 Equipment Access Lock .......... .......... ...... 2-163

2.4.3 Class 1 Group 3 Structures .......... .......... .......... . 2-165

2.4.3.1 Diesel Generator Buildings .......... .......... .... 2-165

2.4.3.2 Standby Gas Treatment Building .......... .......... 2-168

2.4.3.3 Off-Gas Treatment Building .......... .......... .... 2-169

2.4.3.4 Vacuum Pipe Building .......... .......... ........ 2-171

2.4.3.5 Residual Heat Removal Service Water Tunnels ........ 2-173

2.4.3.6 Electrical Cable Tunnel from the Intake Pumping Station to the

Powerhouse .......... .......... .......... ...... 2-175

2.4.3.7 Underground Concrete Encased Structures .......... . 2-177

2.4.3.8 Earth Berm .......... .......... .......... ...... 2-180

2.4.3.9 South Access Retaining Walls .......... .......... . . 2-181

2.4.4 Class 1 Group 6 Structures .......... .......... .......... . 2-182

2.4.4.1 Intake Pumping Station .......... .......... ....... 2-182

2.4.4.2 Gate Structure No. 3 .......... .......... ......... 2-184

2.4.4.3 Intake Channel .......... .......... .......... ... 2-185

2.4.4.4 North Bank of the Cool Water Channel East of Gate Structure

No. 2 .......... .......... .......... .......... . . 2-187

2.4.4.5 South Dike of Cool Water Channel between Gate Structure Nos.

2 and 3 .......... .......... .......... .......... 2-188

2.4.5 Class 1 Group 8 Structures .......... .......... .......... . 2-190

2.4.5.1 Condensate Water Storage Tanks’ Foundations and Trenches

.......... .......... .......... .......... ...... 2-190

2.4.5.2 Containment Atmosphere Dilution Storage Tanks’ Foundations

.......... .......... .......... .......... ...... 2-192

2.4.6 Class 1 Group 9 Structures .......... .......... .......... . 2-194

2.4.6.1 Reinforced Concrete Chimney .......... .......... . . 2-194

2.4.7 Non-Class 1 Structures .......... .......... .......... .... 2-196

2.4.7.1 Turbine Buildings .......... .......... .......... . . 2-196

2.4.7.2 Diesel High Pressure Fire Pump House .......... .... 2-198

2.4.7.3 Vent Vaults .......... .......... .......... ...... 2-200

2.4.7.4 Transformer Yard .......... .......... .......... . 2-202

2.4.7.5 161 kV Switchyard .......... .......... .......... . 2-203

2.4.7.6 500 kV Switchyard .......... .......... .......... . 2-205

2.4.7.7 Isolation Valve Pits .......... .......... .......... 2-207

2.4.7.8 Radwaste Building .......... .......... .......... . 2-208
viii

2.4.7.9 Service Building .......... .......... .......... ... 2-210

2.4.8 Structures and Component Supports Commodities .......... ... 2-212

2.4.8.1 Structures and Component Supports Commodity Group . . 2-212

2.4.9 Conclusion .......... .......... .......... .......... .... 2-216

2.5 Scoping and Screening Results: Electrical and Instrumentation and Controls

Systems .......... .......... .......... .......... .......... . 2-217

2.5.1 Electrical and Instrumentation and Control Commodities ......... 2-217

2.5.1.1 Summary of Technical Information in the Application .... 2-217

2.5.1.2 Staff Evaluation .......... .......... .......... ... 2-218

2.5.1.3 Conclusion .......... .......... .......... ....... 2-223

2.6 Integration of Browns Ferry Nuclear, Unit 1, Restart Activities and License Renewal

Activities .......... .......... .......... .......... .......... . 2-224

2.6.1 Regulatory Framework for Review of BFN LRA and Integration Unit 1

Restart Activities .......... .......... .......... ......... 2-224

2.6.1.1 Main Steam Isolation Valve Alternate Leakage Treatment

.......... .......... .......... .......... ...... 2-227

2.6.1.2 Containment Atmosphere Dilution System .......... . . 2-228

2.6.1.3 Fire Protection .......... .......... .......... ... 2-230

2.6.1.4 Environmental Qualification .......... .......... ... 2-232

2.6.1.5 Intergranular Stress Corrosion Cracking .......... .... 2-234

2.6.1.6 Boiling Water Reactor Vessel and Internals Project Inspection

and Flaw Evaluation Guidelines Implementation ........ 2-235

2.6.1.7 Anticipated Transients Without Scram .......... ...... 2-237

2.6.1.8 Reactor Vessel Head Spray .......... .......... ... 2-238

2.6.1.9 Hardened Wetwell Vent .......... .......... ....... 2-239

2.6.1.10 Service Air and Demineralized Water Primary Containment

Penetrations .......... .......... .......... ...... 2-240

2.6.1.11 Auxiliary Decay Heat Removal System .......... .... 2-241

2.6.1.12 Maintenance Rule .......... .......... .......... 2-243

2.6.1.13 Reactor Water Cleanup System .......... ......... 2-244

2.6.2 Staff Evaluation .......... .......... .......... .......... 2-245

2.6.3 Conclusion .......... .......... .......... .......... ... 2-246

2.7 Conclusion for Scoping and Screening .......... .......... .......... 2-247

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 License Renewal Application .......... .......... . 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

3.0.2.1 Review of AMPs .......... .......... .......... .... 3-4

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

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

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

3.0.3 Aging Management Programs .......... .......... .......... . 3-6

3.0.3.1 AMPs That Are Consistent with the GALL Report, for Which

Further Evaluation is Not Recommended .......... ..... 3-11

3.0.3.2 AMPs That Are Consistent with the GALL Report with Exceptions

or Enhancements .......... .......... .......... ... 3-26
ix

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

GALL Report .......... .......... .......... ...... 3-101

3.0.4 Quality Assurance Program Attributes Integral to Aging Management

Programs .......... .......... .......... .......... .... 3-118

3.0.4.1 Summary of Technical Information in the Application .... 3-119

3.0.4.2 Staff Evaluation .......... .......... .......... ... 3-120

3.0.4.3 Conclusion .......... .......... .......... ....... 3-121

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

System .......... .......... .......... .......... .......... . . 3-122

3.1.1 Summary of Technical Information in the Application .......... . . 3-122

3.1.2 Staff Evaluation .......... .......... .......... .......... 3-122

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

Which Further Evaluation is Not Recommended ......... 3-126

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

Which Further Evaluation is Recommended .......... . . 3-130

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

the GALL Report .......... .......... .......... ... 3-141

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

3.2 Aging Management of Engineered Safety Features .......... .......... 3-177

3.2.1 Summary of Technical Information in the Application .......... . . 3-177

3.2.2 Staff Evaluation .......... .......... .......... .......... 3-177

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 .......... . . 3-183

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

the GALL Report .......... .......... .......... ... 3-187

3.2.3 Conclusion .......... .......... .......... .......... .... 3-201

3.3 Aging Management of Auxiliary Systems .......... .......... ........ 3-202

3.3.1 Summary of Technical Information in the Application .......... . . 3-202

3.3.2 Staff Evaluation .......... .......... .......... .......... 3-203

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

Which Further Evaluation is Not Recommended ......... 3-209

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

Which Further Evaluation is Recommended .......... . . 3-211

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

the GALL Report .......... .......... .......... ... 3-221

3.3.3 Conclusion .......... .......... .......... .......... .... 3-261

3.4 Aging Management of Steam and Power Conversion System .......... . . 3-262

3.4.1 Summary of Technical Information in the Application .......... . . 3-262

3.4.2 Staff Evaluation .......... .......... .......... .......... 3-262

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

Which Further Evaluation is Not Recommended ......... 3-265

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

Which Further Evaluation is Recommended .......... . . 3-267

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

the GALL Report .......... .......... .......... ... 3-270

3.4.3 Conclusion .......... .......... .......... .......... .... 3-278
x

3.5 Aging Management of Containments, Structures, and Component Supports

.......... .......... .......... .......... .......... ....... 3-279

3.5.1 Summary of Technical Information in the Application .......... . . 3-279

3.5.2 Staff Evaluation .......... .......... .......... .......... 3-280

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

Which Further Evaluation is Not Recommended ......... 3-285

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

Which Further Evaluation is Recommended .......... . . 3-289

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

the GALL Report .......... .......... .......... ... 3-305

3.5.3 Conclusion .......... .......... .......... .......... .... 3-350

3.6 Aging Management of Electrical and Instrumentation and Controls ........ 3-351

3.6.1 Summary of Technical Information in the Application .......... . . 3-351

3.6.2 Staff Evaluation .......... .......... .......... .......... 3-351

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

Which Further Evaluation is Not Recommended ......... 3-353

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

Which Further Evaluation is Recommended .......... . . 3-355

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

the GALL Report .......... .......... .......... ... 3-356

3.6.3 Conclusion .......... .......... .......... .......... .... 3-362

3.7 Aging Management Review of Unit 1 Systems in Layup for Extended Outage

.......... .......... .......... .......... .......... ....... 3-363

3.7.1 General Technical Concerns .......... .......... .......... 3-363

3.7.1.1 Wet Layup Program Chemistry Control .......... ..... 3-368

3.7.1.2 Replaced Components .......... .......... ....... 3-369

3.7.1.3 Inspections Verification Programs for Layup and Chemistry

Control .......... .......... .......... .......... 3-371

3.7.1.4 MIC .......... .......... .......... .......... . . 3-378

3.7.1.5 Transition from Layup Program to System Cleanliness

Verification Program .......... .......... .......... 3-381

3.7.2 Reactor Vessel internals and Reactor Coolant System .......... 3-382

3.7.2.1 Reactor Recirculation System (068) .......... ........ 3-382

3.7.2.2 Reactor Vessel (RV), Reactor Vessel Internals (RVIs) ... 3-385

3.7.3 Engineered Safety Features .......... .......... .......... 3-391

3.7.3.1 Engineered Safety Features Systems in Dry Layup ...... 3-391

3.7.3.2 Engineered Safety Features Systems in Various Wet

Environments .......... .......... .......... ..... 3-395

3.7.3.3 Engineered Safety Features Systems in Various Dry

Environments .......... .......... .......... ..... 3-403

3.7.4 Auxiliary Systems .......... .......... .......... ......... 3-407

3.7.4.1 Auxiliary Systems in Dry Layup .......... .......... . 3-407

3.7.4.2 Auxiliary Systems in Wet Lay up .......... .......... 3-413

3.7.4.3 Auxiliary Systems Not in Layup Program .......... .... 3-418

3.7.5 Steam and Power Conversion Systems .......... .......... . . 3-420

3.7.5.1 Steam and Power Conversion Systems in Wet Layup .... 3-420

3.7.5.2 Steam and Power Conversion Systems in Various Wet

Environments .......... .......... .......... ..... 3-423
xi

3.7.5.3 Steam and Power Conversion Systems in Various Dry

Environments .......... .......... .......... ..... 3-430

3.7.6 Containments, Structures, and Component Supports .......... . 3-437

3.7.6.1 Summary of Technical Information in the Application .... 3-437

3.7.6.2 Technical Staff Evaluation .......... .......... ..... 3-437

3.7.6.3 Conclusion .......... .......... .......... ....... 3-442

3.8 Conclusion for Aging Management .......... .......... .......... ... 3-443

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 Neutron Embrittlement of Reactor Vessel and Internals .......... ......... 4-3

4.2.1 Reactor Vessel Materials Upper Shelf Energy Reduction due to Neutron

Embrittlement .......... .......... .......... .......... ... 4-4

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

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

4.2.1.3 UFSAR Supplement .......... .......... .......... . 4-7

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

4.2.2 Adjusted Reference Temperature for Reactor Vessel Materials due to

Neutron Embrittlement .......... .......... .......... ...... 4-8

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

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

4.2.2.3 UFSAR Supplement .......... .......... .......... 4-10

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

4.2.3 Reflood Thermal Shock Analysis of the Reactor Vessel .......... . 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 UFSAR Supplement .......... .......... .......... 4-11

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

4.2.4 Reflood Thermal Shock Analysis of the Reactor Vessel Core Shroud

.......... .......... .......... .......... .......... ... 4-12

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

4.2.4.2 Staff Evaluation .......... .......... .......... .... 4-12

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

4.2.4.4 Conclusion .......... .......... .......... ........ 4-14

4.2.5 Reactor Vessel Thermal Limit Analyses: Operating Pressure-Temperature

Limits .......... .......... .......... .......... ........ 4-15

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

4.2.5.2 Staff Evaluation .......... .......... .......... .... 4-15

4.2.5.3 UFSAR Supplement .......... .......... .......... 4-15

4.2.5.4 Conclusion .......... .......... .......... ........ 4-16

4.2.6 Reactor Vessel Circumferential Weld Examination Relief ......... 4-16

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

4.2.6.2 Staff Evaluation .......... .......... .......... .... 4-17

4.2.6.3 UFSAR Supplement .......... .......... .......... 4-20

4.2.6.4 Conclusion .......... .......... .......... ........ 4-20

4.2.7 Reactor Vessel Axial Weld Failure Probability .......... ........ 4-21
xii

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

4.2.7.2 Staff Evaluation .......... .......... .......... .... 4-21

4.2.7.3 UFSAR Supplement .......... .......... .......... 4-22

4.2.7.4 Conclusion .......... .......... .......... ........ 4-23

4.3 Metal Fatigue .......... .......... .......... .......... .......... 4-23

4.3.1 Reactor Vessel Fatigue Analysis .......... .......... ........ 4-23

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

4.3.1.2 Staff Evaluation .......... .......... .......... .... 4-24

4.3.1.3 UFSAR Supplement .......... .......... .......... 4-24

4.3.1.4 Conclusion .......... .......... .......... ........ 4-25

4.3.2 Fatigue Analysis of Reactor Vessel Internals .......... ......... 4-25

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

4.3.2.2 Staff Evaluation .......... .......... .......... .... 4-26

4.3.2.3 UFSAR Supplement .......... .......... .......... 4-26

4.3.2.4 Conclusion .......... .......... .......... ........ 4-26

4.3.3 Piping and Component Fatigue Analysis .......... .......... . . 4-27

4.3.3.1 Summary of Technical Information in the Application ..... 4-27

4.3.3.2 Staff Evaluation .......... .......... .......... .... 4-27

4.3.3.3 UFSAR Supplement .......... .......... .......... 4-28

4.3.3.4 Conclusion .......... .......... .......... ........ 4-28

4.3.4 Effects of Reactor Coolant Environment On Fatigue Life of Components

and Piping (Generic Safety Issue 190) .......... .......... ... 4-28

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

4.3.4.2 Staff Evaluation .......... .......... .......... .... 4-29

4.3.4.3 UFSAR Supplement .......... .......... .......... 4-30

4.3.4.4 Conclusion .......... .......... .......... ........ 4-30

4.4 Environmental Qualification .......... .......... .......... ......... 4-31

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

4.4.2 Staff Evaluation .......... .......... .......... .......... . 4-33

4.4.3 UFSAR Supplement .......... .......... .......... ........ 4-34

4.4.4 Conclusion .......... .......... .......... .......... ..... 4-34

4.5 Loss of Prestress in Concrete Containment Tendons .......... .......... 4-34

4.6 Primary Containment Fatigue .......... .......... .......... ........ 4-34

4.6.1 Fatigue of Suppression Chamber, Vents, and Downcomers ....... 4-35

4.6.1.1 Summary of Technical Information in the Application ..... 4-35

4.6.1.2 Staff Evaluation .......... .......... .......... .... 4-36

4.6.1.3 UFSAR Supplement .......... .......... .......... 4-37

4.6.1.4 Conclusion .......... .......... .......... ........ 4-37

4.6.2 Fatigue of Torus Attached Pipe and Safety Relief Valve Discharge Lines

.......... .......... .......... .......... .......... ... 4-37

4.6.2.1 Summary of Technical Information in the Application ..... 4-37

4.6.2.2 Staff Evaluation .......... .......... .......... .... 4-38

4.6.2.3 UFSAR Supplement .......... .......... .......... 4-38

4.6.2.4 Conclusion .......... .......... .......... ........ 4-38

4.6.3 Fatigue of Vent Line and Process Penetration Bellows .......... . 4-38

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

4.6.3.2 Staff Evaluation .......... .......... .......... .... 4-39

4.6.3.3 UFSAR Supplement .......... .......... .......... 4-39

4.6.3.4 Conclusion .......... .......... .......... ........ 4-40
xiii

4.7 Other Plant-Specific Analyses .......... .......... .......... ....... 4-40

4.7.1 Reactor Building Crane Load Cycles .......... .......... ..... 4-40

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

4.7.1.2 Staff Evaluation .......... .......... .......... .... 4-40

4.7.1.3 UFSAR Supplement .......... .......... .......... 4-41

4.7.1.4 Conclusion .......... .......... .......... ........ 4-41

4.7.2 Corrosion – Flow Reduction .......... .......... .......... . . 4-42

4.7.3 Dose to Seal Rings for the High Pressure Coolant Injection and Reactor

Core Isolation Cooling Containment Isolation Check Valves ...... 4-42

4.7.4 Radiation Degradation of Drywell Expansion Gap Foam .......... 4-42

4.7.4.1 Summary of Technical Information in the Application ..... 4-42

4.7.4.2 Staff Evaluation .......... .......... .......... .... 4-43

4.7.4.3 UFSAR Supplement .......... .......... .......... 4-44

4.7.4.4 Conclusion .......... .......... .......... ........ 4-44

4.7.5 Corrosion – Minimum Wall Thickness .......... .......... .... 4-45

4.7.6 Irradiation Assisted Stress Corrosion Cracking of Reactor Vessel Internals

.......... .......... .......... .......... .......... ... 4-45

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

4.7.6.2 Staff Evaluation .......... .......... .......... .... 4-46

4.7.6.3 UFSAR Supplement .......... .......... .......... 4-49

4.7.6.4 Conclusion .......... .......... .......... ........ 4-49

4.7.7 Stress Relaxation of the Core Plate Hold-Down Bolts .......... . . 4-50

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

4.7.7.2 Staff Evaluation .......... .......... .......... .... 4-50

4.7.7.3 UFSAR Supplement .......... .......... .......... 4-57

4.7.7.4 Conclusion .......... .......... .......... ........ 4-57

4.7.8 Emergency Equipment Cooling Water Weld Flaw Evaluation ...... 4-58

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

4.7.8.2 Staff Evaluation .......... .......... .......... .... 4-58

4.7.8.3 UFSAR Supplement .......... .......... .......... 4-60

4.7.8.4 Conclusion .......... .......... .......... ........ 4-60

4.8 Conclusion for Time-Limited Aging Analyses .......... .......... ...... 4-61

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

6 Conclusions .......... .......... .......... .......... .......... ......... 6-1

Appendices

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

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

Appendix C: Principal Contributors .......... .......... .......... .......... .... C-1

Appendix D: References .......... .......... .......... .......... .......... . D-1
xiv

Tables

Table 3.0.3-1 BFN’s Aging Management Programs .......... .......... .......... . 3-7

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

Components in the GALL Report .......... .......... .......... ........ 3-123

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

Report .......... .......... .......... .......... .......... ........ 3-178

Table 3.3-1 Staff Evaluation for Auxiliary Systems Components in the GALL Report ... 3-204

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

GALL Report .......... .......... .......... .......... .......... ... 3-263

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

GALL Report .......... .......... .......... .......... .......... ... 3-280

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

Report .......... .......... .......... .......... .......... ........ 3-352
xv

ABBREVIATIONS

AC alternating current

ACI American Concrete Institute

ACSR aluminum conductor steel reinforced

ACRS Advisory Committee on Reactor Safeguards

ADHR auxiliary decay heat removal

ADS atmospheric dilution system

AERM aging effect requiring management

AFFF aqueous film-forming foam 

AFW auxiliary feedwater

AHC access hole cover

AISC American Institute of Steel Construction

AMP aging management program

AMR aging management review

ANSI American National Standards Institute

APCSB Auxiliary and Power Conversion Systems Branch 

APRM average power range monitor

URI unresolved issue

ART adjusted reference temperature

ASCE American Society of Civil Engineers

ASME American Society of Mechanical Engineers

AST alternate source term

ASTM American Society for Testing and Materials

ATWS anticipated transient without scram

B&PV boiler and pressure vessel

B&W Babcock and Wilcox

BFN Browns Ferry Nuclear Plant

BWR boiling water reactor

BWROG Boiling Water Reactor Owners Group 

BWRVIP Boiling Water Reactor Vessel and Internals Project

CAD containment atmosphere dilution

CASS cast austentitic stainless steel

CBF cycle-based fatigue

CCCW closed-cycle cooling water

CCWP condensate circulating water pump 

CF chemistry factor

CFR Code of Federal Regulations

CI confirmatory item

CLB current licensing basis

CMAA Crane Manufacturers Association of America

CO2

carbon dioxide

CRD control rod drive

CS core spray

CUF cumulative usage factor
xvi

CVP Cleanliness Verification Program

CWST condensate water storage tank 

DBA design-basis accident

DBE design-basis event

DC design of civil structures

DCN design change notice

DG diesel generator or Draft Regulatory Guide

DGB diesel generator building

dpa displacements per atom

ECCS emergency core cooling system

ECP electrochemical potential

EDG emergency diesel generator

EECW emergency equipment cooling water

EFPY effective full-power year

EMA equivalent margin analysis

EMPAC enterprise maintenance planning and control

EOL end of life

EPRI Electric Power Research Institute

EPU extended power uprate

EQ environmental qualification

ESF engineered safety feature

EVT enhanced visual test

FAC flow-accelerated corrosion

Fen environmental fatigue life correction factor

FERC Federal Energy Regulatory Commission

FP fire protection

FPC fuel pool cooling and cleanup

FPR Fire Protection Report

FSAR final safety analysis report

FW feedwater

GALL Generic Aging Lessons Learned Report

GDC general design criteria

GE General Electric Corporation

GEIS Generic Environmental Impact Statement

GENE General Electric Nuclear Energy

GES general engineering specification

GL generic letter

GSI generic safety issue

HELB high-energy line break

HEPA high efficiency particulate air

HH handhole

HPCI high pressure coolant injection

HPFP high pressure fire protection

HSLA high-strength low-alloy
xvii

HVAC heating, ventilation, and air conditioning

HWC hydrogen water chemistry

HX heat exchanger

I&C instrumentation and control

IASCC irradiation assisted stress corrosion cracking

ID inside diameter

IGSCC intergranular stress corrosion cracking

IN information notice

INPO Institute of Nuclear Power Operations

IPA integrated plant assessment

IPS intake pumping station

IR insulation resistance

IRM intermediate range monitor

ISG interim staff guidance

ISI inservice inspection

ISP Integrated Surveillance Program

kV kiloVolt

LER Licensee Event Report

LLRT local leak rate test

LLRW low level radioactive waste

LOCA loss-of-coolant-accident

LP layup program

LPCI low pressure coolant injection

LPRM local power range monitor

LR license renewal

LRA license renewal application

LTOP low temperature over-pressure

LWR light water reactor

MEAP material, environment, aging effects, and aging management program

MEL master equipment list

MeV million electron Volts

MIC microbiologically influenced corrosion

MS main steam

MSIV main steam isolation valve

MWe megawatt electric

MWt megawatt thermal

n/cm2 neutrons per square centimeter

NDE nondestructive examination

NEDP Nuclear Engineering Design Procedure

NEI Nuclear Energy Institute

NEIL Nuclear Electric Insurance Limited

NEPA National Environmental Policy Act of 1969

NFPA National Fire Protection Association

NMCA noble metal chemical application
xviii

NPS nominal pipe size

NRC U.S. Nuclear Regulatory Commission

NSR non-safety-related

NSSS nuclear steam supply system

NUREG U.S. Nuclear Regulatory Commission Regulatory Guide

O2 oxygen

OCCW open-cycle cooling water

OE operating experience

OFS orificed fuel supports

OI open item

PB pressure boundary

PER Problem Evaluation Report

PFM probabilistic fracture mechanics

PT penetrant testing

PTS pressurized thermal shock

PUAR Plant Unique Analysis Report

PVC polyvinyl chloride

PW pipe whip restraint

PWR pressurized water reactor

PWSCC primary water stress corrosion cracking

QA quality assurance

RAI request for additional information

RBCCW reactor building closed cooling water

RBM rod block monitor

RCIC reactor core isolation cooling

RCPB reactor coolant pressure boundary

RCS reactor coolant system

RCW raw cooling water

RG regulatory guide

RH relative humidity

RHR residual heat removal

RHRSW residual heat removal service water

RPV reactor pressure vessel

RPVII reactor pressure vessel internals inspection

RSW raw service water

RT reference temperature

RTNDT reference temperature nil ductility transition

RV reactor vessel

RVI reactor vessel internal

RWCU reactor water cleanup

SBF stress-based fatigue

SBO station blackout

SC structure and component

SCC stress corrosion cracking
xix

SCV steel containment vessel

SER Safety Evaluation Report

SGT standby gas treatment

SI surveillance instruction

SIL Service Information Letter

SLC standby liquid control

SMP Structures Monitoring Program

SO2 sulfur dioxide

SOC statement of consideration

SOER Significant Operating Experience Report

SP shelter/protection

SPP standard program and process

SR safety-related

SRM source range monitor

SRP Standard Review Plan

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

Power Plants

SRV safety relief valve

SS stainless steel or structural support or systems and structures

SSA safe shutdown analysis

SSC system, structure, and component

SSE safe shutdown earthquake

TI technical instruction

TIP traversing in-core probe

TLAA time-limited aging analysis

TS technical specification

TVA Tennessee Valley Authority

TVAN Tennessee Valley Authority Nuclear

UFSAR updated final safety analysis report

UNID unique component identifier

USAS USA standard

USE upper-shelf energy

UT ultrasonic testing

UV ultra violet

V volt

VFLD vessel flange leak detection

VIP vessel and internals project

WO work order

XLPE cross-linked polyethylene
THIS PAGE IS INTENTIONALLY LEFT BLANK
1-1

SECTION 1

INTRODUCTION AND GENERAL DISCUSSION

1.1 Introduction

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

for the Browns Ferry Nuclear Plant (BFN), as filed by Tennessee Valley Authority (TVA or the

applicant). By letter dated December 31, 2003, TVA submitted its application to the U.S.

Nuclear Regulatory Commission (NRC or the Commission) for renewal of the BFN 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 managers for the BFN license renewal review are Ram Subbaratnam and Yoira

Diaz-Sanabria. Mr. Subbaratnam can be contacted by telephone at 301-415-1478 or by

electronic mail at rxs2@nrc.gov; Ms. Diaz-Sanabria can be contacted by telephone at

301-415-1594 or by electronic mail at yks@nrc.gov. 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: Ram Subbaratnam, or Yoira Diaz-Sanabria, Mail Stop 0-11-F1

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

licenses issued under Section 104b (Operating License Nos. DPR-33, DPR-52, and DPR-68) of

the Atomic Energy Act of 1954, as amended, for BFN Units 1, 2, and 3 for a period of 20 years

beyond the current license expiration dates of midnight December 20, 2013, for Unit 1; midnight

June 28, 2014, for Unit 2; and midnight July 2, 2016 for Unit 3. The BFN units are located on

the north shore of Wheeler Reservoir in Limestone County, Alabama, at Tennessee River

Mile 294. The site is approximately 30 miles west of Huntsville, Alabama; it is also 10 miles

northwest of Decatur, Alabama and 10 miles southwest of Athens, Alabama. The NRC issued

the construction permits for Unit 1 on May 10, 1967; for Unit 2 on May 10, 1967; and for Unit 3

on July 31, 1968. The staff issued the operating licenses for Unit 1 on December 20, 1973; for

Unit 2 on June 28, 1974; and for Unit 3 on July 2, 1976. All of the units consist of a Mark I

boiling water reactor (BWR) with a nuclear steam supply system supplied by General Electric

Corporation. The balance of each of the plants was originally designed and constructed by

TVA. Unit 1 licensed power output is 3293 megawatt thermal (MWt), with a gross electrical

output of approximately 1100 megawatt electric (MWe). Units 2 and 3 licensed power output is

3458 MWt, with a gross electrical output of approximately 1155 MWe. The updated final safety

analysis report (UFSAR) contains details concerning the plant and the site. The units operated

from the original licensing until 1985 when they were voluntarily shut down by the applicant to

address management and technical issues. The applicant then implemented a comprehensive

nuclear performance plan to correct the deficiencies that led to the shutdown. This plan

included changes in management, programs, processes and procedures, as well as extensive

equipment refurbishment, replacement, and modifications. Unit 2 was subsequently restarted in
1-2

1991, and Unit 3 followed in 1995. In the early 1990s, the applicant decided to defer restart of

Unit 1. Unit 1 is currently in a shutdown status.

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, set forth the requirements against which license renewal applications are

reviewed. The safety review for the BFN license renewal is based on the applicant's license

renewal application (LRA) and on the responses to the staff's requests for additional information

(RAIs). The applicant supplemented and clarified its responses to the LRA and RAIs in audits,

meetings, and docketed correspondence. Unless otherwise noted, the staff reviewed and

considered information submitted through December 31, 2005. The public may view the LRA

and all pertinent information and materials, including the UFSAR 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 Athens-Limestone Public

Library, 405 South Street East, Athens, AL, 35611. In addition, the public may find the BFN

Units 1, 2, and 3 LRA, as well as materials related to the license renewal review, on the NRC

website at www.nrc.gov.

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

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

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

LRA in accordance with 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). The conclusions of this report are in

Section 6.

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 is a list of principal contributors to the SER. Appendix D is a bibliography of the

references used in support of the review.

In accordance with 10 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 BFN Units 1, 2, and 3. The

staff issued (draft) Supplement 21 to NUREG-1437, “Generic Environmental Impact Statement

for License Renewal of Nuclear Plants: Regarding Browns Ferry Nuclear Plant, Units 1, 2, and

3: Draft Report for Comment,” on December 3, 2004. The final report was issued on June 23,

2005.
1-3

1.2 License Renewal Background

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

licenses for commercial power reactors are issued for 40 years. These licenses can be

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

basis of economic and antitrust considerations, rather than on technical limitations; however,

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

expected 40-year service life.

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

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

plant aging research. 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 staff published a

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

procedural issues related to license renewal for nuclear power plants.

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

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 staff found that adverse effects of aging occur

to plant systems and components and the effects are managed during the period of initial

license. In addition, the staff 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 staff 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 staff

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 staff 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 staff 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 fulfill the NRC's responsibilities under the National Environmental Policy

Act of 1969 (NEPA).

1.2.1 Safety Review

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

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

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

exception of the detrimental effects of aging on the functionality of certain SSCs, as well

as a few other safety-related (SR) issues, during the period of extended operation;
1-4

 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

including those SSCs (1) that are SR; (2) whose failure could affect SR 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).

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; however, active equipment

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 can 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 (final

safety analysis report) or UFSAR. This supplement must contain a summary description of the

applicant’s programs and activities for managing the effects of aging and the 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 can operate.

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

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

remain valid for the period of extended operation, project the analyses to the end of the period

of extended operation, or demonstrate that the effects of aging on these SSCs can 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

Nuclear Energy Institute (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 NEI.

NEI 95-10 details an acceptable method of implementing the license renewal rule. The staff

also used the SRP-LR to review this application.

In the LRA, BFN fully utilizes the process defined in NUREG-1801, “Generic Aging Lessons

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

summary of 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
1-5

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 determined can provide adequate aging management

during the period of extended operation.

1.2.2 Environmental Review

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

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

regulations to facilitate the environmental review for license renewal. The staff prepared a

“Generic Environmental Impact Statement (GEIS) for License Renewal of Nuclear Plants”

(NUREG-1437, Revision 1) to document its evaluation of the possible environmental impacts

associated with renewing licenses of nuclear power plants. For certain types of environmental

impacts, the GEIS establishes generic findings that are applicable to all nuclear power plants.

These generic findings are codified in Appendix B to Subpart A of 10 CFR Part 51. 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 also 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 staff 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 staff held a public meeting on April 1, 2004, in Athens, Alabama to identify

environmental issues specific to the plant. The NRC's draft plant-specific Supplement 21 to the

BFN GEIS, which was issued on December 1, 2004, documents the results of the

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

renewal action. The staff held another public meeting on January 25, 2005, in Athens, Alabama,

to discuss the draft plant-specific Supplement 21 to the GEIS. After considering comments on

the draft, the staff published a final, plant-specific supplement to the GEIS separately from this

report on June 23, 2005.

1.3 Principal Review Matters

1.3.1 Operating Experience for BFN Unit 1 in Satisfying the Intent of the License

Renewal Rule

1.3.1.1 Regulatory Framework

Section 54.17(c) of 10 CFR states that an application for a renewed license may not be

submitted earlier than 20 years before the expiration of the operating license currently in effect.

The operating license for BFN Unit 1 expires on December 20, 2013; for Unit 2, on June 28,

2014; and for Unit 3, on July 2, 2016. The license renewal application for Units 1, 2, and 3 was

submitted on December 31, 2003. Thus, all units met this regulatory requirement and no

plant-specific exemptions were required.
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 When 10 CFR Part 54 was published, the Commission originally determined that a 20-year

period of plant-specific operating experience would allow adequate assessment of any agerelated degradation of plant structures, systems, and components. The statement of

consideration (SOC) hence implied an intent of a 20-year threshold limit to ensure that

substantial operating experience is accumulated by licensees before the submittal of license

renewal applications. From that consideration, BFN Unit 1's 10-year operating history does not

entirely meet that intent. The Advisory Committee on Reactor Safeguards (ACRS or the

Committee), in an interim report dated October 19, 2005, on the safety aspects of the license

renewal application for BFN Units 1, 2, and 3, commented that 10 years of plant-specific

operating experience for BFN Unit 1, by itself, does not fully meet the intent of the license

renewal rule. TVA, in its response dated November 16, 2005, submitted for the Committee’s

consideration the following information in support of its claim that Unit 1 meets the intent of the

Rule.

1.3.1.2 Collective Operating Experience of the Three BFN Units

BFN Unit 1 was licensed and began initial operation in 1973. Unit 2 began operation in 1974.

Units 1 and 2 operated until March 22, 1975, at which time both units were shut down due to a

fire in the Unit 1 reactor building. Units 1 and 2 resumed operation in 1976, and Unit 3 began

initial operation in 1977. All three units were operated until March 1985, at which time the

applicant voluntarily shut them down to address regulatory and management issues.

Following successful resolution of the management issues and the Unit 2 and common

regulatory issues, Unit 2 was restarted on May 23, 1991. Unit 3 remained in a layup/recovery

mode for approximately 10 years and, following resolution of the Unit 3 regulatory issues, Unit 3

was restarted on November 19, 1995. Both Units 2 and 3 have operated with high capacity

factors into the present time. In the early 1990s, the applicant decided to defer the restart of

Unit 1.

On May 16, 2002, the applicant announced the Unit 1 Restart Project. As part of the restart

project, the applicant is performing the same restart programs and implementing the same

modifications that were previously completed on Units 2 and 3. At restart, Unit 1 will be

operationally the same as Units 2 and 3. Based only on the periods of operation as of 2005,

Unit 1 has operated for approximately 10 calendar years, Unit 2 has operated for approximately

23 calendar years and Unit 3 has operated for approximately 18 calendar years.

All three BFN units share common facilities, materials, and environments. The three units are

identical General Electric BWR 4 reactors with Mark I containments. TVA designed and

constructed the units to be materially and operationally identical, with identical systems,

components, materials, and environments. For a given power level, the system process

conditions (e.g., pressure, temperatures, moisture content, chemical properties, flow rates,

velocities, etc.) are identical. There is one UFSAR for the three units. Operating procedures and

Technical Specifications are nearly identical. Due to outage scheduling, small unit differences

may exist for short periods of time but are eliminated as modifications are installed on other

units during subsequent unit outages. Thus, over 51 years of operating experience is

accumulated collectively by the three units and this collective experience has been used to

support the preparation of the three-unit license renewal application. Addressing stakeholders’

questions when the Rule was published in 1991, the SOC states that the licensees and the
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NRC can substitute nuclear industry operating experience for plant-specific experience, and the

staff need not limit its safety finding to information developed solely from plant-specific

experience of an applicant. Therefore, the collective 51 years experience is sufficient to support

the renewal of the BFN Unit 1 operating license, because the Unit 2 operating experience,

along with the experience during the ten-year extended layup and subsequent operation of BFN

Unit 3, applies to Unit 1. Specifically, in pursuing license renewal for BFN Unit 1, TVA has relied

not only on Unit 1's CLB, including the specific changes in Appendix F of the LRA, but also on

Unit 1's plant-specific operating experience, the operating experience gained from BFN Units 2

and 3, and relevant industry-wide operating experience. This experience base satisfies and is

consistent with the regulatory requirements and intent of 10 CFR 54.17(c).

1.3.1.3 Corrective Action Program (CAP) Applicability

In its submittal dated January 31, 2005, TVA stated that the three BFN units are essentially

identical, and the application is not unit-specific regarding aging management programs. The

changes being implemented as part of Unit 1 restart activities are consistent with the changes

made previously to Units 2 and 3. AMPs are common for all three units based on their CLB.

Since at restart the Unit 1 licensing basis will be consistent with that of Units 2 and 3, the aging

management programs specified will be applicable to all three units. In addition to the

similarities between the Units 2 and 3 and Unit 1 licensing and design bases, specific programs

function such that relevant Units 2 and 3 operating experience is passed on to Unit 1. First, the

Corrective Action Program (CAP) applies to all TVA organizations involved in nuclear power

activities. This program is not unit specific and, as applicable, a condition identified at any BFN

unit is reviewed for generic implications potentially applicable to the other units. TVA also has

an administrative procedure for the review and dissemination of operating experience obtained

from both external and internal sources. This procedure requires screening of such information

for potential BFN applicability. This information is received from sources such as NRC

Information Notices, Institute of Nuclear Power Operations (INPO), nuclear steam supply

system (NSSS) vendor reports/notices, and in-house operating experience. If an item is

determined to be applicable to BFN, then the information is addressed in the CAP. Thus, these

programs help ensure that relevant operating experience (OE) is applied to all three units.

1.3.1.4 Aging Mechanism Similarities Between Units after Layup and Recovery

During the collective periods of BFN operation, including recovery, the three units have

experienced similar aging mechanisms. For example, each unit has experienced the expected

wear such as Flow Accelerated Corrosion (FAC), general corrosion, and microbiologically

induced corrosion (MIC). Applicable aging mechanisms for the passive plant features are

identified in LRA Section 3.0. The aging mechanisms for the passive plant features are well

known and are addressed by existing plant programs and procedures.

Since components and structures within the scope of AMRs for the three units contain the same

materials and have experienced the same process conditions, all three units experience similar

aging effects. Unit 1 has been shut down since 1985. During the shutdown period, it

experienced aging effects analogous to those experienced on Units 2 and 3 during their

shutdown periods. In this regard, the applicant has utilized the OE gained from restarting and

operating Units 2 and 3, in recovering Unit 1, and has undertaken proactive steps to use the

aging mechanisms experienced during subsequent operation of Units 2 and 3 to determine the
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necessary modifications to Unit 1 to preclude aging effects when possible. In many cases, the

aging mechanisms such as FAC had not resulted in significant wear in Unit 1; however, the

recovery effort has replaced the FAC-susceptible material with FAC-resistant material. The

Unit 1 locations for replacements were expanded to address additional locations with

geometry/process conditions similar to Units 2 and 3 wear locations even if Units 2 and 3 had

not experienced significant wear in all similar locations. For example, if Unit 2 had experienced

wear at one elbow, but not at two other elbows of similar material/geometry/process conditions,

the Unit 1 restart scope included all 3 locations. The Unit 1 recovery design changes have not

resulted in the installation of types of material different from those present in Units 2 and 3.

Thus, during the collective periods of BFN operation, including recovery, the three units have

experienced similar aging mechanisms and will be appropriately managed during the period of

extended operations.

1.3.1.5 Plant Upgrades

As part of the recovery of Units 2 and 3, TVA implemented various plant upgrades (i.e., design

changes) in response to regulatory issues and/or to improve plant operating characteristics.

This upgrade experience has been brought to bear in the Unit 1 recovery effort. For example,

as part of the recovery of Units 2 and 3, TVA replaced piping that was susceptible to

intergranular stress corrosion cracking (IGSCC). Similar design changes are being installed on

Unit 1 as part of the recovery process. IGSCC-susceptible piping in the reactor recirculation,

residual heat removal (RHR), reactor water cleanup (RWCU), and core spray (CS) systems on

Unit 1 is being replaced using materials that are resistant to IGSCC. (Also, see the beginning of

SER Section 3.7)

The applicant stated that it has effectively managed aging through various programs and has

replaced and upgraded the plant to manage the effects of aging. For example, the systems

susceptible to FAC are monitored in accordance with EPRI guidelines (LRA Section B.2.1.15,

SER Section 3.0.3.2.9). Piping on Units 2 and 3 is monitored for FAC-induced wear and

replaced as needed. In many cases, the piping has been replaced with FAC-resistant chrome

molybdenum piping (LRA Section B.2.1.15, SER Section 3.0.3.2.9). Reactor vessel

components such as the shroud, vessel welds, jet pumps, core plate, and top guide are

inspected by accepted industry standards such as the Boiling Water Reactor Vessel Internals

Program (BWRVIP) and repairs/replacements performed as required (LRA Section B.2.1.12,

SER Section 3.0.3.2.7). Raw water piping that is used to transfer heat from SR systems to the

ultimate heat sink is managed by the Open Cycle Cooling Water System Program (LRA Section

B.2.1.17, SER Section 3.0.3.2.11). The primary containment liner is inspected in accordance

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

Section XI, Subsection IWE for steel containments (Class MC) requirements (LRA Section

B.2.1.31, SER Section 3.0.3.1.9). As explained in the LRA, these same programs are used on

all three units.

1.3.1.6 Inspections/Programs Expanded to Proactively Prevent Age Related Wear

In its submittal dated November 16, 2005, TVA stated that the Unit 1 inspections/programs for

other aging mechanisms have been expanded to proactively prevent age-related wear. The

scope of replacement of IGSCC-susceptible piping is significantly larger in Unit 1 than in Units 2

or 3; thus, Unit 1 will contain a significantly larger scope of new pipe that has no pre-existing
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aging effects. Since similar materials and geometry were used in Unit 1 for the expanded

scope, there were no new aging mechanisms introduced. In addition, the Unit 1 systems that

perform a required function in the defueled condition, or that directly support the operation of 

Unit 2 or Unit 3, have been continuously operated and maintained under applicable Technical

Specifications and plant programs since shutdown in 1985. This OE has been factored into the

LRA. Examples of these piping systems include portions of fuel pool cooling and cleanup

(FPC), control rod drive (CRD), raw cooling water (RCW), reactor building closed cooling water

(RBCCW), RHR, residual heat removal service water (RHRSW), EECW, and control air

systems. 

The applicant has maintained the Unit 1 systems in a physical condition during shutdown similar

to those of Units 2 and 3 during their shutdown periods. The internal operating conditions (e.g.,

water chemistry, flow rate, temperature, etc.) for these systems are the same as those found in

the operating units. These systems have experienced the same aging mechanisms and rates

as experienced by the similar Units 2 and 3 systems for shutdown conditions. The Units 1, 2,

and 3 reactor buildings are one continuous structure, and the external operating environments

of the systems are the same. Even though Unit 1 was in an extended outage, the overall

environmental conditions affecting external surfaces in Unit 1 were maintained consistent with

those of Units 2 and 3. Unit 1 had the normal ventilation systems in service, and equipment was

maintained to prevent system leakage so that the equipment was not subjected to aggressive

external conditions.

Other Unit 1 systems have been in a layup condition, and this prior layup experience has been

applied to Unit 1 license renewal. For example, Unit 1 was placed in layup using the same

philosophy, processes, and conditions as used for Unit 3. Some piping systems (or portions of

piping systems) were placed into a "wet layup" under TVA's Unit 1 layup procedure, which

include RV, RCS, RWCU, portions of RHR, CS, and feedwater (FW) systems. The water

chemistry within these Unit 1 piping systems was monitored for compliance with the water

quality requirements. Thus, it would not be expected that a different aging mechanism or rate

would exist in wet layup compared to what would have occurred if the systems were in normal

operation. The full scope of BWRVIP inspections have been performed on the Unit 1 reactor

vessel as part of the restart project. No adverse effects from the layup period were found, and

repairs/ replacements not related to layup will be performed as required. The reactor water

recirculation system and reactor water cleanup system piping, both large bore and small bore,

have been replaced. The RHR and CS piping that was in wet layup has also been replaced.

The piping was replaced with the same materials that were used in Units 2 and 3. Ultrasonic

inspections of the FW piping have confirmed that the piping does not exhibit adverse effects

from the wet layup period. Thus, extensive layup experience has been applied to the Unit 1

license renewal.

Some Unit 1 piping systems (or portions of piping systems) were drained and placed in dry

layup, which included reactor core isolation cooling (RCIC), high pressure coolant injection

(HPCI), main steam (MS), RHR, CS, and FW systems. The exterior of the system/component

was maintained at nominal reactor or turbine buildings ambient conditions, which would have

been the same in Units 1, 2, and 3. Thus, the dry layup systems would have experienced aging

at a rate less than or equal to that of the corresponding Unit 2/3 system.

Some Unit 1 systems were simply drained with no controlled environment. As a result, portions

of two Unit 1 systems experienced accelerated aging. The accelerated aging of these systems
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was previously identified as part of the OE from the Unit 3 outage between 1985 and 1995.

These were portions of the Unit 1 RHRSW piping inside the reactor building and some small

bore raw cooling water piping. As explained in the beginning of SER Section 3.7, Units 2 and 3

OE was incorporated into Unit 1 aging management activities.

As stated previously, all units met the regulatory requirement and no plant-specific exemptions

were required per 10 CFR 54.17(c). However, the staff questioned the applicant’s statement of

the operating experience applicability from Units 2 and 3 to Unit 1 and are not entirely satisfied

that Unit 1 operating experience meets the intent of the Rule. The staff concludes that the Unit

1 Periodic Inspection Program will be an acceptable mitigative action and compensate for the

lack of operating experience in meeting the intent of the Rule.

1.3.2 License Renewal at Currently Licensed Power Level

Part 54 of 10 CFR 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. Section 54.29 of 10 CFR sets

forth the standards for renewing a license. This SER describes the results of the staff's safety

review. The staff while performing the safety review limited its safety finding to matters related

to the CLB and at the currently authorized power levels for which the units are licensed. These

power levels are indicated in Section 1.1 of this SER’s Introduction and General Discussion.

Even though the applicant’s original submittal dated December 31, 2003, included a renewal

request at extended power uprate (EPU) conditions for the three BFN units, the applicant by its

letter dated January 7, 2005, requested decoupling the power uprate request from the LRA. In

that submittal the applicant requested that the staff complete the review based on the current

licensed power level for each of the three units and address separately the EPU conditions after

the renewed licenses are approved. Hence all the safety findings and staff evaluations apply to

the currently authorized power levels for which each of the BFN units are currently licensed. 

1.3.3 Integration of Unit 1 Restart Modification

Ever since March 1985, Unit 1 has been on administrative hold and the applicant has

committed not to restart Unit 1 without prior approval from the staff. The applicant is currently

planning to restart Unit 1 in 2007. The element unique to Unit 1 is that restart activities include

modifying the Unit 1 licensing basis to make it consistent with the CLB of Units 2 and 3. During

the meetings with the staff during 2003, it was agreed the applicant would identify in the LRA

the Unit 1 differences that will be eliminated when restart activities are completed. To highlight

these differences, information not yet applicable to Unit 1 was marked with bolded border. This

annotation methodology is consistent with previous multi-plant LRAs submitted to the staff. LRA

Appendix F describes each of these differences, its effect on the application, the schedule for

resolution, and provides references to application sections affected. This enables the applicant

to submit an LRA based on the CLB for all three units, as well as to identify Unit 1 restart

activities relevant to the LRA. The changes are being implemented as part of Unit 1 restart

activities consistent with the changes made previously to Units 2 and 3. Thus, the applicant

states that the BFN units are essentially identical, and the application is not unit-specific with

regard to AMPs or the AMRs. 
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1.3.4 Other Regulatory Requirements

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

information. The applicant provided this general information in LRA Section 1, which it

submitted by letter dated December 31, 2003.

In 10 CFR 54.19(b), the NRC requires that each LRA 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 the LRA regarding this

issue:

TVA requests that, as appropriate, conforming changes be made to the Article VII of the

indemnity agreement, and item 3 of the Attachment to the agreement, specifying the

extension agreement until the expiration date of the renewed facility operating licenses

as sought in the application.

The staff intends to make conforming changes to the indemnity agreement so that the

requirements of 10 CFR 54.19(b) will be met.

In 10 CFR 54.21, the NRC requires that each LRA must contain: (a) an IPA, (b) a description of

any CLB changes that occurred during the staff review of the LRA, (c) an evaluation of TLAAs,

and (d) an FSAR or a UFSAR supplement. Sections 3 and 4 and LRA Appendix B address the

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

license renewal requirements of 10 CFR 54.21(d).

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

least three months before the scheduled completion of the 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 UFSAR supplement. The

applicant submitted an update to the LRA by letter dated January 31, 2005, which summarized

the changes to the CLB that have occurred during the staff’s review of the LRA. This

submission satisfies the requirements of 10 CFR 54.21(b) and is still under staff review.

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

technical specifications (TSs) 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 BFN. 

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 will incorporate the ACRS report once it

is issued. SER Section 6 will document the findings required by 10 CFR 54.29. 

The final plant-specific supplement to the GEIS was issued on June 23, 2005, and documents

the staff's evaluation of the environmental information required by 10 CFR 54.23.
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1.4 Interim Staff Guidance

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

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

lessons learned address the staff's performance goals of maintaining safety, improving

effectiveness and efficiency, reducing regulatory burden, and increasing public confidence.

Interim staff guidance (ISG) is documented for use by the staff, industry, and other interested

stakeholders until it is incorporated into the license renewal guidance documents such as the

SRP-LR and the GALL Report.

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

sections in which the staff addresses ISG issues.

ISG Issue

(Approved ISG No.)

Purpose SER Section

GALL Report presents one

acceptable way to manage

aging effects

(ISG-1)

This ISG clarifies that the

GALL Report contains one

acceptable way, but not the

only way, to manage aging

for license renewal.

N/A

SBO Scoping

(ISG-2)

The license renewal rule

10 CFR 54.4(a)(3) includes

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.

2.1.3

Concrete AMP

(ISG-3)

Lessons learned from the

GALL demonstration project

indicated that GALL is not

clear on whether concrete

requires an AMP.

3.5.2.2.8
ISG Issue

(Approved ISG No.)

Purpose SER Section

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FP System Piping

(ISG-4)

This ISG clarifies the staff

position for wall-thinning of

the FP piping system in

GALL AMPs XI.M26 and

XI.M27.

The staff's new position is

that there is no need to

disassemble FP piping, as

disassembly can introduce

oxygen to FP piping, which

can accelerate corrosion.

Instead, a non-intrusive

method, such as volumetric

inspection, should 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

Halon/carbon dioxide system

inspections for charging

pressure, valve line-ups, and

the automatic mode of

operation test from GALL;

the staff considers these test

verifications to be operational

activities.

3.0.3.2.17
ISG Issue

(Approved ISG No.)

Purpose SER Section

1-14

Identification and Treatment

of Electrical Fuse Holders

(ISG-5)

This ISG includes electrical

fuse holders AMR and AMP

(i.e., same as terminal blocks

and 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.

2.1.3.2.3

3.6.2.3.1

Scoping for fire protection

equipment

(ISG-7)

This ISG provides

clarification of the fire

protection systems,

structures, and components

scoping to whether the scope

would expand to include

(BTP) APSCB 9.5-1

2.1.3.1.2

The ISG Process

(ISG-8)

This ISG provides

clarification and update to

the ISG process on Improved

License Renewal Guidance

Documents.

N/A
ISG Issue

(Approved ISG No.)

Purpose SER Section

1-15

Standardized Format for

License Renewal

Applications

(ISG-10)

The purpose of this ISG is to

provide a standardized

license renewal application

format for applicants.

N/A

1.5 Summary of Open Items

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

through June 15, 2005, the staff identified the following open items (see below). An issue is

considered open if the applicant has not presented a sufficient basis for resolution. Each open

item (OI) has been assigned a unique identifying number.

OI-2.4-3: (Section 2.4 - Drywell Shell Corrosion)

Supplement 1 of Information Notice (IN) 86-99 indicates that, if leakage from the flooded

reactor cavity is not monitored and managed, there is a potential for corrosion of the cylindrical

portion of drywell shell. As this corrosion would initiate in the non-inspectible areas of the

drywell, it cannot be monitored by IWE inspections. Moreover, this degradation of drywell shell

can occur even if there is very little water found in the sand-pocket area of the drywell. Thus,

the reactor building to drywell refueling seal becomes a non-safety-related (NSR) item that can

affect the integrity of the drywell shell (which is a pressure boundary component) during the

period of extended operation, and falls under the requirement of 10 CFR 54.4(a)(2). For two

BWR plants, the staff accepted an alternative to managing the aging of the seal. The alternative

is to periodically perform ultrasonic testing (UT) of the cylindrical portion of the drywell shell with

an acceptable sampling program, as part of containment inservice inspection (ISI) program.

After reviewing the response to RAI 3.5-4 (in the applicant's letter dated January 31, 2005)

related to the operating experience of drywell shell corrosion at all three units, the staff came to

the conclusion that the applicant should manage the aging (leakage) of refueling seals,

therefore, this is identified as OI 2.4-3.

The applicant responded to OI 2.4-3 by letter dated May 31, 2005. BFN did not include the

refueling seals at the top of the drywell in the scope of license renewal and provided the

following technical basis for that conclusion: The drywell-to-reactor building refueling seal and

the reactor pressure vessel (RPV)-to-drywell refueling seal, in conjunction with the refueling

bulkhead, provide a watertight barrier to permit flooding above the RPV flange while preventing

water from entering the drywell. Providing a watertight barrier to permit flooding above the RPV

flange in support of refueling operations is an NSR function. In 10 CFR 54.4(a), the criteria that

determine whether plant systems, structures, and components are within the scope of license

renewal are set forth. The refueling seals do not satisfy any of the requirements set forth in

10 CFR 54.4(a)(1). The refueling seals are NSR, and they are not relied upon to remain

functional during design basis events. Thus, the refueling seals are not brought within the

scope of license renewal by 10 CFR 54.4(a)(1).
1-16

In a letter dated November 16, 2005, the applicant stated that for Unit 1 it will perform one-time

confirmatory ultrasonic thickness measurements on the vertical cylindrical area immediately

below the drywell flange. For Units 2 and 3, it will perform the same testing in the portion of the

cylindrical section of the drywell in a region where the liner plate is 0.75 inches thick. This will

provide a bounding condition since the nominal thickness of the wall in this region has the least

margin. The applicant committed to perform these ultrasonic thickness measurements prior to

the Unit 1 restart, and prior to the period of extended operation for Units 2 and 3. The staff

found this acceptable; therefore, OI 2.4-3 is closed.

OI-4.7.7: (Section 4.7.7 - Stress Relaxation of the Core Plate Hold-Down Bolts)

In LRA Section 4.7.7, the loss of preload of the core plate hold-down bolts due to thermal and

irradiation effects was evaluated in accordance with the requirements of 10 CFR 54.21(c)(1)(ii).

For the 40-year lifetime, the Boiling Water Reactor Vessel and Internals Project (BWRVIP)-25

concluded that all core plate hold-down bolts will maintain some preload throughout the life of

the plant. For the period of extended operation, the expected loss of preload was assumed to

be 20 percent, which bounds the original BWRVIP analysis that was prepared to bound the

majority of plants, including BFN units after operating for 20 additional years. With a loss of 20

percent in preload, the core plate will maintain sufficient preload to prevent sliding under both

normal and accident conditions. Based on this assumption, the applicant concluded that the

loss of preload is acceptable for the period of extended operation.

In RAIs 4.7.7-1, 4.7.7-2, and follow ups, the staff requested the applicant to demonstrate how

the BWRVIP-25 analysis can be applied to the BFN units based on the configuration and the

geometry of core plate hold-down bolts and the reactor environment (temperature and neutron

fluence) assumed in the original report. In its letter dated September 6, 2005, the applicant

provided the vendor’s plant-specific calculations that will validate the assumptions as stated

above. However, the staff found that the methodology used did not follow the staff’s approved

BWRVIP-25 analysis; therefore, it requested additional information. In its letter dated November

16, 2005, the applicant provided supplemental responses and identified several of the staff’s

concerns raised during a teleconference on October 18, 2005. The applicant took the staff’s

comments under advisement and committed to perform a plant-specific analysis consistent with

BWRVIP-25. This analysis will be submitted for the staff’s review two years prior to the period

of extended operation. The staff considers this acceptable; therefore, OI 4.7.7 is closed.

OI-3.0-3 LP: (Section 3.0 - B.2.1.42, Unit 1 Periodic Inspection Program)

During the 526th meeting of the Advisory Committee on Reactor Safeguards, October 6-7,

2005, the ACRS reviewed the LRA for the BFN Units 1, 2, and 3, and the associated SER with

open items prepared by the staff. Though the Committee agreed with the staff that periodic

inspections of systems and components that were not replaced are appropriate and necessary,

it was not clear which systems will be included in the scope of the Unit 1 Periodic Inspection

Program, since no further attributes of this future program have been provided in the SER. The

main attributes of the program, including the intended scope, need to be defined in the final

SER. The Committee stated that periodic inspections are the most significant compensating

actions for the lack of plant-specific operating experience of BFN Unit 1 and It was not possible

to judge the adequacy of this important program since insufficient information has been

provided. As a result of the Committee’s review, the staff elevated this issue from a
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confirmatory item to an open item and requested the applicant to provide details of the periodic

inspection program prior to issuance of the final SER. This is open item 3.0.3.

When the staff briefed the Committee on the SER with open items during the October 5-6, 2005

meeting, it omitted a description of this new plant-specific program called “B.2.1.42 - Unit 1

Periodic Inspection Program.” The SER described the staff's review of information submitted to

the NRC through June 15, 2005, the cutoff date for consideration in the SER with open items.

Staff has since received details of this AMP titled, “B.2.1.42 - Unit 1 Periodic Inspection

Program.“ The staff review and evaluation of the program is included in this final version of the

SER in Section 3.0.3.3.5. This closes open item 3.0.3. 

1.6 Summary of Confirmatory Items

As a result of the staff's review of the LRA for BFN, including additional information and

clarifications submitted to the staff through June 15, 2005, the staff identified the following

confirmatory items (CIs). An issue is 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 CI has been assigned a unique identifying number. The items identified in this

section have been properly closed by the technical staff.

CI 3.3.2.35-1: (Section 3.3 Bolting in Auxiliary Systems)

For auxiliary system closure bolting, the staff was concerned that cracking and loss of preload

are not entirely addressed by either the American Society of Mechanical Engineers (ASME)

Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program or Bolting

Integrity Program. Although ASME Section XI requires bolt torquing loads to be in accordance

with ASME Section III for replacement of Class 1 and 2 bolting, no bolt torquing requirements

are specified for Class 3 bolting, NSR bolting or bolting that is reused after being removed for

maintenance. The staff raised these issues in RAI 3.3.32.35-1.

The staff reviewed the applicant's response dated March 16, 2005, and found the response to

be reasonable and acceptable. The applicant provided additional information to clarify that

cracking and loss of preload in bolting are being effectively managed. However, the response

did not provide the results of any self assessments, inspections, or maintenance activities, and

operating experience to determine if closure bolting in auxiliary systems was effectively

managed at BFN for cracking and loss of preload. The staff discussed this issue with the

applicant in a teleconference, and the verification of this confirmatory item was addressed

during the AMP inspection performed on September 2005. In the inspection report, letter dated

November 7, 2005, the staff concluded that the bolting practices in BFN are functioning

adequately; therefore, CI 3.3.2.35-1 is closed.

CI-B.2.1.36 (Section B.2.1.36, Structures Monitoring Program)

The staff had a follow-up question in a May 4, 2005, teleconference regarding evaluation of

inspection personnel qualification based on industry guidance, the American Concrete Institute

(ACI) 349.3R-96 as stated in the Structures Monitoring Program. The staff stated that this

industry guidance alone will not be adequate to qualify the inspectors for the examination of

steel supports for the Structures Monitoring Program. The staff requested that the applicant

reevaluate the program element from previous staff positions and submit the description for
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staff review. In its response to a follow up to RAI B.2.1.33-1, by letter dated May 31, 2005, the

applicant responded to the staff’s question and committed (letter dated December 12, 2005) to

manage the aging effects of Class MC supports under ASME Code Section XI Subsection IWF.

The applicant also agreed to include the inspector’s qualification in accordance with the

requirements of ASME Code Section XI Subsection IWF and not per the BFN Structures

Monitoring Program. The staff found this acceptable; therefore, CI-B.2.1.36 is closed.

1.7 Summary of Proposed License Conditions

As a result of the staff's review of the LRA, including subsequent information and clarifications

provided by the applicant, the staff identified four proposed license conditions.

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

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

issuance of the renewed licenses.

The second license condition requires the future activities identified in the FSAR supplement to

be completed prior to entering the period of extended operation.

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

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

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

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

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

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

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

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

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

The fourth license condition is satisfactory completion of the thirteen Unit 1 restart commitments

that are discussed in LRA Appendix F (see SER Section 2.6). Successful completion of these

restart activities provides a necessary regulatory framework for review of the LRA and is a staff

assumption fundamental throughout the staff safety review. When completed, the CLB of Unit 1

will be consistent with the CLB of Units 2 and 3. Completion of these activities is a condition to

be met prior to power operations of Unit 1.
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SECTION 2

STRUCTURES AND COMPONENTS SUBJECT TO AGING

MANAGEMENT REVIEW

2.1 Scoping and Screening Methodology

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 54.21, “Contents of

Application — Technical Information,” requires that each application for license renewal contain

an integrated plant assessment (IPA). Furthermore, the IPA must list and identify those

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

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

accordance with 10 CFR 54.4. LRA Sections 2.1.4 and 2.1.5 of the license renewal application

(LRA) describe the applicant’s process for identifying these structures and components (SCs)

and provide the scoping and screening results for those components, subcomponents,

structural members, and commodity groups that are subject to an AMR in accordance with LRA

Section 3.0.

In LRA Section 2.1, “Scoping and Screening Methodology,” the applicant described the scoping

and screening methodology used to identify SSCs at the Browns Ferry Nuclear Plant (BFN)

within the scope of license renewal and SCs that are subject to an AMR. The staff reviewed the

applicant’s scoping and screening methodology to determine if it meets the scoping

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

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

requirements of the Rule, the Statement of Consideration (SOC) for the Rule, and the guidance

presented by the Nuclear Energy Institute (NEI), “Industry Guideline for Implementing the

Requirements of 10 CFR Part 54 - The License Renewal Rule,” Revision 3, March 2001,

(NEI 95-10). In addition, the applicant considered the Nuclear Regulatory Commission (NRC)

staff’s correspondence with other applicants and with the NEI in the development of this

methodology. Scoping and screening were performed as an integrated review at the

system/structure level. Screening was performed on a component-level basis, and the scoping

results were reviewed and revised as required to be consistent with the screening results. The

short-lived passive components that could be excluded from an AMR on the basis of a qualified

life or a specified replacement time period were identified and screened out as part of the AMR

process.

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 SCs that are subject to an

AMR as required by 10 CFR 54.21(a)(1). LRA Section 2.1.2 discusses the application of the
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10 CFR 54.4(a) scoping criteria; Section 2.1.3 provides a discussion of the documentation that

was used to perform scoping and screening; and LRA Sections 2.1.4 and 2.1.5 describe the

scoping and screening methodology.

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:

Structures”; and Section 2.5, “Scoping and Screening Results: Electrical and Instrumentation

and Control Systems” amplify the process the applicant used to identify the SCs that are

subject to an AMR. LRA Section 3, “Aging Management Review Results,” contains the following

information: 

 • Section 3.1, “Aging Management of Reactor Vessel, Internals, and Reactor Coolant

System”

 • Section 3.2, “Aging Management of Engineered Safety Features Systems”

 • Section 3.3, “Aging Management of Auxiliary Systems”

 • Section 3.4, “Aging Management of Steam and Power Conversion Systems”

 • Section 3.5, “Aging Management of Containment, Structures and Component Supports”

 • Section 3.6, “Aging Management of Electrical and Instrumentation and Controls”

LRA Section 4, “Time-Limited Aging Analyses,” contains the applicant’s identification and

evaluation of time-limited aging analyses (TLAAs).

2.1.2.1 Scoping Methodology

In LRA Section 2.1, the applicant described the methodology used to scope systems and

structures pursuant to the requirements of 10 CFR 54.4(a). The applicant identified differences

between the current licensing basis (CLB) for Unit 1 and the CLB for Units 2 and 3, and

documented them in LRA Appendix F. The applicant stated that the differences between CLBs

will be resolved before the restart of Unit 1, so that the CLB for Unit 1 will be consistent with

Units 2 and 3. The applicant’s scoping methodology, as described in the LRA, is outlined in the

sections below.

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

The applicant described the general approach to scoping SSCs that are safety-related (SR),

nonsafety-related (NSR) affecting SR, or credited with demonstrating compliance with certain

regulated events in LRA Section 2.1.2, “Application of Scoping Criteria in 10 CFR 54.4(a).” The

scoping approaches specific to each of the three 10 CFR 54.4(a) scoping criteria are described

in the following sections. 

Application of the Scoping Criteria in 10 CFR 54.4(a)(1). In LRA Section 2.1.2.1,

"10 CFR 54.4(a)(1) - Safety-Related," the applicant discussed the scoping methodology as it

relates to SR criteria in accordance with 10 CFR 54.4(a)(1). With respect to the SR criteria, if

one or more of the three SR criteria were met, the applicant determined that the function was

an SR intended function, and included the corresponding SR SSCs within the scope of license

renewal that are relied upon to remain functional during and following/ a design basis event
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(DBE) as defined in 10 CFR 50.49(b)(1) and are based on reviews of plant accident analyses

and evaluations.

Application of the Scoping Criteria in 10 CFR 54.4(a)(2). In LRA Section 2.1.2.2,

“10 CFR 54.4(a)(2) - Nonsafety-Related SSCs Whose Failure Could Prevent Satisfactory

Accomplishment of Safety-Related Functions,” the applicant discussed the methodology used

to identify SSCs meeting the 10 CFR 54.4(a)(2) NSR license scoping criteria. Specifically, the

applicant considered the following SSCs to be in the scope of 10 CFR 54.4(a)(2):

 • SCs, such as pipe whip restraints, that provide protection to SR SSCs to be in the scope

of 10 CFR 54.4(a)(1) rather than 10 CFR 54.4(a)(2) SSCs

 • Liquid-filled NSR SSCs directly connected to SR SSCs

 • NSR SSCs that are not directly connected to SR structures such as, reactor buildings,

primary containment structures

 • NSR air/gas and heating, ventilation, and air conditioning (HVAC) systems that could

prevent the satisfactory accomplishment of an SR function

In LRA Section 2.1.2.2, the applicant described the methods and rationale used to scope each

of the above categories of NSR SSCs in the LRA. The applicant’s review encompassed the

DBEs considered in these documents. The NSR SSCs already included within the scope of

license renewal for 10 CFR 54.4(a)(3) were not identified for inclusion under 10 CFR 54.4(a)(2).

Application of the Scoping Criteria in 10 CFR 54.4(a)(3). In LRA Sections 2.1.2.3, “10 CFR 54.4

(a)(3) - The Five Regulated Events,” and 2.1.3.4, “Specific Scoping Documents for Regulated

Events,” the applicant discussed the methodology used to identify SSCs credited in performing

a function that demonstrates compliance with regulations for fire protection, environmental

qualification (EQ), anticipated transient without scram (ATWS), and station blackout (SBO)

pursuant to 10 CFR 54.4(a)(3) license renewal scoping criteria. The applicant did not address

pressurized thermal shock (PTS) because Browns Ferry units are boiling water type reactors to

which this criterion does not apply. 

2.1.2.1.2 Documentation Sources Used for Scoping and Screening

In LRA Section 2.1.3, “Documentation Sources Used for Scoping and Screening,” the applicant

listed sources that were used as input during the license renewal scoping and screening

process:

 • updated final safety analysis report (UFSAR)

 • safe shutdown analysis (SSA) calculation

 • Maintenance Rule documentation

 • CLB and design-basis documents (design criteria documents and calculations,

qualitative assessments and analyses, quantitative computations)

 • controlled plant component database (also known as enterprise maintenance planning

and control (EMPAC)) 

 • site drawings
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The applicant stated that these sources were 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)-(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 2.1.4, “Scoping Methodology,” the applicant stated that the scoping

methodologies used to identify mechanical, electrical, and instrumentation and control (I&C)

systems and structures were described under the respective disciplines. In general, the

applicant created a list of systems and structures from the EMPAC, site drawings, and the

structures’ design documents, UFSAR, Maintenance Rule documents, and other plant design

documents. The methodologies for individual disciplines are discussed below.

Mechanical Component Scoping. In LRA Section 2.1.4.1, the applicant described the scoping

methodology for components within SR and NSR mechanical systems. For every mechanical

system, the applicant applied the following scoping process: (1) identify system intended

functions, (2) determine system evaluation boundary, and (3) create license renewal drawings.

The applicant used information from the SSA calculation, the UFSAR, and other applicable

documents to identify those systems that perform intended functions as defined in

10 CFR 54.4(a)(1).

A summary was prepared for each system that listed the identified system intended functions

and the 10 CFR 54.4 criteria that caused the system to be within the scope of license renewal.

Those systems for which no functions were identified as satisfying any of the three scoping

criteria were classified as systems outside the scope of license renewal, and no further

evaluation was performed. After identifying the system intended functions, the applicant

established the system evaluation boundary, which identifies the portions of the system that are

required to perform an intended function. Included in the evaluation boundary are the passive,

long-lived components needed for the system to perform its intended functions. The

components within the system evaluation boundary were reviewed according to the criteria of

10 CFR 54.4(a) used during evaluation of the system.

Electrical and Instrumentation and Control System Component Scoping. In LRA

Section 2.1.4.2, the applicant described the scoping methodology for components in SR and

NSR electrical and I&C systems. Specifically, the applicant selected the electrical and I&C

components from the EMPAC list and evaluated them against the 10 CFR 54.4(a) criteria. The

applicant reviewed NEI 95-10, and BFN documents such as plant drawings and EMPAC to

determine the complete set of electrical commodities installed at BFN. These electrical

commodities were included in the license renewal scope for evaluation using the spaces

approach. The spaces approach identified the electrical and I&C commodity groups that are

installed in the plant and the limiting environmental conditions for each group. The only

exception to the spaces approach was in the SBO offsite power restoration methodology. The

applicant used the conventional system evaluation methodology (i.e., mechanical system

scoping) to identify the system intended functions and subsequent SCs within the scope of

license renewal. As part of this review, the applicant reviewed the SSA calculation, UFSAR
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descriptions, Maintenance Rule documents, CLB, and design-basis documents to determine

the system’s safety classification level, and to identify the system intended functions. 

Structural Component Scoping. In LRA Section 2.1.4.3, the applicant described the scoping

methodology for components within SR and NSR structures. Specifically, the applicant stated

that the list of structures used for scoping was developed from the review of design drawings,

design criteria document, and Maintenance Rule documentation, which include items such as

free-standing buildings and structures, primary containment shell, tank foundations, manholes,

tunnels, duct banks, and earthen structures. The applicant relied on the design criteria

document for structures and the UFSAR to identify the safety classification of structures and

structural components. 

For review purposes, seismic Class I structures and structural components were considered

SR. Structure functions were evaluated against the 10 CFR 54.4(a) criteria and structure

intended functions were identified. The structure interfaces were examined and, in those

instances where a failure of a structure could prevent a satisfactory accomplishment of any SR

intended function or adversely impact other SR structures, that structure was identified and

included within the scope of license renewal. The applicant reviewed detailed structural

drawings for structures determined to be within the scope of license renewal to identify

structural components. For structures within the scope of license renewal, all structural

components required to support the intended functions were identified as within the scope of

license renewal.

2.1.2.2 Screening Methodology

In LRA Section 2.1.5, “Screening Methodology,” the applicant described the process of

identifying the structures and components that are subject to an AMR. The applicant stated

that, in accordance with 10 CFR 54.21(a)(1)(i), the screening process used the industry

guidance contained in NEI-95-10, Revision 3, Appendix B, “Typical Structure, Component and

Commodity Groupings and Active/Passive Determinations for the Integrated Plant

Assessment,” to identify SSCs from items within the scope of license renewal that require AMR.

The identified SSCs were then sorted into groups that (1) perform an intended function, as

described in 10 CFR 54.4, without moving parts or without a change in configuration or

properties; and (2) those that are not subject to replacement based on a qualified life or

specified time period. Components were then evaluated to determine which were long-lived.

Components were considered long-lived unless specific plant documentation indicates the

component is replaced at intervals of less than forty years.

2.1.2.2.1 Mechanical Component Screening

In LRA Section 2.1.5.1, the applicant described the component screening for mechanical

systems as a continuation of the component scoping activity. The applicant evaluated each

component within the scope of license renewal to determine if it has a passive function. If a

component has a passive function that supports a system intended function, and if the

component was determined to be long-lived, then the component was considered subject to an

AMR. The applicant reviewed maintenance procedures, records, and vendor recommendations

to determine if a component is long- or short-lived. 
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2.1.2.2.2 Structural Component Screening

In LRA Section 2.1.5.3, the applicant described the methodology used to screen the structural

components within the scope of license renewal. The screening methodology classified

in-scope structural components as passive consistent with the guidance found in NEI 95-10,

Appendix B. In-scope structural components such as elastomers, which are subject to

replacement in specified intervals, were considered short-lived and were excluded from an

AMR. The structural screening included certain structural components in electrical systems

(e.g., cable trays) and mechanical systems (e.g., pipe supports).

2.1.2.2.3 Electrical and Instrumentation and Control System Component Screening

Methodology

In LRA Section 2.1.5.2, the applicant described the screening methodology for electrical and

I&C components. The applicant had classified all electrical and I&C components within the

scope of license renewal based on the spaces approach, with the exception of components in

the SBO offsite power restoration flow path. Components were characterized as active or

passive, based on NEI 95-10, Appendix B, guidance. Long-lived commodity groups were

identified by using industry and BFN experience. The spaces approach identifies the electrical

and I&C commodity groups that are installed in the plant and the limiting environmental

conditions for each group. The spaces approach then determines if any area environment is

more severe than the limiting environment for the commodity group. If the area environment is

more severe than a commodity group’s limit, and if a component in the commodity group is

actually located in the area, an AMR is required for that commodity group.

2.1.3 Staff Evaluation

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

guidance contained in Section 2.1, "Scoping and Screening Methodology," of U.S. Nuclear

Regulatory Commission Regulatory Guide (NUREG)-1800, "Standard Review Plan for Review

of License Renewal Applications for Nuclear Power Plants" (SRP-LR). 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 sections of the LRA using the guidance contained in 

the SRP-LR:

 • 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), (a)(2), and (a)(3),
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 • Section 2.2, "Plant-Level Scoping Results”; Section 2.3, "Scoping and Screening

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

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

Instrumentation and Control Systems," to 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 audit at the Tennessee

Valley Authority (TVA) corporate offices in Chattanooga, TN, from June 7 to 10, 2004. The

focus of the audit was to ensure 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. In addition, the staff 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 results reports for the residual heat

removal service water (RHRSW) system and the emergency equipment cooling water (EECW)

system to ensure that the methodology outlined in the technical evaluations was appropriately

implemented and the results were consistent with the CLB.

2.1.3.1 Scoping Methodology

The scoping evaluations for the Browns Ferry Nuclear LRA were performed by the applicant’s

license renewal project personnel. The staff conducted detailed discussions with the applicant’s

license renewal project personnel and reviewed documentation pertinent to the scoping

process. The staff assessed whether the scoping methodology outlined in the LRA and

implementation procedures was appropriately implemented and whether the scoping results

were consistent with CLB requirements. 

2.1.3.1.1 Implementation Procedures and Documentation Sources Used for Scoping and

Screening

The staff reviewed the applicant’s scoping and screening implementation procedures to verify

that the process used to identify structures and components subject to an AMR was consistent

with the LRA and SRP-LR and that the applicant had appropriately implemented the procedural

guidance. Additionally, the staff reviewed the scope of CLB documentation sources used to

support the LRA development and the process used by the applicant to ensure that CLB

commitments has been appropriately considered during the scoping and screening process.

Scoping and Screening Implementation Procedures. The staff reviewed the following TVA

scoping and screening methodology implementation procedures and engineering documents: 

0-TI-346 Maintenance Rule Performance Indicator Monitoring, Trending, and

Reporting

0-TI-455 Mechanical Technical Evaluations For License Renewal, Revision 2 
2-8

0-TI-456 Electrical Technical Evaluations For License Renewal 

0-TI-457 Civil Technical Evaluations For License Renewal 

0-TI-458 License Renewal Time Limited Aging Analyses, Revision 1 

NEDP-21 Technical Evaluations for License Renewal, Revision 2 

NEDP-4 Q-list and UNID Control, Revision 7 

NEDP-5 Design Document Reviews

SPP-3.1 Corrective Action Program, Revision 6 

SPP-9.6 Master Equipment List, (MEL) Revision 6

In reviewing these procedures, the staff focused on the consistency of the detailed procedural

guidance with information in the LRA and the various staff positions documented in the SRP-LR

and interim staff guidance documents. The staff found that the scoping and screening

methodology instructions were generally consistent with LRA Section 2.1 and were of sufficient

detail to provide the applicant with concise guidance on the scoping and screening

implementation process to be followed during the LRA activities. 

In addition to the implementing procedures, the staff reviewed supplemental design information

including design-basis documents, system drawings, and selected licensing documentation,

that the applicant relied on during the scoping and screening phases of the review. The staff

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

SSCs identified by the applicant was consistent with the plant’s CLB.

Sources of Current Licensing Basis Information. The staff reviewed the scope and depth of the

applicant’s CLB review to verify that the methodology was sufficiently comprehensive to identify

SSCs within the scope of license renewal and SCs requiring an AMR. As defined in

10 CFR 54.3(a), the CLB is the set of NRC requirements applicable to a specific plant and a

licensee’s written commitments for ensuring compliance with, and operation within, applicable

NRC requirements and the plant-specific design basis that are docketed and in effect. The CLB

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

specifications, design-basis information documented in the most recent UFSAR, and licensee

commitments remaining in effect from docketed licensing correspondence such as applicant

responses to NRC bulletins, generic letters (GLs), and enforcement actions, as well as licensee

commitments documented in NRC safety evaluations or licensee event reports. The applicant

identified differences between the CLB for Unit 1 and the CLB for Units 2 and 3, and

documented them in LRA Appendix F. 

The staff determined that LRA Section 2.1.3 provides a description of the CLB and related

documents used during the scoping and screening process that is consistent with the guidance

contained in the SRP-LR and NEI 95-10. Specifically, the applicant provided a comprehensive

listing of documents that could be used to support scoping and screening evaluations. The

applicant noted that system descriptions and system intended functions had been identified

based on the review of the applicable sections of the UFSAR, Appendix B determinations,

Maintenance Rule scoping document, and design and licensing basis documents.
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Conclusion. Based on a review of information provided in LRA Section 2.1, a review of the

applicant’s detailed scoping and screening implementation procedures, and the results from the

scoping and screening audit, the staff concluded that the applicant’s scoping and screening

methodology had considered a scope of CLB information generally consistent with the guidance

contained in the SRP-LR and NEI 95-10. 

Quality Assurance Controls Applied to LRA Development. The staff reviewed the quality

assurance controls used by the applicant to verify that they provided reasonable confidence

that the LRA scoping and screening methodologies had been adequately implemented. The

applicant chose not to credit the existing 10 CFR 50, Appendix B quality assurance program for

the development of the LRA. However, the applicant controlled the LRA development activities

as follows:

 • Written procedures and guidelines governed implementation of the scoping and

screening methodology.

 • All final in-scope and screening information was developed by a lead technical staff

member and independently reviewed by an additional technical staff member prior to

being reviewed and approved by the program manager.

 • The applicant developed a formal database for documenting license renewal information

identified during in-scope and screening evaluations. This database was controlled in

accordance with written instructions, and access to it was strictly controlled. 

 • The LRA was reviewed and approved by an independent expert committee comprised of

experienced members of the TVA corporate engineering staff and BFN personnel.

 • The applicant conducted two program peer reviews and one self-assessment of LRA

activities to validate the implementation process and the technical accuracy of the

application.

 • The applicant instituted a training program, which required all participants in LRA

activities to be certified to perform LRA activities and to attend training on the use of

procedures, guidance documents, computer programs, and drawings.

Conclusion. The staff concluded that these quality assurance activities, which exceeded current

regulatory requirements, provided additional assurance that LRA development activities were

performed consistently with the LRA descriptions.

Training for License Renewal Project Personnel. The staff reviewed the applicant’s

implemented training process to ensure the guidelines and methodology for the scoping and

screening activities would be performed in a consistent and appropriate manner. The

applicant’s LRA staff consisted of several engineers and contractors who had gained previous

license renewal experience working on the Edwin I. Hatch LRA. The purpose of the training was

to provide a framework for ensuring that the staff assigned to the technical portion of the LRA

acquired a fundamental level of knowledge of the license renewal process and regulatory

requirements. BFN used the Nuclear Engineering Design Procedure (NEDP)-7, Engineering

Support Personnel Training, Revision 12, dated January 29, 2004, to impart training to all

personnel involved in the LRA activities. Other documents used in the training include NEDP-7

Qualifications Guides (QGs), Task-Specific QGs, License Renewal Program, NEDP-21,

Technical Evaluation for License Renewal, the Code of Federal Regulations, and NEI 95-10,
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Industry Guidelines for Implementing the Requirements of 10 CFR Part 54 - The License

Renewal Rule.

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

license renewal staff, including both experienced and non-experienced members, who

performed scoping and screening activities. The staff did not identify any adverse findings. 

Additionally, based on discussions with the applicant’s license renewal personnel 

during the audit, the staff verified that the applicant’s license renewal staff were knowledgeable

concerning the license renewal process requirements and the specific technical issues within

their areas of responsibility. The staff found that the applicant’s license renewal training records

were considered quality-related records and that these records were accurate, comprehensive,

and complete.

Conclusion. The results from the scoping and screening audit indicate that the applicant

considered the information in the CLB for Units 1, 2, and 3 in developing the scoping and

screening methodology. The CLB documentation review methodology was capable of

identifying the intended functions of the SSCs in a manner consistent with the requirements of

10 CFR 54.4 and 10 CFR 54.21. In addition, the applicant applied appropriate quality controls

during the development of the application and adequately trained the applicable personnel. The

staff concluded that the applicant had considered all relevant information during the preparation

of the scoping and screening methodologies.

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

The staff evaluated the application of the scoping criteria for the methodology for scoping SRand NSR-related SSCs and SSCs relied upon to demonstrate compliance with regulated events

pursuant to 10 CFR 54.4(a). The results of the staff’s evaluation are described below.

Application of the Scoping Criteria in 10 CFR 54.4(a)(1). Pursuant to 10 CFR 54.4(a)(1), the

applicant must consider all SR SSCs that are relied upon to remain functional during and

following DBEs to ensure the following functions: (1) maintain the integrity of the reactor coolant

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

shutdown condition, or (3) maintain the capability to prevent or mitigate the consequences of

accidents that could result in potential offsite exposures comparable to those referred to in

10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2) or 10 CFR 100.11.

During the scoping and screening methodology audit, the staff questioned how non-accident

DBEs, particularly DBEs that may not be described in the UFSAR, were considered during

scoping. The applicant responded by identifying the DBEs applicable to BFN, including external

hazards such as fire, earthquakes, flooding, wind and missiles, and high-energy line breaks.

Additional DBEs were evaluated in the SSA calculation that was used by the applicant as a

primary source for the purposes of identifying SSCs within the scope of license renewal. The

SSA calculation was reviewed by the staff and discussed with the applicant. The staff found that

the report contained a concise and detailed evaluation of approximately 35 events, and included

appropriate CLB documentation references to support the review. The staff concluded that the

applicant considered a scope of DBEs that was consistent with the guidance contained in the

SRP-LR.
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In addition, the staff evaluated the guidance documents governing the applicant’s evaluation of

SR SSCs: specifically, BFN standard department procedures; NEDP-5, “Design Document

Reviews,” Revision 2; NEDP-21, “Technical Evaluations for License Renewal,” Revision 2; and

license renewal instruction series 0-TI-455 through 458. Guidance was established for the

preparation, review, verification, and approval of the scoping evaluations to assure the

adequacy of the results of the scoping process. During the scoping and screening audit the

staff reviewed the guidance and discussed the scoping approach with the applicant.

Specifically, the staff reviewed a sample of the license renewal scoping results for the residual

heat removal (RHR) system to provide additional assurance that the applicant adequately

implemented its SR scoping methodology. The system scoping sheet identified the RHR

system as SR with additional NSR systems supporting its operation. The evaluation identified

the RHR system as meeting several of the 10 CFR 54.4(a)(3) criteria including: (1) EQ, (2) fire

protection, and (3) SBO. All the system safety descriptions were listed, and the licensing basis

calculations supporting those determinations were appropriately referenced. The report

identified the cognizant license renewal staff members who prepared and verified the results.

The applicant documented the information on a scoping results form. The applicant created a

license boundary drawing in which every component in the system was identified by its unique

component identifier (UNID) number, the description of the component, whether it was SR or

NSR, whether it supported any of the regulated events, and the commodity material group to

which it belonged (valve or pump etc.). The staff determined that the applicant identified and

used pertinent engineering and licensing information to support the scoping determinations for

the items sampled, and found the preparation, review, and approval of the scoping results to be

effective for the development and evaluation of SR functions and subsequent identification of

SSCs within the scope of license renewal.

The applicant reviewed the license renewal drawings in conjunction with physical drawings and

component listings from EMPAC to determine the in-scope components that met the SR

scoping criterion. All components identified as SR using the SR classification field in the

EMPAC were considered for inclusion within the scope of the license renewal project. The

applicant noted that the EMPAC safety-classification field was prepared many years ago using

a definition for SR that was not necessarily the same as the definition of SR as described in the

Rule. The staff reviewed the safety classification criteria used to determine the EMPAC safety

classification to verify consistency with the 10 CFR 54.4(a)(1) criteria. The staff determined that

the nuclear SR definition used by the applicant in its safety classification program did not

include all the exposure limitations referenced in 10 CFR 54(a)(1)(iii). Specifically, procedures

BFN-50-739, “Classification of Structures, Systems, and Components, Revision 3,” and

NEDP-4, “Q-list and UNID Control, Revision 7,” did not include a reference to the offsite

exposure limitations contained in 10 CFR 50.67(b)(2) for use of an alternate source term (AST). 

Based on the above, the staff 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 request for additional information (RAI) as discussed below. 

In RAI 2.1-1, dated July 30, 2004, the staff requested the applicant to provide additional

information to describe the SR classification definitions that were used in developing the list of

SSCs for the license renewal scoping and screening process, and describe how the offsite

exposure limitations were factored into the LRA.
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In its response, by letter dated September 3, 2004, the applicant stated:

Consistent with 10 CFR 54.4(a)(1)(iii), BFN utilized a definition of safety-related that

incorporated potential offsite exposures as follows: "The capability to prevent or mitigate

the consequences of accidents which could result in potential offsite exposures

comparable to those referred to in 10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), or

10 CFR 100.11, as applicable." The applicable regulation for BFN is 10 CFR 100.11.

10 CFR 50.34 applies to applications for a construction permit and as such is not

applicable to BFN. 10 CFR 50.67(b)(2) is applicable to plants revising their current

accident source term to Alternative Source Term (AST). TVA has submitted a request

for an amendment to the BFN Units 1, 2, and 3 facility operating licenses supporting a

full scope application of the AST methodology. The application of AST is not approved

by NRC hence, 10 CFR 50.67(b)(2) is not applicable to BFN. The BFN safety-related

equipment classification and the SSCs included in the scope of license renewal continue

to be based on potential offsite exposures contained in 10 CFR 100. Based on a review

of TVA’s AST submittal it is expected no new systems or component types will be added

within the License Renewal scope that are not already identified in the application.

On September 27, 2004, the staff approved the applicant’s license amendment request

regarding AST per 10 CFR 50.67(b)(2) for offsite dose exposure as the CLB for BFN. Since the

definition of SR components as applied to the scoping of components in the LRA can be either

10 CFR 50.67(b)(2) or 10 CFR 100.11, as applicable, and the AST submittal did not add new

components within the LRA scope, it does not impact the SR definition. Hence the staff

concluded that, consistent with 10 CFR 54.4(a)(ii), BFN utilized a definition of SR that included

the capability to shut down the reactor and maintain it in a safe shutdown condition. The staff

determined that the applicant’s response is acceptable. The staff’s concern described in

RAI 2.1-1 is resolved.

Conclusion. The staff reviewed a sample of the license renewal database 10 CFR 54.4(a)(1)

scoping results and discussed the methodology and results with the applicant’s license renewal

project personnel. The staff verified that the applicant had identified and used pertinent

engineering and the CLB in order to determine the SSCs required to be within the scope of

license renewal in accordance with the 10 CFR 54.4(a)(1) criteria. On the basis of a review of

the applicant’s methodology and evaluation of a sampling of scoping results and responses to

the staff’s RAI, the staff concluded that the applicant’s SR scoping methodology provided

reasonable assurance that SSCs meeting the scoping criteria of 10 CFR 54.4(a)(1) were

included within the scope of license renewal.

Application of the Scoping Criteria in 10 CFR 54.4(a)(2). Section 54(a)(2) of 10 CFR requires, in

part, that the applicant consider all NSR SSCs whose failure could prevent satisfactory

accomplishment of any of the functions identified in paragraphs 10 CFR 54(a)(1)(i),

10 CFR 54(a)(1)(ii), or 10 CFR 54(a)(1)(iii) to be within the scope of the license renewal. 

In addition, by letters dated December 3, 2001, and March 15, 2002, the NRC issued a staff

position to the NEI, which described areas for applicants to consider and options it expects

applicants to use to determine which SSCs meet the 10 CFR 54.4(a)(2) criterion (i.e., all NSR

SSCs whose failure could prevent satisfactory accomplishment of any SR functions identified in

paragraphs 10 CFR 54.4(a)(1)(i)-(iii)). The December 3, 2001, letter provided specific examples

of operating experience that identified pipe failure events (summarized in Information Notice
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(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 staff

considers acceptable to determine which piping systems should be included within the scope of

license renewal based on the 10 CFR 54.4(a)(2) criterion. The March 15, 2002, letter, further

described the staff’s expectations for the evaluation of non-piping SSCs to determine which

additional NSR SSCs are within the scope of license renewal. The position states that

applicants should not consider hypothetical failures, but, instead, 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 the plausibility of a failure.

Documentation would include generic communications and event reports, plant-specific

condition reports, industry reports such as significant operating experience reports (SOERs),

and engineering evaluations.

As stated in the LRA, the applicant had included in the scope of license renewal NSR SSCs

whose failure could prevent satisfactory accomplishment of any of the functions identified in

paragraphs 10 CFR 54.4(a)(1)(i)-(iii). The applicant identified SSCs satisfying criterion

10 CFR 54.4(a)(2) based on review of applicable CLB and engineering design bases and

design documents, plant-specific and industry operating experience, and industry guidance

documents.

The applicant documented the review of scoping activities in support of 10 CFR 54.4(a)(2) in an

engineering report titled “10 CFR 54.4(a)(2) Scoping Methodology.” The applicant discussed

the scoping methodology as it related to the NSR criteria in accordance with 10 CFR 54.4(a)(2).

With respect to the NSR criteria, the applicant stated that a review had been performed to

identify the NSR SSCs whose failure could prevent satisfactory accomplishment of the SR

intended functions identified in 10 CFR 54.4(a)(1).

As stated in the LRA, the applicant identified NSR SSCs whose failure could prevent

satisfactory accomplishment of a safety function. The impacts of NSR system, structure, and

component (SSC) failures were considered as either functional or spatial. In a functional failure,

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

failure, a safety function is impacted by the loss of structural or mechanical integrity of an SSC

in physical proximity to an SR component. 

Functional Failures of Nonsafety-Related SSCs. In general SSCs required to perform a function

in support of SR functions were classified as SR and included in the scope of license renewal

per 10 CFR 54.4(a)(1). For the exceptions where NSR SSCs are required to remain functional

in support of an SR function (and were not classified as SR), the supporting SSCs are included

within the scope of license renewal pursuant to 10 CFR 54.4(a)(2).

Overhead-Handling Systems. Overhead-handling systems located in structures that contain SR

SSCs were considered in scope if they had the ability to drop a load resulting in damage to an

SSC that prevents satisfactory accomplishment of an SR intended function.

Nonsafety-related SSCs Directly Attached to Safety-Related SSCs. The applicant used a

spaces approach and included all NSR liquid-filled piping and the corresponding supports that

were located in buildings or structures that contain SR equipment within the scope of license

renewal in accordance with 10 CFR 54.4(a)(2), with exceptions as discussed below. The
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applicant used plant drawings, such as flow diagrams, physical drawings, and isometric

drawings to determine which systems, or portions of systems, were located in each building or

structure. The applicant indicated that, by including within the scope of license renewal all NSR

piping and corresponding supports in buildings or structures that contain SR equipment, the

need to identify the piping up to the first seismic anchor was eliminated and that at the point

where an NSR system leaves the building or structure that contains the SR SSCs and enters a

building or structure that contains no SR SSCs, the NSR piping and supports are no longer

within the scope of license renewal. 

The staff discussed the spaces approach with the applicant and determined that, since all NSR

piping and supports in the SR structure were considered within the scope of license renewal in

accordance with 10 CFR 54.4(a)(2), the applicant had not identified any “equivalent anchors” as

a scoping boundary, but, instead, had marked scoping boundaries at the structure wall. The

staff reviewed license renewal boundary drawing 1-47E801, which showed the four main steam

lines in red (denoting within scope) in the reactor building. Where the main steam line piping

exited the reactor building and entered the turbine building, the color changed from red to black,

denoting the change from within scope to outside the scope of license renewal. 

The staff’s review of LRA Section 2.1 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 RAIs as discussed below. 

In RAI 2.1-2A, dated July 30, 2004, the staff requested the applicant provide the following:

 1. A description of the criteria used to determine that the integrity of the in-scope piping

functions will be preserved if an age-related degradation failure occurs in the attached

NSR piping.

 2. A description of how it was determined that the SR piping in the reactor building is

adequately supported so that it will remain functional if an age-related degradation

occurs in the attached NSR piping in the turbine building.

 3. A description of how the methodology ensured that the NSR piping up to first equivalent

anchor point was included within the scope of license renewal.

The applicant responded to RAI 2.1-2A(1) and (2) by letters dated September 3, 2004, and

October 18, 2004. In those responses, the applicant described the evaluation of SR and NSR

portions of the main steam piping system. Specifically, the applicant stated, in part, that the

seismic Class I portions of the four main steam lines have anchors isolating them from the

seismic Class II piping. The seismic Class I/II interface is at the anchor. The piping up to the

anchor is designed to seismic Class I requirements. The anchor locations are inside the reactor

building, outboard of the isolation valves. The piping up to the anchor, and the anchor, is

included within the scope of license renewal per 10 CFR 54.4(a)(1). 

The NSR piping segments extending from the anchors to the reactor building/turbine building

interface are qualified to seismic Class II pressure retention requirements to support secondary

containment. Since secondary containment is an SR function, these piping segments are in the

scope of license renewal and are shown in red on the license renewal drawing. This is

consistent with BFN’s scoping methodology document which states that some NSR SSCs have

been determined to perform SR intended functions (e.g., secondary containment, or main
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steam alternate leak path). As such, the applicant identified all piping supports, and other

components inside secondary containment that are required to maintain the structural integrity

of the secondary containment and verified that these SSCs were brought into scope.

Additionally, the applicant stated that it would identify any additional piping, supports, and other

components outside secondary containment that are required to maintain the structural integrity

of the secondary containment prior to the period of extended operation.

After review of the information provided by the applicant regarding its evaluation, the staff held

a teleconference with the applicant on May 3, 2005, and informed the applicant that any

additional SSCs outside secondary containment necessary to maintain the structural integrity of

the secondary containment must be identified and evaluated for aging effects as part of the

current license renewal activities. As a result, the applicant performed a supplemental review of

the SSCs associated with the secondary containment piping to identify those that are necessary

to maintain the structural integrity of the secondary containment. This supplemental review was

provided to the staff in a letter from the applicant, dated May 31, 2005. Specifically, the

applicant described its supplemental review process, which included a review of plant drawings

and piping system qualification documentation and performance of plant system walkdowns to

identify the NSR piping, supports, and other components that are within the scope of license

renewal for 10 CFR 54.4(a)(2) for secondary containment qualification. The results of this

supplemental review identified several system boundary changes and identification of several

new component types, materials, or environments that affected the AMR results. Details of the

scoping results that expanded the boundaries of these systems and revisions to the AMR

results are discussed in SER Sections 2.3, 2.4, and 3.5, respectively.

Based on the applicant’s supplemental evaluation of SSCs associated with the secondary

containment, which included a review of plant system drawing, piping and support qualification

documentation, and extensive plant system walkdowns, the staff determined that the applicant

had performed an adequate analysis to identify certain additional piping, components, and

structures to be included within the scope of license renewal. The staff concluded that the

analysis and inclusion of additional SSC’s within the scope of license renewal adequately

addressed RAI 2.1-2A(1) and (2). Therefore, the staff’s concerns described in the RAI are

resolved.

By letters dated September 3, 2004, October 18, 2004, January 31, 2005, and February 28,

2005, the applicant addressed RAI 2.1-2A(3) as discussed below. 

The applicant indicated that during the restart of Units 2 and 3, and during the current restart

process for Unit 1, the seismic Class I qualification documentation had been updated to ensure

that the analyzed configuration reflected the as-built configuration. This documentation

implements the CLB and provides the information necessary to determine the NSR piping and

components that are necessary to maintain qualification of the connected SR piping and

components. To ensure the license renewal boundaries are consistent with the CLB

requirements, the applicant performed a review of the seismic Class I qualification

documentation to identify the NSR piping, supports/equivalent anchors, and other components

that are within the scope of license renewal for 10 CFR 54.4(a)(2) for the cases where NSR

piping or components are directly connected to SR piping or components.

This review included the verification of each seismic Class I boundary identified in the CLB. The

seismic Class I boundaries could typically be included in one of the following categories:
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 • Base-Mounted Equipment (pump, heat exchanger, tank, etc.) – a rugged component

that is designed to provide support for connected piping and impose no loads on the

piping. The review assures that when base-mounted equipment implements a seismic

Class I boundary, the piping from the boundary to the equipment, and the equipment

itself, are included within the scope of license renewal.

 • Pipe Anchor – a special pipe support, which resists all six degrees of freedom, that has

been designed and installed on the piping. The review assures that when a pipe anchor

implements a seismic Class I boundary, the piping from the boundary to the pipe

anchor, and the pipe anchor itself, are included within the scope of license renewal.

 • Embedded Piping Segment – where piping is structurally attached (usually welded) to

piping that is embedded in a concrete floor or wall and acts as an anchor. The review

assures that when an embedment implements a seismic Class I boundary, the piping

from the boundary to the embedment, and the embedment itself, are included within the

scope of license renewal.

 • Large Run Line – when a branch line moment of inertia is significantly smaller than a run

line’s moment of inertia, the branch line can be decoupled from the run line. The run line

is then considered as an equivalent anchor. The review assures that in a case in which

a large run line forms a seismic Class I boundary, the large run line is included within

the scope of license renewal.

 • Piping Free End – piping qualified up to an end that has no structural connection. The

review assures that when a seismic Class I boundary is formed by a piping free end, all

of the piping and supports from the boundary to piping free end(s) are included within

the scope of license renewal.

 • Flexible Connection – where a pipe stress analysis terminates at a flexible connection

that is considered as a free end in that analysis. The review assures that when a flexible

connection forms a seismic Class I boundary, the piping and supports from the

boundary to the flexible connection are included within the scope of license renewal.

 • Overlap Regions – where a series of single or multidirectional pipe supports have been

installed to isolate one region of piping from another. The review assures that when an

overlap region forms a seismic Class I boundary all of the piping and supports in the

overlap region are included within the scope of license renewal.

The applicant indicated that the results of the review brought new portions of piping,

components of existing systems, and two additional structures within the scope of license

renewal in accordance with the requirements of 10 CFR 54.4(a)(2).

The staff determined that the applicant had performed an analysis that defined several types of

seismic Class I boundaries and had appropriately used this information to identify certain

additional piping, components, and structures to be included within the scope of license

renewal. The staff concluded that the analysis and inclusion of additional SCs within the scope

of license renewal adequately addressed RAI 2.1-2A(3). Therefore, the staff’s concern

described in RAI 2.1-2A(3) is resolved.

Nonsafety-Related SSCs in Proximity of Safety-Related SSCs. The applicant used a spaces

approach and included all NSR liquid-filled piping and the corresponding supports that are

located in buildings or structures that contain SR equipment within scope in accordance with
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10 CFR 54.4(a)(2), with exceptions as discussed below. The applicant used plant drawings,

such as flow diagrams, physical drawings, and isometric drawings to determine which systems,

or portions of systems, are located in each building or structure. 

NSR high-energy piping located in buildings or structures that contain SR equipment was

included within the scope of license renewal per 10 CFR 54.4(a)(2). The applicant had taken an

exception to this approach by not including within the scope of license renewal the NSR pipe

located in the SR-classified turbine building, although twelve SR main steam tunnel

temperature switches are located in the main steam tunnel portion of the turbine building. In

addition to the main steam lines, the main steam tunnel houses other NSR piping and

components. The staff was unable to determine if the applicant demonstrated that the twelve

temperature switches installed in the steam tunnel portion of the turbine building are adequately

protected from age-related degradation of NSR SSCs.

In RAI 2.1-2B, dated July 30, 2004, the staff requested the applicant to address whether the 12

temperature switches installed in the main steam tunnel portion of the turbine building are

adequately protected from wetting or spraying from the failure of NSR SSC components due to

age-related degradation.

In its responses, by letters dated September 3, 2004, and October 18, 2004, the applicant

addressed RAI 2.1-2B.

The applicant indicated that a design change notice (DCN) will be developed that will qualify the

circuits for wetting and spray from a moderate/low-energy line break. The DCN will replace the

temperature switch connectors and will also seal conduits as required to ensure circuit integrity

and to mitigate the consequences of a moderate/low-energy line break. The applicant indicated

that identification of moderate/low-energy, liquid-filled piping systems located in the vicinity of

the temperature switches was not necessary since the switches will be qualified for the

environment that would result from a moderate/low-energy line break. The applicant indicated

that the DCN will be implemented prior to the period of extended operation.

The staff reviewed the response to RAI 2.1-2B and determined that the applicant had indicated

that a DCN would be issued to modify the temperature switches located within the main steam

tunnel such that they would be qualified to perform in an environment resulting from a

moderate/low-energy line break. Therefore, the staff concern described in RAI 2.1-2B is

resolved.

NSR moderate/low-energy piping located in buildings or structures that contain SR equipment

was generally included within the scope of license renewal in accordance with

10 CFR 54.4(a)(2). The exceptions to inclusion within scope were identified in the LRA as the

turbine building (discussed above), intake pumping station, and the RHRSW tunnel.

In RAI 2.1-2C, dated July 30, 2004, the staff stated that in engineering report “10CFR54.4(a)(2)

Scoping Methodology,” the applicant discussed the basis for exclusion of moderate/low energy

piping located within the intake pumping station and RHRSW tunnel. The report stated that

active SR components located within the intake pumping station were environmentally qualified

and were normally exposed to outside weather conditions. In addition, the water from the NSR

moderate/low energy pipe in the intake pumping station would not adversely affect the passive

SR components (pipes or manual valves) since degradation would occur gradually over a
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period of time and system leakage would be detected prior to such degradation by plant

personnel during activities such as operator rounds, routine radiation protection surveys or

system engineer walkdowns. The same basis was applied to the potential effect of fluid from

NSR SSCs on SR SSCs within the RHRSW tunnel (which only contain passive SR SSCs).

Therefore, the staff requested that the applicant provide the additional information concerning

the basis for the conclusion that failure of moderate/low energy fluid-filled NSR SSCs in the

proximity of passive SR SSCs will not adversely affect the SR SSCs. 

By letters dated September 3, 2004, and October 18, 2004, the applicant addressed

RAI 2.1-2C, as discussed below.

The applicant reviewed the NSR fluid piping systems contained in the RHRSW tunnel and

determined that all piping systems are within the scope of license renewal, with the exception of

the 24-inch raw cooling water discharge piping, which was subsequently included within the

scope of license renewal. The applicant indicated that exposure duration was not used in the

scoping process.

In addition, the applicant reviewed the effect of water spray from NSR systems at the intake

pumping station structure. The applicant determined that the SR equipment located within the

intake pumping structure was designed for a normal operating environment of outside air, which

includes precipitation and operation in a wetted environment. The applicant revised its scoping

methodology to address components located in the lower compartments of the intake pumping

station, which are subject to submergence during the probable maximum flood. The applicant

determined that all SR passive electrical components installed at the intake pumping station are

located above probable maximum flood level and are designed to either be protected from the

effects of a wetted environment or designed to perform their function in a wetted environment.

The applicant indicated that exposure duration was not used in the scoping process. 

The staff reviewed the response to RAI 2.1-2C and determined that the applicant had not taken

credit for exposure duration to exclude any NSR piping located within the RHRSW tunnel from

scoping consideration. The applicant had included all applicable NSR piping within the scope of

license renewal for the RHRSW tunnel. In addition, the applicant had determined that SR

components in the intake pumping station, that are located above the probable maximum flood

level are either protected from the effects of a wetted environment or designed to perform their

function in a wetted environment. The staff concluded that this adequately resolved RAI 2.1-2C.

Conclusion. On the basis of the additional information supplied by the applicant, including

determining that certain additional SSCs that would be placed within the scope of license

renewal based on analysis and additional review, determining that certain SSCs were qualified

for the environment, identifying the basis for the definition and use of the first equivalent

anchor, and reviewing the results of NRC inspection and audit activities, the staff concluded

that the applicant had supplied sufficient information to demonstrate that all SSCs that meet the

10 CFR 54.4(a)(2) scoping requirements have been identified as being within the scope of

license renewal. 

Application of the Scoping Criteria in 10 CFR 54.4(a)(3). Section 54(a)(3) of 10 CFR 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 NRC regulations for fire protection
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(10 CFR 50.48), EQ (10 CFR 50.49), ATWS (10 CFR 50.62), and SBO (10 CFR 50.63) to be

within the scope of license renewal.

The applicant performed the initial scoping for regulated events by evaluating CLB information

relevant to each regulated event to identify if the structure or system met the scoping criteria of

10 CFR 54.4(a)(3). For these events, the applicant developed an engineering report describing

the relevant Rule requirements. A functional description of the implementation includes the

process to identify the scoping boundaries associated with the systems credited, the intended

functions applicable to the requirement, information on how to record the results of the

evaluation in the license renewal database and appropriate MEL, a list of CLB information

sources used for the analysis, and a list of systems and components determined to be within

scope for the given regulated event.

 • Fire Protection. The applicant provided a description of the scoping of SSCs required to

demonstrate compliance with the fire protection requirements in 10 CFR 50.48. The

applicant stated that the fire protection report, EMPAC, and the CLB had been reviewed

to ensure that SSCs required to perform the necessary safe shutdown functions and to

minimize the risk of radioactive releases to the environment during and following fires

are included within the scope of license renewal. In addition, the applicant stated that it

considered the NRC’s Interim Staff Guidance (ISG) related to scoping fire protection

equipment, ISG-07, to determine if a system performs a function that demonstrates

compliance with NRC’s regulations. Specifically, the applicant verified that the EMPAC

contains a designated field identifying components that are part of the fire protection

program consistent with the CLB. The staff reviewed the process used by the applicant

to identify those components and verified, through review of a selection of scoping

results, that the EMPAC information was adequately incorporated into the license

renewal evaluation.

 • Environmental Qualification. The applicant stated that BFN maintains documents

containing detailed information related to environmental qualification of components at

BFN. Additionally, EMPAC provides a list of components that are subject to an EQ

program. The applicant reviewed these documents to prepare the list of in-scope items

for the LRA. Specifically, EMPAC contains a designated field identifying components

that are part of the EQ program. The staff reviewed the process used by the applicant to

identify those components and verified, through review of a selection of scoping results,

that EMPAC information was adequately incorporated into the license renewal

evaluation.

 • Anticipated Transient Without Scram. The applicant reviewed UFSAR Section 7.19 and

used the quality-related classification field in EMPAC to identify components of the

ATWS mitigation system required by 10 CFR 50.62. EMPAC is a controlled plant

component database containing integrated design and maintenance record

management information. The plant component database lists plant components at the

level of detail for which discrete maintenance or modification activities are typically

performed. Specifically, EMPAC contains a designated field identifying components that

are credited for ATWS mitigation. The staff reviewed the process used by the applicant

to identify those components and verified, through review of a selection of scoping

results, that the EMPAC information had been adequately incorporated into the license

renewal evaluation.
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 • Station Blackout. In an NRC letter dated April 1, 2002, the staff provided guidance on

the scoping of equipment relied on to meet the requirements of the SBO rule,

10 CFR 50.63. In this letter, the staff noted that, consistent with the requirements

specified in 10 CFR 54.4(a)(3) and 10 CFR 50.63(a)(1), the plant system portion of the

offsite power system that is used to connect the plant to the offsite power source should

be included within the scope of the Rule. 

In LRA Section 2.1.8.2, the applicant stated that, based on the guidance in the April 1, 2002,

letter for SBO recovery, an evaluation was performed to determine, and bring into the scope of

license renewal, components credited for recovery of the offsite power system. For each of the

systems credited for SBO recovery, the applicant used, as a minimum, information from the

SBO calculations and Emergency Operating Procedures and Technical Specification

Bases 3.8.1, to determine the appropriate NSR portions of the in-plant electrical system that

would be used to connect the offsite power system to the SR portions of the plant electrical

system. The applicant performed calculations to summarize the results of a detailed review of

SBO CLB documentation. The calculations provided lists of systems with their credited

functions and a listing of major components. The applicant did not use the spaces approach to

evaluate all plant electrical and I&C components in the SBO offsite power restoration flow path.

The applicant provided license renewal drawings that identified the additional components in

the offsite power restoration flow paths from 500 kilovolt (kV) and 161 kV switchyards to the

plant SR shutdown buses using plant procedures for the restoration of offsite power.

Additionally, an AMR was performed for all long-lived passive structures and components within

these systems. A scoping effort identified structures and components of the offsite power

system for each plant required to restore power from the onsite switchyard down to the SR

busses in the plant. The applicant also stated that the plant offsite power system and these

structures and components were classified as satisfying10 CFR 54.4(a)(3) criteria and were

included within the scope of license renewal. The staff determined that the applicant’s approach

to scoping SSCs relied on to demonstrate compliance with the SBO rule (10 CFR 50.63) was

consistent with the staff’s April 1, 2002, interim guidance. 

Conclusion. The staff reviewed a sample of the license renewal database 10 CFR 54.4(a)(3)

scoping results and discussed the methodology and results with the applicant’s license renewal

project personnel. The staff verified that the applicant had identified and used pertinent

engineering and licensing information to identify SSCs to be within the required scope in

accordance with the 10 CFR 54.4(a)(3) criteria. On the basis of this sample review, discussions

with the applicant, and review of the applicant’s scoping process, the staff determined that the

applicant’s methodology for identifying systems and structures meeting the scoping criteria of

10 CFR 54.4(a)(3) was adequate. 

2.1.3.1.3 System Level Scoping of Structures and Components

The applicant started the system-level scoping of structures and components with the review of

the SSA calculation, UFSAR descriptions, Maintenance Rule documents, CLB, and

design-basis documents to determine the system safety classification level functions and to

identify the system intended functions. The SSA provided the system designation and the

system function. The relevant flow drawings were retrieved for the system and description, and

their safety classifications were determined. The components were identified and their functions

were mapped. The applicant consulted the UFSAR to see if any additional functions were listed
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therein, because the applicant created the SSA during the restart of Units 2 and 3, listing all the

possible system functions. 

At the system level, the scoping methodology used for electrical and I&C systems was identical

to the mechanical system-level scoping. The SSA calculation, UFSAR descriptions,

Maintenance Rule documents, and other design-basis documents were reviewed to determine

an electrical system’s safety classification and to identify the electrical system’s intended

functions. System-level functions were evaluated against the criteria of 10 CFR 54.4(a). This

information was included in the license renewal database for inclusion in the LRA.

The applicant entered the information on the “System Scoping Results” data sheet for the

specific system. The staff reviewed the scoping results for the RHR system and observed that

the data sheet contained detailed information that identified each component and its parent

system, component type, the scoping criteria that it was required to meet, and its associated

AMR information.

2.1.3.1.4 Component Level Scoping

The applicant reviewed license renewal boundary drawings in conjunction with physical layout

drawings and component listings from EMPAC to determine the components within the scope

of license renewal. Any component that was needed to fulfill any system intended function or

determined to be an NSR component that could prevent satisfactory accomplishment of an SR

function was considered to be within the scope of license renewal. The applicant evaluated the

components either individually or in groups of like components and functions to ensure that all

components were properly addressed. Electrical and I&C components of in-scope mechanical

systems were classified as electrical and I&C commodities. Structural components of in-scope

mechanical systems were classified as structural commodities. Structural commodities, such as

cable trays and their supports, were classified as plant civil system commodities. Pressure

boundary components of electrical penetrations were classified as civil commodities. Structural

components of in-scope structures that are required to support the intended functions were

generally evaluated as generic structural commodities, and not individual components.

Mechanical Component Scoping. The staff reviewed 0-TI-455, “Mechanical Technical

Evaluation for License Renewal,” Revision 2, dated May 28, 2004. The applicant provided a

technical description and overview of the process in Section 4.1, Mechanical Scoping and

Screening, of 0-TI-455. Specifically, the applicant stated that systems and components are

determined to be within the scope of license renewal if they have been evaluated to meet any of

the scoping criteria. 

The staff verified that mechanical system evaluation boundaries were established for each

system within the scope of license renewal. These boundaries were determined by mapping the

pressure boundary associated with system-level license renewal intended functions onto the

system flow and control drawings. Mechanical component types were loaded into a scoping and

screening database and further review was performed to ensure that all component types were

identified. A preparer and an independent reviewer performed a comprehensive evaluation of

the boundary drawings to ensure the completeness and accuracy of the review results.

Following identification of all system component types, the applicant used the license renewal

boundary as an aid to evaluate each component against the scoping criteria of 10 CFR 54.4(a).
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System components meeting the criteria of 10 CFR 54.4(a) were classified as within the scope

of license renewal.

The staff conducted detailed discussions with the applicant’s license renewal project personnel

and reviewed documentation pertinent to the scoping process. The staff assessed whether the

applicant had appropriately applied the scoping methodology outlined in the LRA and

implementation procedures and whether the scoping results were consistent with CLB

requirements.

The staff reviewed the process of scoping for the RHRSW and ECCW systems. The staff

verified that the applicant had identified and highlighted system flow and control drawings to

develop the system boundaries in accordance with the procedural guidance. The applicant was

knowledgeable concerning the process and conventions for establishing boundaries as defined

in the license renewal implementation procedures. Additionally, the staff verified that the

applicant had independently verified the results in accordance with the governing procedures.

Specifically, other personnel knowledgeable of the system had independently reviewed the

marked-up drawings to ensure accurate identification of system intended functions. The staff

performed additional cross-discipline verification and independent reviews of the resultant

highlighted drawings before final approval of the scoping effort.

Conclusion. The staff determined that the applicant’s methodology was consistent with the

description provided in LRA Section 2.1.4 and that the guidance contained in SRP-LR

Section 2.1 was adequately implemented. On the basis of the applicant’s detailed scoping

implementation procedures and a sampling review of mechanical components scoping results,

the staff concluded that the applicant’s methodology for identifying mechanical components

within the scope of license renewal met the requirements of 10 CFR 54.4(a).

Structural Component Scoping. The applicant performed its structural scoping in accordance

with the detailed methodology defined in 0-TI-457, “Civil Technical Evaluations for License

Renewal,” Revision 2. The scoping procedure was used to evaluate SSCs to identify their

functions and determine which are intended functions required for compliance with one or more

criteria of 10 CFR 54.4(a)(1)-(3). Initial identification of BFN structures was accomplished by

reviewing BFN drawing 0-10E21-series and/or Maintenance Rule documentation, 0-TI-346. For

each structure, the applicant further reviewed the drawings and plant databases to identify

specific structural components and features. The structural component intended functions for

SCs within the scope of license renewal were identified based on the guidance provided in

Regulatory Guide (RG) 1.188, "Standard Format and Content for Applications to Renew

Nuclear Power Plant Operating Licenses," NEI 95-10, and the SRP-LR. The procedure also

described the source design documentation to be used for the evaluation of structures meeting

the 10 CFR 54.4(a) criteria including the UFSAR, general design criteria (GDC) document, and

other appropriate documents. For civil structures, the evaluation boundaries were determined

by developing a complete description of each structure with respect to the intended functions

performed by the structure and its components. A license renewal database was created for

use in compiling the structural scoping results. The database contained (1) a unique

identification number for each structure, (2) a list of structural components or commodity types

associated with the structure, (3) evaluation results for each of the 10 CFR 54.4(a)(1)-(3)

criteria for the structure, (4) a description of structural intended functions and source reference

information for the functions, and (5) a reference to pertinent license renewal drawings

associated with each structure.
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License renewal procedure 0-TI-457 was also used to define the evaluation boundaries and

discipline interfaces for civil/mechanical and civil/electrical systems. With respect to the

civil/mechanical interface, the procedure identified the following component types within

mechanical systems that were evaluated as part of the civil review. These component types

included: (1) piping system supports, (2) HVAC duct supports, (3) equipment supports and

foundations, (4) bolting and fasteners for structural supports and mechanical fasteners that are

required for mechanical closure of mechanical components, and (5) whip restraints and jet

impingement shields.

With respect to the civil/electrical interface, the procedure identified the following component

types within electrical systems that were evaluated as part of the civil review. These component

types included: (1) cable trays and supports, (2) conduits and supports, (3) electrical cabinets,

panels, racks, and other enclosures providing structural integrity, (4) instrument racks, panels,

frames, and enclosures providing structural integrity, and (5) electrical and I&C penetrations

providing structural support functions.

The staff conducted detailed discussions with the applicant’s license renewal project personnel

and reviewed documentation pertinent to the scoping process. The staff assessed whether the

scoping methodology outlined in the LRA and implementation procedures were appropriately

implemented and whether the scoping results were consistent with CLB requirements. The staff

also reviewed several plant structural evaluation results for the reactor building and turbine

building to verify proper implementation of the scoping process for structural components. The

staff also compared a sample of structural components identified in the drawings to the

structural list in the license renewal data base to ensure consistency. Based on these audit

activities, the staff did not identify any discrepancies between the methodology documented

and the implementation results.

Conclusion. The staff determined that the applicant’s methodology for structural scoping was

consistent with the description provided in LRA Section 2.1.4.3 and the guidance contained in

the SRP-LR Section 2.1. Based on a review of information contained in the LRA, the applicant’s

detailed scoping implementation procedures, and a sampling review of structural component

scoping results, the staff concluded that the applicant’s methodology for identification of

structural components within the scope of license renewal met the requirements of

10 CFR 54.4(a). 

Electrical and I&C Scoping. The staff reviewed 0-TI-456, “Electrical Technical Evaluations For

License Renewal,” which describes the electrical and I&C scoping and screening process and

discussed the methodology and results with the applicant’s cognizant engineers. With the

exception of components in the SBO offsite power restoration flow path, plant electrical and I&C

components were evaluated using a “spaces” approach. The spaces approach identifies the

electrical and I&C commodity groups that are installed in the plant and the limiting

environmental conditions for each group. The spaces approach then determines if any area

environment is more severe than the limiting environment for the commodity group. If the area

environment is more severe than a commodity group’s limit, and if a component in the

commodity group is actually located in the area, an AMR is required for that commodity group.

For this LRA, the applicant used a bounding spaces approach, as described in NEI 95-10.

Electrical and I&C component types used plant-wide were identified without regard to the plant

system they are in. The applicant used the listing provided by NEI 95-10, Appendix B as the
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basis for this list. Electrical component types were identified from the plant controlled computer

database, EMPAC. Then these component types were assembled into commodity groups such

as breakers, switches, and cables using the NEI 95-10, Appendix B list as a starting point. The

EMPAC database has a fine division of component titles based on component performance

characteristics, so sub-commodity groups were formed to separate components into specific

groups with common applications or materials. Thus under the commodity group, “circuit

breakers,” there may be a number of sub-commodity groups including all the circuit breakers

identified in EMPAC as having common application, operating characteristics, fabrication

materials, etc. The result is a detailed list by commodity and sub-commodity of all electrical and

I&C components installed in the plant.

An exception to the spaces approach was the identification of electrical and I&C equipment

needed for the SBO event offsite power restoration. Using the intended-function approach, the

applicant developed license renewal drawings showing the basic electrical distribution paths for

SBO offsite power restoration. Plant operating procedures were used to develop these SBO

offsite power restoration license renewal drawings and to identify the components required to

perform the function. The staff determined that the scoping and screening methodology used in

0-TI-456, “Electrical Technical Evaluations For License Renewal”; and described by the

applicant’s engineers during the audit provided adequate guidance, was consistent with the

requirements of 10 CFR 54.4 for the scoping evaluation of electrical components.

Conclusion. The staff determined that the applicant’s methodology for electrical and I&C

scoping was consistent with the description provided in LRA Section 2.1.4.2 and the guidance

contained in the SRP-LR. Based on review of information contained in the LRA, the applicant’s

detailed scoping implementation procedures, and a sampling review of electrical component

scoping results, the staff concluded that the applicant’s methodology for identification of

electrical and I&C components within the scope of license renewal met the requirements of

10 CFR 54.4(a).

2.1.3.2 Screening Methodology

The staff reviewed the screening methodology used by the applicant to determine if

mechanical, structural, and electrical components within the scope of license renewal would be

subject to further aging management evaluation. The applicant described the screening

methodology in LRA Section 2.1.5. In general, the applicant’s screening approach consisted of

evaluations to determine which structures and components within the scope of LRA were

passive and long-lived. Passive and long-lived structures and components were then subject to

an AMR.

The staff evaluated the applicant’s screening methodology against criteria contained in

10 CFR 54.21(a)(1) and 10 CFR 54.21(a)(2) using the review guidance contained in SRP-LR

Section 2.1.3.2, “Screening.” The staff evaluation of the applicant’s screening approach for

each of these disciplines is discussed below.

2.1.3.2.1 Mechanical Component Screening

The staff reviewed the methodology used by the applicant to determine if mechanical

components within the scope of license renewal would be subject to further AMR. For
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mechanical components, the applicant applied a screening process to each mechanical system

determined to be within the scope of license renewal in order to determine the types of

mechanical component commodities within the systems and the various materials and

environments to be considered in the AMR. The applicant then established evaluation

boundaries for the various plant mechanical systems in order to further identify individual

mechanical components for review.

The listing of mechanical components was facilitated by combining these items into commodity

groups from a review of each boundary drawing. The applicant placed these commodity groups

into the license renewal database and evaluated them in accordance with the screening criteria

described in 0-TI-455. The applicant provided the staff with a detailed discussion of the process

and provided screening report information from the license renewal database that described the

screening methodology, as well as a sample of the screening results reports for a selected

group of SR and NSR systems. The staff determined that the screening methodology was

consistent with the requirements of the Rule and that implementation of the methodology will

identify SCs that meet the screening criteria of 10 CFR 54.21(a)(1).

During the audit, the staff reviewed the methodology used by the applicant to identify and list

the mechanical components and commodities subject to an AMR, as well as the applicant’s

technical justification for this methodology. The staff discussed the methodology and results

with the applicant’s cognizant engineers and senior staff. The staff also examined the

applicant’s results from the implementation of this methodology by reviewing a sample of the

mechanical systems identified as within the scope of license renewal. These systems included

the RHRSW system and EECW system. The review included the evaluation boundaries and

resultant in-scope components, the corresponding component-level intended functions, and the

resulting list of mechanical components and commodity groups subject to an AMR. 

The staff reviewed several summary screening reports, which list a breakdown of the

mechanical components that are within the scope of license renewal. Each report lists several

categories, including component type, component material, whether an AMR is required, and

an extensive comment section. The staff also reviewed a sample of the mechanical drawing

packages assembled by the applicant and discussed the process and results with the cognizant

engineers who performed the review. The staff did not identify any discrepancies between the

methodology documented and the implementation results.

Conclusion. The staff determined that the applicant’s mechanical component screening

methodology was consistent with the guidance contained in the SRP-LR and was 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 0-TI-457, “Civil Technical Evaluations For License Renewal,” which outlined

the applicant’s methodology to determine if SCs within the scope of license renewal would be

subject to an AMR. The screening process applied to in-scope buildings and civil structures was

designed to determine the structural elements and construction materials, as well as to

determine the environments to which these buildings and civil structures will be exposed so that

these factors could be considered in the AMR. Engineering document 0-TI-457 Section 6.3,

“Structures Screening,” describes the guidance for the structural screening process. For all
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structural component types with intended functions, the applicant then determines if the

component type is long-lived. The applicant used existing plant program procedures and

operating experience to determine if the component type was subject to replacement based on

a qualified life or whether it was long-lived. 

During the audit of the applicant’s license renewal scoping and screening process, the staff

reviewed the methodology used by the applicant to identify and list the structural components

and structural commodities subject to an AMR as well as the applicant’s technical justification

for this methodology. The staff discussed the methodology and results with the applicant’s

cognizant engineers and senior staff. The applicant provided the staff with a detailed discussion

of the process and provided technical reports that described the screening methodology as well

as a sample of the screening results for a selected group of structures.

The staff also examined the applicant’s results from the implementation of this methodology by

reviewing a sample of the reactor building and turbine building plant structures identified as

being within the scope of license renewal. The review included the evaluation boundaries and

resultant in-scope components, the corresponding component-level intended functions, and the

resulting list of structural components and structural commodity groups subject to an AMR. 

Conclusion. The staff determined that the applicant’s structural component screening

methodology was consistent with the guidance contained in the SRP-LR and was capable of

identifying those passive and long-lived components within the scope of license renewal that

are subject to an AMR.

2.1.3.2.3 Electrical Component Screening.

The staff reviewed the applicant’s procedure 0-TI-456, “Electrical Technical Evaluations For

License Renewal,” which provided guidance on the screening of electrical and I&C components.

The applicant used a bounding spaces approach as described in NEI 95-10, Revision 3, to

perform the electrical evaluation. The electrical and I&C component types were identified from

EMPAC. These component types were assembled into commodity groups such as breakers,

switches, and cables using the NEI 95-10, Appendix B, list and supplemented with site-specific

information. The applicant then applied the screening criteria to determine those electrical

commodities subject to an AMR.

The staff discussed the methodology and results with the applicant’s cognizant engineers and

senior staff. The staff also examined the applicant’s results from the implementation of this

methodology by reviewing several electrical and I&C commodity reports and samples from the

license renewal database. The review verified that the applicant’s staff had consistently applied

the screening criteria to identify those electrical and I&C commodity groups subject to an AMR.

The staff determined that the electrical screening process was consistent with criteria in

10 CFR 54.21(a)(1)(ii) and excluded those components or commodity groups that are subject to

equipment qualification requirements. The staff did not identify any discrepancies between the

methodology documented and the implementation results.

The staff also reviewed the applicant’s approach to scoping and screening of electrical fuse

holders. In license renewal ISG-5, “Identification and Treatment of Electrical Fuse Holders for

License Renewal,” dated March 10, 2003, the staff stated that, consistent with the requirements

specified in 10 CFR 54.4(a), fuse holders (including fuse clips and fuse blocks) are considered
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to be passive electrical components. Fuse holders would be scoped, screened, and included in

the AMR in the same manner as terminal blocks and other types of electrical connections that

are currently being treated in the process. This staff position applies only to fuse holders that

are not part of a larger assembly, but support SR and NSR functions in which the failure of a

fuse precludes a safety function from being accomplished (10 CFR Part 54.4(a)(1) and

10 CFR 54.4(a)(2)). As described in LRA Sections 2.1.8.5, and 3.6.2.3.1, the applicant

developed a process for identifying and evaluating fuse holders as part of its license renewal

evaluation. The process included using EMPAC to identify fuses in the plant and then to apply a

series of evaluations and screening to identify a subset of the plant fuses which would

potentially be susceptible to various effects of moisture or chemical contamination, thermal

cycling, vibration, and mechanical stress. The applicant evaluated plant operating experience

and determined that fatigue due to mechanical stress was an applicable aging

effect/mechanism. The applicant then evaluated all remaining fuses to determine if any were

susceptible to mechanical stress. The staff reviewed the applicant’s process for identifying and

evaluating the fuse holders and determined it was adequate.

Conclusion. The staff determined that the applicant’s electrical and I&C screening methodology

was consistent with the guidance contained in the SRP-LR and was capable of identifying

passive, long-lived components within the scope of license renewal that are subject to an AMR.

2.1.4 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 RAIs formed the basis of the staff’s safety determination. The staff verified that the

applicant’s scoping and screening methodology was consistent with the requirements of the

Rule and the staff’s position on the treatment of NSR SSCs. 

On the basis of this review, the staff concluded that there is reasonable assurance that the

applicant’s methodology for identifying the SSCs within the scope of license renewal and the

structures and components requiring an AMR is consistent with the requirements of

10 CFR 54.4 and 10 CFR 54.21(a)(1).
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2.2 Plant-Level Scoping Results

2.2.1 Introduction

In LRA Section 2.1, the applicant described the methodology for identifying the systems and

structures (SSs) within the scope of license renewal. In LRA Section 2.2, the applicant used the

scoping methodology to determine which of the SSs are required to be included within the

scope of license renewal. The staff reviewed the plant-level SSs relied upon to mitigate DBEs,

as required by 10 CFR 54.4(a)(1), or whose failure could prevent satisfactory accomplishment

of any of the SR functions, as required by 10 CFR 54.4(a)(2), as well as the SSs relied on in

safety analyses or plant evaluations to perform a function that is required by any of the

regulations referenced in 10 CFR 54.4(a)(3).

2.2.2 Summary of Technical Information in the Application

In LRA Tables 2.2.1 and 2.2.2, the applicant provided a list of the plant systems and structures,

respectively, 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 NSR systems and structures, and certain regulated events,

the applicant identified those plant-level systems and structures that are within the scope of

license renewal, as defined by 10 CFR 54.4.

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 the safety

evaluation report (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

Tables 2.2.1 and 2.2.2, and added systems due to the changed scoping methodologies to

confirm that there were no omissions of plant-level systems and structures within the scope of

license renewal.

In response to RAI 2.1-2A(3), described in SER Section 2.1, the applicant revised the

methodology used to determine the NSR SSCs to be included in the scope of license renewal in

accordance with the requirements of 10 CFR 54.4(a)(2). The applicant’s response to

RAI 2.1-2A(3) and supplemental information related to implementation of the revised scoping

methodology are documented in the applicant’s response, dated February 28, 2005. As a result

of the implementation of the scoping methodology changes, the applicant expanded the scope

of license renewal and added the following mechanical systems that had additional in-scope

piping or components:

 • condensate and demineralized water system

 • containment system

 • reactor building closed cooling water system

 • auxiliary decay heat removal system

 • fuel pool cooling and cleanup system

 • CO2 system
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 • sampling and water quality system

 • off-gas system

 • radioactive waste treatment system

 • diesel generator starting air system

The applicant also added the following structures to the scope of license renewal:

 • radwaste building

 • service building

In response to a follow-up question of RAI 2.1-2A(1), dated May 31, 2005, described in SER

Section 2.1, the applicant provided supplemental information on the implementation of the

revised scoping methodology of NSR piping segments that support secondary containment

penetrations qualified to seismic Class II pressure retention requirements.

As a result of the implementation of the scoping methodology changes, the applicant added the

following mechanical systems that had additional piping or components added to the scope of

license renewal:

The following mechanical systems only had systems boundary changes. No new component

types, materials, or environments that affected either the scoping/screening or AMR results in

the LRA were added.

 • main steam system

 • auxiliary boiler system

 • raw cooling water system 

 • station drainage system 

 • high pressure coolant injection system 

 • residual heat removal system 

 • radioactive waste system 

 • fuel pool cooling and cleanup system 

 • radiation monitoring system

The following mechanical systems had systems boundary changes. For some of these

systems, new component types were added that affected the scoping/screening results in the

LRA. For all systems listed, new components, materials or environments that affected the AMR

results in the LRA were added.

 • condensate and demineralized water system 

 • feedwater system

 • potable water system 

 • service air 

 • containment system 

The remainder of the mechanical systems were not affected by this review. 

The staff reviewed the selected systems and structures that the applicant had not identified as

falling within the scope of license renewal to verify whether the systems and structures have

any intended functions that would require their inclusion within the scope of license renewal in

accordance with 10 CFR 54.4. The staff's review of the applicant's implementation was
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conducted in accordance with the guidance described in SRP-LR Section 2.2, “Plant-Level

Scoping Results.”

The staff sampled the contents of the UFSAR based on the systems and structures listed in

LRA Tables 2.2.1 and 2.2.2 to determine whether there are any systems or structures that may

have intended functions within the scope of license renewal, as defined by 10 CFR 54.4, but

were omitted from 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 UFSAR to determine

whether any systems and structures within the scope of license renewal had not been identified

by the applicant. The staff's review did not identify any omissions. On the basis of this review,

the staff concluded that the applicant had properly 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 Scoping and Screening Results: Mechanical Systems

This section documents the staff’s review of the applicant’s scoping and screening results for

mechanical systems. Specifically, this section discusses the following mechanical systems:

 • reactor coolant systems

 • engineered safety features

 • auxiliary systems

 • steam and power conversion systems

In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must identify and list

passive, long-lived structural SSCs that are within the scope of license renewal and subject to

an AMR. To verify whether the applicant has 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 system components that meet the scoping criteria and

are subject to an AMR.

In the LRA, the applicant described a methodology for mechanical systems scoping and

screening that interprets 10 CFR 54.21(a) differently from previous LRAs and the SRP-LR.

Specifically, the applicant did not define component-level scoping boundary. The applicant

combined passive, long-lived, and intended function criteria into one screening process to meet

the requirements of 10 CFR 54.21(a)(1). The applicant highlighted those components on the

license renewal drawings that are passive, long-lived, and have intended functions as being

subject to an AMR. Therefore, some of the components that have intended functions may not

be identified and listed in the LRA Section 2.3 tables or highlighted on the license renewal

drawings, because the component scoping boundary is not defined.

The methodology used by previous LRA applicants, consistent with the SRP-LR review

guidance, describes two steps to perform scoping and screening. The first step, scoping,

identifies those SSCs within the scope of license renewal in accordance with 10 CFR 54.4(a).

The applicant then identified the components of the in-scope system that have intended

functions to be included in the license renewal scope in accordance with the criteria of

10 CFR 54.4(a). The component scoping boundary within a system is then highlighted on

license renewal drawings. The second step, screening, identifies those components in the

scoping boundary that are passive and long-lived in accordance with 10 CFR 54.21(a)(1). The

resulting components from these scoping and screening steps are subject to an AMR. This

matter was further complicated because the drawings for Unit 1 only highlighted those portions

of the system that are subject to an AMR and are not expected to change as a result of

modifications needed to bring the CLB for Unit 1 in line with Units 2 and 3.

Because the applicant used a different scoping and screening process and provided insufficient

information in its LRA associated with this methodology, the staff was unable to determine

whether there were any omissions of components from the scope of license renewal and

subject to an AMR. The applicant did not provide scoping information at the component level

equivalent to that provided by previous LRA applicants for the review of systems in LRA

Section 2.3. 
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To better understand the applicant’s scoping methodology, the staff conducted an audit review

at the TVA offices in Chattanooga, TN, between June 7 and 10, 2004, to review the applicant’s

license renewal project guidelines and procedures. The purpose of this plant audit was to

determine, by review of plant information, that system components within the scope of license

renewal are identified and that the components of the in-scope systems subject to an AMR are

screened. The staff reviewed the applicant’s site documentation in the following areas:

 • department procedure for license renewal technical evaluations

 • mechanical technical evaluations for license renewal

 • SBO calculations

 • system reports

To ensure that all components of an in-scope system were screened, or identified as passive

and long-lived in accordance with 10 CFR 54.21(a)(1), the staff audited the system report for

the main steam system. Additionally, the staff reviewed the SBO calculations to determine if

any systems were omitted from scope in accordance with 10 CFR 54.4(a)(3). In its trip report,

the staff documented which procedures and reports were reviewed at the plant site.

As a result of the staff’s review of LRA Section 2.3, the staff found that additional clarification

was needed to determine whether the applicant’s mechanical component-level scoping for the

in-scope systems was adequate. Therefore, by letter dated August 31, 2004, the staff issued

RAIs to determine whether the applicant had properly applied the scoping criteria of

10 CFR 54.4(a). The following paragraphs describe the staff’s RAIs and the applicant’s

responses.

In RAI 2.3-1, the staff stated that many of the tables in LRA Section 2.3 list "fittings" as a

component type subject to an AMR. The term “fittings” typically refers to components such as

elbows, tees, unions, reducers, caps, flanges, etc., which are an integral part of piping systems.

LRA Section 2.3.5 lists other components that fall under the component type “fittings” but does

not list the above components. Therefore, the staff requested the applicant to confirm that

components such as those listed above are considered as part of the component type “fittings”

in the LRA tables, or to state if they are considered as part of another listed component type.

In its response, by letter October 19, 2004, the applicant stated that elbows, tees, unions,

reducers, caps, flanges, etc., are not typically shown with UNIDs on the license renewal

drawings, and that they were not listed in LRA Section 2.3.5. LRA Section 2.3.5 was generated

to help identify components that are shown on boundary drawings, have a specific UNID, and

are included in a commodity. The applicant further stated that components such as elbows,

tees, unions, reducers, caps, flanges, quick disconnects, thermal sleeves, aux heads, and

drains are included in commodity type “fittings.” 

Based on its review, the staff found the applicant’s response to RAI 2.3.-1 acceptable. It

confirms that the components addressed in the RAI are already included in the component type

“fittings” as being subject to an AMR. Therefore, the staff’s concern described in RAI 2.3-1 is

resolved.
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In RAI 2.3-2, the staff stated that LRA Section 2.1.7.9, Group (c) states that “oil, grease, and

component filters” are short-lived and are periodically replaced. It further states that various

plant procedures are used in the replacement of oil, grease, and component filters that are

within the scope of license renewal. In the process of verifying the results of the above

applicant’s methodology, the staff raised the following questions.

Because the LRA uses AMR boundary drawings instead of scoping boundary drawings, the

components that are within the scope of license renewal but not subject to an AMR are not

highlighted on the drawings. Therefore, the staff was unable to determine, for mechanical

systems, whether all in-scope oil, grease, and component filters had been identified in

accordance with 10 CFR 54.4. Additionally, the staff could not determine whether plant

procedures exist and are adequate for the all in-scope “oil, grease, and component filters” that

are not subject to an AMR. For example, “crane system” is within the scope of license renewal

in accordance with 10 CFR 54.21(a)(2); however, filters of the system are not listed in LRA

Table 2.3.3.34 as component types subject to an AMR. Additionally, no drawings were provided

for this system. The staff could not determine whether this system contains any in-scope oil,

grease, and component filters, or whether the plant procedures are adequate for them.

Therefore, in RAI 2.3-2, the staff requested the applicant to do the following:

 1. Verify all the in-scope oil, grease, and component filters that are identified in the license

renewal boundary drawings. If not, list those in-scope oil, grease, and component filters

that are not identified in the drawings.

 2. Identify the plant procedures that are used for the replacement of every in-scope oil,

grease, and filter that is not subject to an AMR to demonstrate that the oil, grease, or

filter is replaced on a periodic basis and identify the specific period. 

 3. Identify those in-scope oil, grease, and component filters without proper plant

procedures that are subject to an AMR.

In its response, by letter October 19, 2004, the applicant stated:

 1. The boundary drawings were not intended to depict oil or grease. All filters

associated with mechanical systems are not depicted on boundary drawings.

The boundary drawings are based on flow diagrams which depict components in

the system fluid flow path (i.e., pressure boundary). Even though most discrete

components are shown on the flow diagrams, the flow diagrams show various

levels of detail associated with vendor supplied skids. For example, some flow

diagrams associated with vendor supplied skids show the associated lubricating

oil and cooling water components (i.e., filters, pumps, etc.). Other flow diagrams

may only depict the major component in the flow path, such as a heat exchanger

associated with a vendor supplied chiller package. The refrigerant loop

associated with the vendor supplied chiller unit is not depicted on the flow

diagram. Vendor drawings and vendor manuals provide details associated with

the vendor supplied equipment. In these cases, the vendor documents were

utilized to identify components, such as filters, that are subject to aging

management review. Examples of filters that were subject to an AMR that were

not shown on drawings are: Unit 1 reactor core isolation cooling system lube oil

filters; Unit 1 high pressure coolant injection system lube oil filters; and filters
2-34

associated with the refrigerant loop of heating ventilation and air condition

system chillers. 

 2. Browns Ferry has various maintenance procedures and work orders in place to

assure that filters for safety related components are being monitored and

replaced as required to assure that equipment will perform its function. Some

examples of procedures used to replace the elements are: MPI-0-026-INS002

which is performed annually or 250 hour cumulative inspection, MPI-0-82-

INS002 which performs the Standby Diesel Engine 24 month inspection,

procedure 0-GI-300-1 Attachment 15.11 which is the Monthly Ventilation Filter

Check, repetitive work orders done every 24 weeks, 0-SI-4.8.B.2-1 which is

performed weekly, MPI-0-071-TRB001 and repetitive work order every 24

months, and MPI-0-073-TRB001 and repetitive work order every 12 weeks.

Browns Ferry has various preventive maintenance procedures and work orders

in place to assure that oil and grease for safety related components are being

monitored and replaced as required to assure that equipment will perform its

function. The following are examples of procedures that are used for oil and

grease replacement: QMDS NUMBER MOV-001 (performed every 54 months),

QMDS NUMBER MOV-002 (performed every 54 months), QMDS NUMBER

MOV-003 (performed every 54 months), QMDS NUMBER MOT-001 (perform oil

samples every six months), QMDS NUMBER MOT-003 (performed at 24 and 36

month intervals), QMDS NUMBER PLN-003 (performed every 3 years), EPI-0-

000-MOT- 001 (Preventive Maintenance work orders are generated at various

frequencies to add grease to motors), EPI-0-000- MOT-002 (Preventive

Maintenance work orders are generated at various frequencies to add oil to

motors), and MPI-0- 000-LUB001 (Preventive Maintenance work orders are

generated at various frequencies to add grease to equipment). In addition, some

components lubricants are monitored and replaced based on oil analysis

(predictive maintenance). 

 3. Our review did not identify any cases where oil, grease, or in scope filters were

without proper plant procedures to exclude them as short lived. 

In the initial response review, the staff was unable to find the applicant’s response to RAI 2.3-2

acceptable. The applicant did not provide sufficient information to provide reasonable

assurance that all oil, grease and component filters are either outside the scope of license

renewal or are replaced based on a qualified life or specified time period. By letter dated

May 18, 2005, the applicant revised its response to state that it has various maintenance

procedures and work orders in place to assure that all filters for SR components are being

monitored and replaced as required to assure that the equipment will perform its function. 

Based on its review, the staff found the applicant’s revised response acceptable. There is

reasonable assurance that all filters for SR components are covered by procedures or work

orders. Therefore, the staff’s concerns described in RAI 2.3-2 are resolved. 

In RAI 2.3-3, the staff stated that LRA Section 2.1.7.2 states that insulation at BFN does not

have an intended function associated with the scoping requirements of 10 CFR 54.4(a)(1)

through (a)(3). However, there is insufficient information in the LRA and the UFSAR for the staff

to determine if the statement is valid at such a generic level. Insulation may be required for a

variety of reasons, e.g., systems efficiency, heat-load calculations, EQ purposes. etc. If the
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insulation is relied upon for EQ purposes, the passive, long-lived insulation should be within the

scope of license renewal and subject to an AMR. Therefore, the staff requested that the

applicant provide a basis for not including any piping or equipment insulation within the scope of

license renewal.

On March 22, 2005, the staff held a teleconference with the applicant to discuss the treatment

of insulation. In its response, by letter May 18, 2005, as modified by letter dated June 15, 2005,

the applicant stated that all the mechanical piping and equipment insulation contained in the SR

structures as well as some NSR structures have been added to the scope of license renewal,

since they meet the criteria of 10 CFR 54.4(a)(2) and (a)(3). Piping and equipment insulation

has the intended functions of insulate and integrity. The applicant stated that these intended

functions will be added to LRA Table 2.0.1. The applicant also stated that piping and equipment

insulation and insulation jacketing are component types that are subject to an AMR. LRA

Table 2.1.7.2 will be added to reflect these two component types and their intended functions.

Based on its review, the staff found the applicant’s response to RAI 2.3-3 acceptable. The

applicant placed all piping and equipment insulation that is within SR and some NSR structures

within the scope of license renewal and the insulation is subject to an AMR. Therefore, the

staff’s concern described in RAI 2.3-s3 is resolved.

The staff reviewed LRA Section 2.3 and the applicant’s responses to the RAIs and performed a

plant audit. Based on this review, the staff found that the applicant’s methodology for scoping

and screening was well documented in an auditable and retrievable form at the plant site. The

staff also found that the results of the audit on the system and the regulated event confirmed

that there were no omissions of any components subject to an AMR for the audited systems. In

the LRA Section 2.3 tables, the staff found that the results are consistent with the methodology

and are acceptable. With the additional information obtained from responses to RAIs 2.3-2 and

2.3-3, the staff concluded that the applicant, while using a different methodology from that

described in the review guidance of the SRP-LR, provided scoping and screening results and

components subject to an AMR with no omissions. For other in-scope systems that were not

audited at the plant site, the staff issued RAIs related to components that could be subject to an

AMR based on its review of the LRA, UFSAR, and site documentation.

In RAIs 2.1-2A(1) and (2) (described in SER Section 2.1) of the July 30, 2004, letter, the staff

requested that the applicant describe the criteria used to determine that the integrity of in-scope

piping functions (in the reactor building) is preserved if a potential age-related degradation

failure occurred on the attached NSR piping (in the turbine building), given that the NSR piping

is not in scope and piping is not anchored, and 2) explain how it determined that the SR piping

(in the reactor building) is supported so that it would remain functional if a potential age-related

degradation occurred on the NSR piping (in the turbine building) attached to it. In its response

dated, October 18, 2004, the applicant committed to review the CLB requirements and identify

the piping, supports and other components outside secondary containment required to maintain

the structural integrity of the secondary containment. The applicant committed to performing

this review prior to the period of extended operation. The deferral of this issue until prior to the

period of extended operation is unacceptable. Therefore, the applicant performed the review,

the results of which are documented in a letter dated May 31, 2005. The following mechanical
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systems only had systems boundary changes (i.e., no new component types, materials, or

environments were added) that affected either the scoping/screening or AMR review results in

the LRA:

 • main steam system

 • auxiliary boiler system

 • raw cooling water system

 • station drainage system

 • high pressure coolant injection system

 • residual heat removal system

 • radioactive waste system

 • fuel pool cooling and cleanup system

 • radiation monitoring system

The following mechanical systems had systems boundary changes; however, for some of these

systems, new component types were added that affected the scoping/screening results in the

LRA. For all systems listed, new components, materials, or environments were added that

affected the AMR review results in the LRA:

 • condensate and demineralized water system

 • feedwater system

 • potable water system

 • service air system

 • containment system

The effects of these changes are evaluated and discussed in the corresponding sections of the

SER.

In RAI 2.1-2A(3), described in SER Section 2.1, dated July 30, 2004, the staff requested that

the applicant describe how the scoping and screening methodology ensured that NSR piping up

to the first equivalent anchor point was included within the scope of license renewal. The

applicant in its initial response to RAI 2.1.2A(3), dated September 3, 2004, committed to review

the seismic Class I piping boundaries and identify any additional piping segments and

supports/equivalent anchors that were needed to be placed within the scope of license renewal.

On September 24, 2004, in a teleconference between the staff and the applicant, the staff

requested that the applicant provide additional information related to the methodology to be

utilized to ensure the liquid-filled NSR piping up to the first equivalent anchor point was

captured. By letter, dated January 31, 2005, the applicant stated that an extensive review was

performed that included verification of each seismic Class I boundary that typically falls into one

of the following categories: base-mounted equipment, pipe anchor, embedded piping segment,

large run line, piping free end, flexible connection and overlap regions. Any identified piping,

supports/equivalent anchors, or other components would be added to the scope of license

renewal as needed. 

In a letter dated February 28, 2005, the applicant provided final status information and results

from the calculation review requested by the staff. In enclosure 1 of the letter, the applicant

provided a summary of the following changes to the LRA as a result of this review. 
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The mechanical systems listed below had additional piping or components added to the scope

of license renewal; however, even for those systems that had boundary changes as a result of

the additional piping and components, no changes to the LRA were required, because the

component-material-environment-program combination was already addressed in the LRA.

 • condensate and demineralized water system

 • standby liquid control system

 • containment system

 • reactor building closed cooling water system

 • auxiliary decay heat removal system

 • fuel pool cooling and cleanup system

The following mechanical systems also had additional piping or components added to the

scope of license renewal. However, for these systems with boundary changes because of the

addition of piping and components, changes to the LRA were required, because the

component-material-environment-program combination was not addressed in the LRA.

 • CO2 system

 • sampling and water quality system

 • off-gas system

 • radioactive waste treatment system

 • diesel generator starting air system

The effect of these changes are evaluated and discussed in the corresponding sections of the

SER (see Section 2.3.4.4 for details of RAIs 2.3.4.4-1 and 2.3.4.4-2).

2.3.1 Reactor Coolant Systems

In LRA Section 2.3.1, the applicant identified the structures and components of the reactor

coolant systems (RCSs) that are subject to an AMR for license renewal.

The applicant described the supporting structures and components of the RCSs in the following

sections of the LRA:

 • 2.3.1.1 reactor vessel

 • 2.3.1.2 reactor vessel internals

 • 2.3.1.3 reactor vessel vents and drains system

 • 2.3.1.4 reactor recirculation system

The corresponding SER subsections, 2.3.1.1 - 2.3.1.4, present the staff’s review findings.

2.3.1.1 Reactor Vessel

2.3.1.1.1 Summary of Technical Information in the Application

In LRA Section 2.3.1.1, the applicant described the reactor vessel. The reactor vessel provides

a container for the reactor core and the primary coolant in which the core is submerged. Each

unit has a separate reactor vessel. The reactor vessel is a pressure vessel with the geometry of
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a vertically-aligned cylinder capped with hemispherical heads of welded construction. The

cylindrical shell and bottom hemispherical head of the reactor vessel are fabricated from 

low-alloy carbon steel plate that is clad on the interior with weld overlay. The cylindrical shell is

clad with stainless steel and the bottom hemispherical head is clad with Inconel. The vessel top

head is not clad and is secured to the reactor vessel by studs and nuts. The vessel flanges are

sealed by two concentric metallic seal-rings that are designed for no detectable leakage

through the inner or outer seal at any operating condition.

The reactor vessel contains SR components that are relied upon to remain functional during,

and following, DBEs to ensure the following intended functions:

 • forms part of the reactor coolant pressure boundary

 • provides physical support for the reactor core and the reactor vessel internals

 • ensures a floodable volume and coolant distribution to mitigate accidents

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.1.1, the applicant identified the following reactor vessel component types that

are within the scope of license renewal and subject to an AMR: attachments and welds, closure

studs and nuts, heads, flanges, shell, nozzle safe ends, nozzles, other external attachments,

penetrations, refueling bellows support skirt, stabilizer bracket, and support skirt and

attachment welds.

2.3.1.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.1 and the UFSAR Section 4.2, 7.8, and Appendices J, K,

and L using the evaluation methodology described in SER Section 2.3. The staff conducted its

review on the reactor vessel in accordance with the guidance described in SRP-LR Section 2.3,

“Scoping and Screening Results - Mechanical Systems.”

In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in

accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not omitted

from the scope of license renewal any components with intended functions delineated under

10 CFR 54.4(a). The staff then reviewed those components that the applicant 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).

2.3.1.1.3 Conclusion

The staff reviewed the LRA to determine whether any SSCs that should be within the scope of

license renewal had not been 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 had not been 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

had adequately identified the reactor vessel components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and the reactor vessel components that are subject to

an AMR, as required by 10 CFR 54.21(a)(1).
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2.3.1.2 Reactor Vessel Internals

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 internals. The reactor vessel

internals are unique to each unit and provide partitions between regions within the reactor

vessel in order to provide proper coolant distribution, thereby allowing power operation without

fuel damage due to inadequate cooling. The reactor vessel internals also provide positioning

and support for the fuel assemblies, control rods, in-core flux monitors, and other components

to assure that control rod movement is not impaired. In addition, the reactor vessel internals

provide a floodable volume so that the core can be adequately cooled if there is an external

reactor vessel breach in the nuclear system process barrier.

The reactor vessel internals consist of the following components:

 • core shroud

 • shroud head and steam separator assembly

 • core support

 • top guide

 • fuel support pieces

 • control rod guide tubes (control rod housing)

 • jet pump assemblies

 • steam dryers

 • feed water spargers

 • core spray lines and spargers

 • vessel head spray nozzle

 • differential pressure and liquid control line

 • in-core flux monitor guide tubes

 • startup neutron sources

 • surveillance sample holders

The reactor vessel contains SR components that are relied upon to remain functional during,

and following, DBEs to ensure the following intended functions:

 • provides physical support for the reactor core and the reactor vessel internals

 • ensures a floodable volume and coolant distribution to mitigate accidents

 • provides pressure boundary

 • provides spray pattern

 • provides structural support

In LRA Table 2.3.1.2, the applicant identified the following reactor vessel internals component

types that are within the scope of license renewal and subject to an AMR: core shroud and

plate; core spray lines and spargers; control rod drive (CRD) housing; dry tubes and guide

tubes; fuel support; jet pump assemblies; and top guide.
2-40

2.3.1.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.2 and UFSAR Section 3.3, 4.2, and Appendices J, K, and

L using the evaluation methodology described in SER Section 2.3. The staff conducted its

review in accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in

accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not omitted

from the scope of license renewal any components with intended functions delineated under

10 CFR 54.4(a). The staff then reviewed those components that the applicant 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 reviewing LRA Section 2.3.1.2, the staff identified areas in which additional information

was necessary to complete the evaluation of the applicant’s scoping and screening results. 

In RAI 2.3.1.2-1, dated October 8, 2004, the staff requested the applicant to determine whether

the scoping criteria of 10 CFR 54.4 (a) and the screening criteria of 10 CFR 54.21(a)(1) had

been properly applied. The staff requested the following:

In LRA Table 2.3.1.2, one of the intended functions of core spray spargers was

appropriately identified as maintaining the spray pattern in a manner that all fuel

assemblies will be adequately cooled following a loss of coolant accident (LOCA). The

staff’s understanding is that adequate long-term core cooling following a LOCA can only

be assured by retaining the original spray distribution over the core, which was assumed

for the CLB. In the SER for the Boiling Water Reactor Vessel and Internals Project

(BWRVIP)-18 report, the staff had concluded that, when performing inspection of core

spray spargers, all boiling water reactor (BWR) plants must be treated as

geometry-critical plants. Furthermore, it is staff’s understanding that the previous

BWRVIP designations of “geometry-tolerant” plants have been rescinded and all plants

are now considered to be “geometry-critical.” Consequently, in order to assure adequate

cooling of the uncovered upper third of the core, the core spray system must provide

adequate spray distribution to all assemblies in the core. The staff also believes that

leakage through sparger and piping cracks, as well as repairs and potential blockage of

spray nozzles must be considered in assessing the core spray distribution. As a result, it

is essential that spraying water on the fuel assemblies in a pattern that was originally

designed must be maintained, and that the applicant’s aging management activities

provide reasonable assurance that the original spray distribution will be preserved

during the period of extended operation.

On the basis of the above discussion, the staff requests the applicant to affirm that when

performing inspection of core spray spargers, the BFN plants are inspected in

accordance to the requirements for the “geometry-critical” plants, as required by the

staff SER for the BWRVIP-18 report; and that the original spray pattern assumed for the

CLB will be preserved during the extended period of operation.
1TVA by letter dated January 7, 2005, agreed to decouple the power uprate licensing

request from License Renewal Application. The safety review of this item will be further

evaluated as part of the EPU review. 

2-41

In its response, by letter dated November 3, 2004, the applicant stated that BFN is performing

inspections as required by the BWRVIP-18 report, as modified by January 11, 1999, letter,

which requires that core spray spargers of all plants receive the same type of inspection. The

applicant also stated that, based on the Chemistry Control Program and that the nozzles are

constructed of a stainless steel material, corrosion is not a credible aging mechanism to cause

flow blockage. 

Based on its review, the staff found the applicant’s response to RAI 2.3.1.2-1 acceptable. The

applicant included the subject components and their intended functions as within scope

requiring an AMR. Therefore, the staff’s concern described in RAI 2.3.1.2-1 is resolved.

Recent industry experience of steam dryer failures at operating BWRs and the potential of

steam dryers to generate loose parts that can degrade SR components have necessitated that

the staff reconsider whether steam dryers should be within the scope of license renewal, in

accordance with 10 CFR 54.4(a)(2), and require aging management. Although the steam dryer

does not perform an SR function, the steam dryer must maintain its structural integrity to

support emergency core cooling system (ECCS) operation, and also to prevent the occurrence

of loose parts in the reactor vessel or steam lines that could adversely affect plant operation. 

In RAI 2.3.1.2-2, dated October 8, 2004, the staff requested the applicant to provide the

following additional information:

 • Whether the steam dryer designs at BFN and Quad Cities are similar. If not, the

applicant was requested to describe the significant differences between the two designs

that support the conclusion that steam dryer failures similar to those that occurred at

Quad Cities are unlikely to develop at the BFN steam dryers following power uprate.

 • Describe any actions, including analysis, that will be performed to confirm that extended

power uprate

1

 conditions will not generate loose parts from the steam dryer.

In its response, by letter November 3, 2004, the applicant stated that the steam dryers had

been added within the scope of license renewal on the basis of 10 CFR 54.4(a)(2) scoping

criterion. In addition, the applicant provided the following information to compare the

configuration of the steam dryers at BFN with the configuration of the steam dryers at the Quad

Cities Nuclear Power Station plants. 

There are three general types of steam dryer configurations:

 1. BWR/3-style steam dryers with a square hood and internal braces (This is the

configuration at Quad Cities).

 2. BWR/4-style steam dryers that have slanted hoods (This is the configuration at

BFN).
2-42

 3. BWR/5 and later steam dryer designs that incorporate curved hoods to optimize

the steam flow.

Basically the BFN dryer is a slanted hood design, which is much less susceptible to

vibration-induced failures than the square hood design of the Quad Cities dryers. General

Electric Corporation (GE) has conducted finite element model analysis, which documents that

the square hood is more susceptible to operating stresses. The forcing function for the dryer

loads has been identified as being primarily acoustic loads that originate in the steam lines. The

BWRVIP and the industry have efforts underway to develop methods to measure and

document the amount of additional loads that may be placed on the dryer as the result of

uprated conditions. The applicant further stated that it will follow the BWRVIP guidelines for the

inspection and evaluation of the dryers to insure their future integrity under uprated operating

conditions. 

The applicant added the subject components within the scope requiring an AMR and the staff’s

concerns described in RAI 2.3.1.2-2 are partly resolved. However, the subject of the second

question of the staff RAI is currently being reviewed as part of the ongoing EPU review (see

footnote previous page).

2.3.1.2.3 Conclusion

The staff reviewed the LRA and RAI responses to determine whether any SSCs that should be

within the scope of license renewal had not been 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 had not been 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 had adequately identified the reactor vessel internals components that are within

the scope of license renewal, as required by 10 CFR 54.4(a), and the reactor vessel internals

components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.1.3 Reactor Vessel Vents and Drains System

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 vents and drains system. The

reactor vessel vents and drains system consists of the valves and piping connected to the

reactor coolant pressure boundary (RCPB). This includes the reactor vessel head vent piping,

the reactor vessel bottom head drain piping, and the blowdown piping from the main steam

relief valves (MSRVs) to the pressure suppression chamber. The system is unique to each unit

and shares no components with other units. All piping and components are located within the

primary containment.

The reactor vessel vents and drains system contains SR components that are relied upon to

remain functional during, and following, DBEs to ensure the following intended functions:

 • provides a path for the main steam (MS) system, safety relief valves (SRVs), and steam

blowdown to the primary containment suppression pool

 • provides RCPB
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 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.1.3, the applicant identified the following reactor vessel vents and drains

system component types that are within the scope of license renewal and subject to an AMR:

bolting, fittings, RCPB fittings, piping, RCPB piping, valves, and RCPB valves.

2.3.1.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.3 and UFSAR Sections 4.11, 7.8, and C.2 using the

evaluation methodology described in SER Section 2.3. The staff conducted its review

in accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in

accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not omitted

from the scope of license renewal any components with intended functions delineated under

10 CFR 54.4(a). The staff then reviewed those components that the applicant 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 had not been 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 had not been 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

had adequately identified the reactor vessel vents and drains system components that are

within the scope of license renewal, as required by 10 CFR 54.4(a), and the reactor vessel

vents and drains system components that are subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.3.1.4 Reactor Recirculation System

2.3.1.4.1 Summary of Technical Information in the Application

In LRA Section 2.3.1.4, the applicant described the reactor recirculation system. The reactor

recirculation system is unique to each unit and consists of two piping loops connected to, but

external to, the reactor vessel. Each loop has a single, variable speed, motor driven pump with

pump suction and discharge valves. Each pump takes suction from the reactor vessel

downcomer region and discharges into a manifold that supplies flow to ten jet pumps contained

within the reactor vessel. During normal operations, the system provides sufficient subcooled

water to the reactor core to maintain the normal core operating temperatures. The system also

provides control of reactor power by varying recirculation flow during normal operations. In

addition, the system provides a flow path for the low pressure coolant injection flow from the
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RHR system to the reactor vessel during design basis accidents (DBAs) and a flow path to and

from the RHR system for removal of decay heat at low temperatures.

The reactor recirculation system contains SR components that are relied upon to remain

functional during, and following DBEs. The failure of NSR SSCs in the reactor recirculation

system could prevent the satisfactory accomplishment of an SR function. In addition, the

reactor recirculation system performs functions that support fire protection, EQ, and ATWS.

The intended functions within the scope of license renewal include the following:

 • provides RCPB

 • provides a primary containment boundary

 • restricts flow

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.1.4, the applicant identified the following reactor recirculation system

component types that are within the scope of license renewal and subject to an AMR: bolting,

fittings, RCPB fittings, flexible connectors, heat exchangers, piping, RCPB piping, pumps,

reactor coolant pumps, restricting orifices, RCPB restricting orifices, strainers, tanks, tubing,

valves, and RCPB valves.

2.3.1.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.4 and UFSAR Sections 3.7.6, 4.3, 5.2.3, 7.8, 7.9, and

7.19 using the evaluation methodology described in SER Section 2.3. The staff conducted its

review in accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in

accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not omitted

from the scope of license renewal any components with intended functions delineated under

10 CFR 54.4(a). The staff then reviewed those components that the applicant 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 reviewing LRA Section 2.3.1.4, the staff identified an area in which additional information

was necessary to complete the evaluation of the applicant’s scoping and screening results. The

staff requested the applicant to determine whether the scoping criteria of 10 CFR 54.4 (a) and

the screening criteria of 10 CFR 54.21(a)(1) have been properly applied. 

In RAI 2.3.1.4-1, dated October 8, 2004, the staff stated that in LRA Table 2.3.1.4, for the

reactor recirculation system, and for other systems, for example, the containment inerting

system, heat exchangers have been identified as a component type within the scope of license

renewal. However, for these heat exchangers, the pressure boundary function was identified as

the only intended function requiring aging management. Therefore, the staff requested the

applicant to clarify why the heat transfer function was not also identified as an intended function
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that needs to be maintained during the extended period of operation by assigning appropriate

aging management program (AMP) for it.

In its response, by letter dated November 3, 2004, the applicant stated that the heat

exchangers associated with LRA Table 2.3.1.4 are the heat exchangers shown on license

renewal drawings 2-47E844-2-LR and 3-47E817-2-LR. The shell sides of these heat

exchangers are within the scope of license renewal for secondary containment as a pressure

boundary for the raw water system. These heat exchangers are not SR, but the tube side is

within the scope of license renewal to satisfy 10 CFR 54.4(a)(2) requirements only. Therefore,

these heat exchangers are not credited for their heat transfer function. 

Based on its review, the staff found the applicant’s response to RAI 2.3.1.4-1 acceptable. The

applicant provided the justification as to why the heat transfer function of the subject

components need not be within the scope of license renewal requiring aging management.

Therefore, the staff’s concern described in RAI 2.3.1.4-1 is resolved.

2.3.1.4.3 Conclusion

The staff reviewed the LRA, the accompanying scoping boundary drawings, and RAI response

described above to determine whether any SSCs that should be within the scope of license

renewal had not been 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 had not been 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 had

adequately identified the reactor recirculation system components that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and the reactor recirculation 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 (ESFs) that are subject to an AMR for license renewal.

The applicant described the supporting structures and components of the ESF in the following

sections of the LRA:

 • 2.3.2.1 containment systems

 • 2.3.2.2 standby gas treatment system

 • 2.3.2.3 high pressure coolant injection system

 • 2.3.2.4 residual heat removal system

 • 2.3.2.5 core spray system

 • 2.3.2.6 containment inerting system

 • 2.3.2.7 containment atmosphere dilution system

The corresponding SER subsections, 2.3.2.1 – 2.3.2.7, present the staff’s review findings with

respect to the ESF for BFN.
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2.3.2.1 Containment System

2.3.2.1.1 Summary of Technical Information in the Application

In LRA Section 2.3.2.1, the applicant described the containment system. The containment

system includes the following subsystems: the primary containment and primary containment

isolation system, the secondary containment, and the reactor building ventilation system. The

scoping and screening results for the primary containment isolation valves for the various

processes are presented within their respective systems. The results of the scoping and

screening evaluations for the other components within the containment system including valves,

piping, penetrations, structural steel, that are essential for primary containment integrity, are

presented in other sections of this SER.

The primary containment system for each unit employs an independent pressure suppression

that houses the reactor vessel, reactor coolant recirculation loops, and other branch

connections of systems that form the RCPB. The Mark I containment is a pressure suppression

system design, which consists of a drywell and a pressure suppression chamber that is

alternatively referred to as the “torus” or “wetwell.” The Mark I pressure suppression system

also contains a connecting vent system between the drywell and the pressure suppression

chamber, isolation valves, equipment for establishing and maintaining a pressure differential

between the drywell and pressure suppression chamber, and other service equipment. Air that

is transferred to the pressure suppression chamber pressurizes the chamber and is

subsequently vented to the drywell to equalize the pressure between the two vessels, and it is

necessary in the event of a process system piping failure within the drywell. Cooling systems

are provided to remove heat from the drywell and the water from the pressure suppression

chamber, thus cooling and controlling the pressure in the primary containment under accident

conditions. In addition, valves and flowpaths are provided to control the internal and the

torus/drywell differential pressure. If long-term, post-accident cooling capability is lost, resulting

in a pressure increase that would jeopardize the structural integrity of the primary containment,

a hardened wetwell vent to the plant stack can be opened to relieve the pressure increase.

The containment system also includes the secondary containment system. The secondary

containment system provides an essentially leak-tight envelope for any radiation release from

the primary containment during DBEs. The secondary containment system also provides a

primary envelope for radiation releases when the primary containment systems are open for

refueling or maintenance.

This structure is divided into three reactor zones and a refueling zone. Each reactor zone

houses the reactor, the primary containment, and the individual unit’s ECCS. The structure also

contains a spent fuel storage pool for each individual unit. The refueling zone allows continuous

access to the three spent fuel storage pools and the reactor vessel for refueling and servicing.

The reactor building ventilation system is also included within the containment system. The

reactor building is heated, cooled, and ventilated during normal and shutdown operations by a

circulating air system. The reactor building ventilation system is shut down and isolated when a

zone of secondary containment is isolated and connected to the standby gas treatment (SGT)

system. The ventilation system has supply fans that provide makeup air that is filtered, heated

by hot water coils for winter heating, and cooled by evaporative coolers for summer cooling. Air
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is exhausted from the reactor building by exhaust fans located on the building’s roof. Air from

each zone is monitored before release. The reactor building ventilation system also includes

area cooling units for areas containing ECCS components.

The containment system contains SR components that are relied upon to remain functional

during, and following, DBEs. The failure of NSR SSCs in the containment system could prevent

the satisfactory accomplishment of an SR function. In addition, the containment system

performs functions that support fire protection, EQ, and SBO.

The intended functions within the scope of license renewal include the following:

 • provides a primary containment boundary

 • provides a vacuum relief system (vacuum breaker valves) to prevent drywell or

suppression chamber (torus) negative pressure from damaging the containment

structure

 • provides air-operated re-closure of the inboard reactor building to the torus vacuum

breakers

 • provides pressure suppression by cooling/condensation of the safety relief valves

(SRVs) steam from boiler drains and vents system and reactor core isolation cooling

(RCIC) system and high pressure coolant injection (HPCI) system turbine exhaust

steam

 • accepts HPCI and RCIC system pump minimum bypass flow

 • provides a water supply to the RCIC system, HPCI system, core spray (CS) system, and

RHR system pumps

 • provides forced air cooling for the RHR system and the CS system pump motors

 • provides a secondary containment boundary (passive functions)

 • provides a pressure boundary of containment system components connected to the

control air system that must maintain the pressure boundary in support of supplying

containment atmosphere dilution (CAD) to the main steam safety relief valves (MSRVs)

 • provides fire dampers that are required for unit operation

 • provides debris protection

 • provides fire barrier

 • provides for heat transfer

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.2.1, the applicant identified the following containment system component

types that are within the scope of license renewal and subject to an AMR: bolting, ductwork,

heat exchangers, fire dampers, flexible connectors, fittings, piping, strainers, traps, tubing, and

valves.
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2.3.2.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.1, LRA Appendix F, and UFSAR Sections 5.2, 5.3,

5.3.3.2, 5.3.3.6, and 7.3, F.7.1, and F.7.11 using the evaluation methodology described in SER

Section 2.3. The staff conducted its review in accordance with the guidance described in

SRP-LR Section 2.3.

In conducting the review, the staff reviewed the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 reviewing LRA Section 2.3.2.1, the staff identified an area in which additional information was

necessary to complete the review of the applicant’s scoping and screening results. Therefore,

by letter dated October 8, 2004, the staff issued an RAI concerning the specific issues to

determine whether the applicant had properly applied the scoping criteria of 10 CFR 54.4(a)

and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs describe the staff’s

RAIs and the applicant’s related responses.

In RAI 2.3.2.1-1, the staff requested that the applicant clarify whether all the system

components such as, but not limited to, air cooling unit housings, dampers and damper

housings, cooling coil housings, valve bodies, and screens for intake and exhaust structures

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, by letter dated November 3, 2004, and supplemented by a letter dated

December 3, 2004, the applicant stated that all applicable system components consisting of air

cooling unit housings, dampers and damper housings, cooling coil housings, and valve bodies

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 RBVS (containment). LRA Section 2.3.5,

“Notes Associated with the Section 2.3 Tables,” is revised to reflect these component types

and, therefore, is part of “Component Types” in LRA Table 2.3.2.1, “Containment System,” and

LRA Table 3.2.2.1, “Containment System-Summary of Aging Management Evaluation.” The

applicant also stated that the RBVS contains an intake plenum that contains louvers with

screens and that these components perform no license renewal function; therefore, these

components are not within the scope of license renewal.

Based on the review, the staff found the applicant’s response to RAI 2.3.2.1-1 acceptable. The

applicant clarified that all applicable system components consisting of air cooling unit housings,

dampers and damper housings, cooling coil housings, and valve bodies are within the scope of

license renewal, and subject to an AMR for the RBVS and are already included in “Component

Types” in LRA Tables 2.3.2.1 and 3.2.2.1. Since the RBVS intake plenum with louvers and

screens performs no license renewal function, these components are not within the scope of

license renewal. Therefore, the staff’s concern described in RAI 2.3.2.1-1 is resolved.
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2.3.2.1.3 Conclusion

The staff reviewed the LRA and RAI response described above to determine whether any SSCs

that should be within the scope of license renewal had not been 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 had not been 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 had adequately identified the containment system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the containment system components that are subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.3.2.2 Standby Gas Treatment System

2.3.2.2.1 Summary of Technical Information in the Application

In LRA Section 2.3.2.2, the applicant described the SGT system. The SGT system is shared

between Units 1, 2, and 3. The SGT system consists of a suction duct system, three filter trains

and blowers, and a discharge vent system. The common suction duct system takes suction

from the normal ventilation exhaust duct of each of the three reactor zones and from the

refueling zone that is independent of the normal ventilation system. Each filter train contains a

moisture separator, a heater, a pre-filter, an upstream high efficiency particulate air (HEPA)

filter, a charcoal filter, and a downstream HEPA filter. These three filter trains and blowers are

arranged in parallel. The three blowers share a common discharge header that discharges to

the plant stack 600 feet in elevation. The filter trains and blowers are located in the SGT

building. The SGT system is normally in standby operation and will start automatically, when

required.

The SGT system contains SR components that are relied upon to remain functional during, and

following, DBEs. In addition, the SGT system performs functions that support EQ.

The intended functions within the scope of license renewal include the following:

 • maintains negative pressure in the secondary containment on the primary containment

system group six isolation signal 

 • filters airborne particulates and gases including those from the HPCI and CAD systems

prior to discharge to the off-gas system

 • maintains negative pressure in secondary containment on primary containment system

signal due to radiation monitoring system refueling zone high radiation signal

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.2.2, the applicant identified the following SGT system component types that

are within the scope of license renewal and subject to an AMR: bolting, ductwork, fittings,

flexible connectors, piping, tubing, and valves.
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2.3.2.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.2 and LRA Appendix F and UFSAR Sections 5.3.3,

7.12.5, and F.7.18 using the evaluation methodology described in SER Section 2.3. The staff

conducted its review in accordance with the guidance described in SRP-LR Section 2.3.

In conducting the review, the staff reviewed the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 reviewing LRA Section 2.3.2.2, the staff identified an area in which additional information was

necessary to complete the review of the applicant’s scoping and screening results. Therefore,

by letter dated October 8, 2004, the staff issued an RAI concerning the specific issues to

determine whether the applicant had properly applied the scoping criteria of 10 CFR 54.4(a)

and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs describe the staff’s

RAI and the applicant’s responses.

In RAI 2.3.2.2-1, the staff requested the applicant to clarify whether all the system’s

components such as, but not limited to, fan housings, filter housing, damper housing, valve

bodies, screens for intake and exhaust structures, and all other applicable components of the

system, including duct sealants, wall sealants, 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).

In its response, by letter dated November 3, 2004, and supplemented by a letter dated

December 3, 2004, the applicant stated that all applicable system components consisting of fan

housings, filter housing, damper housing, valve bodies 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 SGT

system. The applicant also stated that structural sealants, such as those required to maintain

the secondary containment at a negative pressure with respect to the adjacent areas, are

contained in LRA Section 3.5.2.1.2 and Table 3.5.2.2 as component types “Compression Joints

and Seals” and “Caulking and Sealants,” and that the SGT system does not contain air

intake/exhaust structures with screens (SGT system exhausts to the reinforced concrete

chimney (plant stack) as addressed in LRA Section 2.4.6.1).

 In LRA Section 2.3.5, “Notes Associated with the Section 2.3 Tables,” “Component Types” are

revised to reflect these components and, therefore, are part of LRA Table 2.3.2.2, “Standby

Gas Treatment System” and LRA Table 3.2.2.2, “Standby Gas Treatment System-Summary of

Aging Management Evaluation.”

Based on its review, the staff found the applicant’s response to RAI 2.3.2.2-1 acceptable. The

applicant clarified that all applicable system components consisting of fan housings, filter

housing, damper housing, valve bodies, and all other applicable components of the system,

including duct sealants, wall sealants, and pressure boundary sealants are within the scope of
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license renewal, and subject to an AMR for the SGT system and are already included in

“Component Types” in LRA Tables 2.3.2.2 and 3.2.2.2. Therefore, the staff’s concern described

in RAI 2.3.2.2-1 is resolved.

2.3.2.2.3 Conclusion

The staff reviewed the LRA and RAI response described above to determine whether any SSCs

that should be within the scope of license renewal had not been 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 had not been 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 had adequately identified the SGT system components

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the SGT

system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.2.3 High Pressure Coolant Injection System

2.3.2.3.1 Summary of Technical Information in the Application

In LRA Section 2.3.2.3, the applicant described the HPCI system. The HPCI system, in

conjunction with the other ECCSs, limits the peak fuel clad temperature, over the complete

spectrum of possible break sizes in the RCPB, during design-basis accidents. The HPCI

system also provides adequate core cooling for small breaks and depressurizes the reactor

coolant systems to allow low-pressure coolant injection and core spray flow. In addition, the

HPCI system provides reactor vessel make-up, pressure control, and decay heat removal

during regulated events.

Each unit has an individual HPCI system and no components are shared; however, each unit’s

HPCI pump may take suction from any unit’s condensate storage tank. The HPCI system

consists of a single steam turbine-driven pump. The steam supply for the turbine comes from

the MS system and exhausts to the suppression pool. The pump takes suction from the

condensate storage tank, or the suppression pool, and discharges into the reactor vessel,

through the feedwater (FW) system. A full-flow test line to the condensate storage tank is

provided. During normal operation, the HPCI system is in standby. The HPCI system

automatically starts if there is high pressure in the drywell or a low-water level in the reactor

vessel.

The HPCI system contains SR components that are relied upon to remain functional during,

and following, DBEs. The failure of NSR SSCs in the HPCI system could prevent the

satisfactory accomplishment of an SR function. In addition, the HPCI system performs functions

that support fire protection, EQ, and SBO.

The intended functions within the scope of license renewal include the following:

 • provides an RCPB during HPCI system standby and operation

 • provides a primary containment boundary during HPCI system standby and operation
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 • limits the loss of coolant through the HPCI system steam supply line break (passive,

flow restrictor built into the steam line)

 • provides a secondary containment boundary

 • establishes a main steam safety isolation valve (MSIV) leakage pathway to the

condenser

 • provides coolant to the reactor vessel until it can be manually run in the condensate

storage tank to condensate storage tank recirculation mode for pressure relief and

decay heat 

 • provides debris protection

 • provides for flow distribution

 • restricts flow

 • provides for heat transfer

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.2.3, the applicant identified the following HPCI system component types that

are within the scope of license renewal and subject to an AMR: bolting, condenser, expansion

joint, fittings, RCPB fittings, flexible connectors, gland seal blower, heat exchangers, piping,

RCPB piping, pumps, restricting orifice, RCPB restricting orifice, strainers, tanks, traps, tubing,

turbines, valves, and RCPB valves.

2.3.2.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.3 and UFSAR Sections 5.2.3, 5.3, 6.3, 6.4.1, and 7.4

using the evaluation methodology described in SER Section 2.3. The staff conducted its review

in accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in

accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not omitted

from the scope of license renewal any components with intended functions delineated under

10 CFR 54.4(a). The staff then reviewed those components that the applicant 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 had not been 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 had not been 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

had adequately identified the HPCI system components that are within the scope of license
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renewal, as required by 10 CFR 54.4(a), and the HPCI system components that are subject to

an AMR, as required by 10 CFR 54.21(a)(1).

2.3.2.4 Residual Heat Removal System

2.3.2.4.1 Summary of Technical Information in the Application

In LRA Section 2.3.2.4, the applicant described the RHR system. Each unit has two RHR

system loops and each loop has two RHR pumps and two RHR heat exchangers. The pump

suction header and the heat exchanger discharge header of one loop in Unit 1 and one loop in

Unit 2 can be cross-connected. A similar cross-connection is provided between Unit 2 and

Unit 3. 

The RHR system provides a number of functions that are manually initiated. The RHR system

provides shutdown cooling during normal operations and regulated events. The RHR system, in

conjunction with the other ECCSs, also provides core flooding to limit the peak fuel clad

temperatures over the complete spectrum of possible break sizes in the RCPB during

design-basis accidents.

Provisions are provided within the RHR system, for both makeup and reject, to maintain the

suppression pool level within the required limits. Cross-connections with the fuel pool cooling

system allow the RHR heat exchangers to supplement heat removal and provide a permanent

source of makeup water for the spent fuel pool.

The RHR contains SR components that are relied upon to remain functional during, and

following, DBEs. The failure of NSR SSCs in the RHR could prevent the satisfactory

accomplishment of an SR function. In addition, the RHR performs functions that support fire

protection, EQ, and SBO.

The intended functions within the scope of license renewal include the following:

 • provides suppression pool water cooling to maintain the suppression pool water

temperature below limits to assure that pump net positive suction head requirements are

met and that complete condensation of blowdown steam from a design-basis LOCA can

be expected

 • provides spray to drywell and torus for containment cooling and lowering of containment

pressure under post-accident conditions

 • provides a secondary containment boundary and a pressure boundary interface with the

condensate ring header

 • provides RCPB

 • provides RHR system piping flow path for transmission of condensate and

demineralized water system water supply to HPCI system piping upstream of HPCI

system pump

 • provides RHR system piping flow path from the HPCI system pump minimum flow

coolant to the main RHR system heat exchangers
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 • provides debris protection

 • provides for flow distribution

 • restricts flow

 • provides for heat transfer

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.2.4, the applicant identified the following RHR system component types that

are within the scope of license renewal and subject to an AMR: bolting, fittings, RCPB fittings,

heat exchangers, piping, RCPB piping, pumps, restricting orifice, strainers, tubing, valves, and

RCPB valves.

2.3.2.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.4 and UFSAR Sections 3.3, 4.1, 4.8, 5.2.3, 5.3, 6.4.4,

7.3, 7.4, 7.18, 9.2, 10.5, 10.9, 10.10, 10.17, F7.9, F7.15, and F7.16 using the evaluation

methodology described in SER Section 2.3. The staff conducted its review in accordance with

the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in

accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not omitted

from the scope of license renewal any components with intended functions delineated under

10 CFR 54.4(a). The staff then reviewed those components that the applicant 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 had not been 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 had not been 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

had adequately identified the RHR system components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and the RHR system components that are subject to

an AMR, as required by 10 CFR 54.21(a)(1).

2.3.2.5 Core Spray System

2.3.2.5.1 Summary of Technical Information in the Application

In LRA Section 2.3.2.5, the applicant described the CS system. The CS system, in conjunction

with the other ECCSs, provides spray cooling to the reactor core to limit the peak fuel clad
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temperature over the complete spectrum of possible break sizes in the RCPB during

design-basis accidents. Each individual unit contains a separate CS system with two

independent loops. Each loop has two pumps that can pump water from the suppression pool

directed into the reactor vessel to the spray headers located above the core and within the core

shroud. Some CS system components are located within the reactor vessel; these components

are evaluated in the reactor vessel internals section of this SER. 

Full-flow pump test capability is provided by discharge line to the suppression pool. During

normal operation, the CS system is in standby and can be started automatically, when required.

Full-flow suction lines from the condensate storage tanks penetrate the secondary containment

and provide a suction flow path for the RCIC and HPCI systems.

The CS system contains SR components that are relied upon to remain functional during, and

following, DBEs. The failure of NSR SSCs in the CS system could prevent the satisfactory

accomplishment of an SR function. In addition, the CS system performs functions that support

EQ.

The intended functions within the scope of license renewal include the following:

 • supplies cooling water to the reactor (automatic initiation)

 • provides RCPB

 • provides a primary containment boundary

 • provides a secondary containment boundary and pressure boundary interface with the

condensate system ring header

 • provides debris protection

 • restricts flow

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.2.5, the applicant identified the following CS system component types that are

within the scope of license renewal and subject to an AMR: bolting, fittings, RCPB fittings,

piping, RCPB piping, pumps, restricting orifice, RCPB restricting orifice, strainers, tanks, tubing,

valves, and RCPB valves.

2.3.2.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.5 and the UFSAR Sections 4.4, 5.2, 5.3, 6.4.3, 7.3, 7.4,

7.8, 10.10, and 11.7 using the evaluation methodology described in SER Section 2.3. The staff

conducted its review in accordance with the guidance described in the SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in

accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not omitted

from the scope of license renewal any components with intended functions delineated under

10 CFR 54.4(a). The staff then reviewed those components that the applicant had identified as
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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 reviewing LRA Section 2.3.2.5, the staff identified an area in which additional information

was necessary to complete the evaluation of the applicant’s scoping and screening results.

Therefore, by letter to the applicant dated October 8, 2004, the staff issued an RAI concerning

the specific issues to determine whether the applicant had properly applied the scoping criteria

of 10 CFR 54.4 (a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs

describe the staff’s RAIs and the applicant’s related responses.

In RAI 2.3.2.5-1, the staff stated that the low pressure coolant injection (LPCI) coupling was

identified in the BWRVIP-06 report as an SR component. It appears, however, that the

component was not identified in the LRA as requiring an AMR. Therefore, the staff requested

the applicant to justify its exclusion from aging management and to submit an AMR for the

subject component.

In its response, by letter dated November 3, 2004, the applicant stated that BFN does not

contain a LPCI coupling; therefore this component was not identified in the LRA. Therefore, the

staff’s concern described in RAI 2.3.2.5-1 is resolved.

2.3.2.5.3 Conclusion

The staff reviewed the LRA and RAI response described above to determine whether any SSCs

that should be within the scope of license renewal had not been 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 had not been 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 had adequately identified the CS system components

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the CS system

components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.2.6 Containment Inerting System

2.3.2.6.1 Summary of Technical Information in the Application

In LRA Section 2.3.2.6, the applicant described the containment inerting system. The

containment inerting system provides the capability to measure oxygen and hydrogen

concentrations in the primary containment following an accident. A separate oxygen and

hydrogen monitoring system, with two sampling loops, is provided for each unit. The loops

have pumps that pump the drywell or torus atmosphere past the hydrogen and oxygen sensors

and back to the torus. In the event of an accident, the containment inerting system would be

manually started.

The containment inerting system contains SR components that are relied upon to remain

functional during, and following, DBEs. The failure of NSR SSCs in the containment inerting

system could prevent the satisfactory accomplishment of an SR function. In addition, the

containment inerting system performs functions that support EQ.
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The intended functions within the scope of license renewal include the following:

 • provides oxygen and hydrogen gas analyzers and indicators to monitor gas

concentrations inside the primary containment in support of CAD system operation,

 • provides a primary containment boundary

 • provides a secondary containment boundary

 • provides debris protection

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.2.6, the applicant identified the following containment inerting system

component types that are within the scope of license renewal and subject to an AMR: bolting,

flexible connectors, heat exchangers, fittings, piping, pumps, strainers, traps, tubing, and

valves.

2.3.2.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.6, LRA Appendix F, and UFSAR Section 5.2.6 using the

evaluation methodology described in SER Section 2.3. The staff conducted its review in

accordance with the guidance described in SRP-LR Section 2.3.

In conducting the review, the staff reviewed the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 reviewing LRA Section 2.3.2.6, the staff identified an area in which additional information was

necessary to complete the review of the applicant’s scoping and screening results. Therefore,

by the letter dated October 8, 2004, the staff issued an RAI concerning the specific issues to

determine whether the applicant had properly applied the scoping criteria of 10 CFR 54.4(a)

and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs describe the staff’s

RAI and the applicant’s response.

In RAI 2.3.2.6-1, the staff requested that the applicant clarify whether the system components

such as piping, valves, and equipment between FCV-76-17 and PC-V67-14, including the

downstream bypass line after BYV-76-542, and between CKV-76-653 and CKV-76-659

depicted on LRA drawings 47E860-1-LR for Units 1, 2, and 3, 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, by letter dated November 3, 2004, the applicant stated that all applicable

system components between primary containment isolation valve FCV-76-17 and secondary
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containment isolation valve PCV-76-14, and between primary containment isolation valve

CKV-76-653 and secondary containment isolation valve CKV-76-659 are not within scope for

10 CFR 54.4(a)(1). They are not within scope for 10 CFR 54.4(a)(3) since they are not required

for any of the regulated events. Also, since these components are not liquid filled, they do not

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

Based on its review, the staff found the applicant’s response to RAI 2.3.2.6-1 acceptable. The

applicant clarified why the above system components are not within the scope of license

renewal. The applicant identified those portions of the containment inerting system that meet

the scoping requirements of 10 CFR 54.4 and included them within the scope of license

renewal in LRA Section 2.3.2.6. The applicant also included containment inerting system

components that are subject to an AMR in accordance with 10 CFR 54.4(a) and

10 CFR 54.21(a) (1) in LRA Table 2.3.2.6, “Containment Inerting System,” and in LRA

Table 3.2.2.6, “Containment Inerting System-Summary of Aging Management Evaluation.”

Therefore, the staff’s concern described in RAI 2.3.2.6-1 is resolved.

2.3.2.6.3 Conclusion

The staff reviewed the LRA, the accompany scoping boundary drawings, and the RAI response

described above to determine whether any SSCs that should be within the scope of license

renewal had not been 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 had not been 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 had

adequately identified the containment inerting system components that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and the containment inerting system

components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.2.7 Containment Atmosphere Dilution System

2.3.2.7.1 Summary of Technical Information in the Application

In LRA Section 2.3.2.7, the applicant described the CAD system. The CAD system is shared

between Units 1, 2, and 3. The system consists of two trains, each of which is capable of

supplying nitrogen through separate piping systems, to the drywell and suppression chamber.

The system is in standby during normal operation and is started manually when required.

The CAD system contains SR components that are relied upon to remain functional during, and

following, DBEs. In addition, the CAD system performs functions that support fire protection,

EQ, and SBO.

The intended functions within the scope of license renewal include the following:

 • provides for dilution of the primary containment atmosphere with nitrogen after a LOCA

to maintain hydrogen and oxygen gas concentrations below a level that could produce a

combustible mixture (five percent oxygen by volume) 

 • provides a primary containment boundary
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 • provides a secondary containment boundary

 • provides nitrogen as the actuating medium for the reactor building to torus vacuum

breaker butterfly valves when control air is not available

 • provides nitrogen makeup to the MSRVs

 • provides for heat transfer

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.2.7, the applicant identified the following CAD system component types that

are within the scope of license renewal and subject to an AMR: bolting, fittings, flex hose, heat

exchangers, piping, tanks, tubing, and valves.

2.3.2.7.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.7, LRA Appendix F, and UFSAR Sections 5.2.3 and 5.2.6

using the evaluation methodology described in SER Section 2.3. The staff conducted its review

in accordance with the guidance described in SRP-LR Section 2.3.

In conducting the review, the staff reviewed the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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).

On the basis of its review, the staff found that the applicant identified those portions of the CAD

system that meet the scoping requirements of 10 CFR 54.4 and included them within the scope

of license renewal in LRA Section 2.3.2.7. The applicant also included CAD system

components that are subject to an AMR in accordance with 10 CFR 54.4(a) and

10 CFR 54.21(a)(1) in LRA Table 2.3.2.7, “Containment Atmosphere Dilution System,” and in

LRA Table 3.2.2.7, “Containment Atmosphere Dilution System-Summary of Aging Management

Evaluation.” LRA Section F.2, “Containment Atmosphere Dilution System Modifications,”

indicates that Unit 1 capability to supply pressurized nitrogen to operate the MSRVs when

control air is not available will be identical to the capability of Units 2 and 3 and will result in the

same AMPs for each unit. This item will be discussed in SER Section 2.6.1.2.

2.3.2.7.3 Conclusion

The staff reviewed the LRA to determine whether any SSCs that should be within the scope of

license renewal had not been 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 had not been 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

had adequately identified the CAD system components that are within the scope of license
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renewal, as required by 10 CFR 54.4(a), and the CAD 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 systems and components of the auxiliary

systems that are subject to an AMR for license renewal in the following sections of the LRA:

 • 2.3.3.1 auxiliary boiler system

 • 2.3.3.2 fuel oil system

 • 2.3.3.3 residual heat removal service water system

 • 2.3.3.4 raw cooling water system

 • 2.3.3.5 raw service water system

 • 2.3.3.6 high pressure fire protection system

 • 2.3.3.7 potable water system

 • 2.3.3.8 ventilation system

 • 2.3.3.9 heating, ventilation, and air conditioning system

 • 2.3.3.10 control air system

 • 2.3.3.11 service air system

 • 2.3.3.12 CO2 system

 • 2.3.3.13 station drainage system

 • 2.3.3.14 sampling and water quality system

 • 2.3.3.15 building heat system

 • 2.3.3.16 raw water chemical treatment system

 • 2.3.3.17 demineralizer backwash air system

 • 2.3.3.18 standby liquid control system

 • 2.3.3.19 off-gas system

 • 2.3.3.20 emergency equipment cooling water system

 • 2.3.3.21 RWCU system

 • 2.3.3.22 reactor building closed cooling water system

 • 2.3.3.23 reactor core isolation cooling system

 • 2.3.3.24 auxiliary decay heat removal system

 • 2.3.3.25 radioactive waste treatment system

 • 2.3.3.26 fuel pool cooling and cleanup system

 • 2.3.3.27 fuel handling and storage system

 • 2.3.3.28 diesel generator system

 • 2.3.3.29 control rod drive system

 • 2.3.3.30 diesel generator starting air system

 • 2.3.3.31 radiation monitoring system

 • 2.3.3.32 neutron monitoring system

 • 2.3.3.33 traversing in-core probe system

 • 2.3.3.34 cranes system

The corresponding sub-sections of this SER (2.3.3.1 – 2.3.3.34) present the staff’s review

findings for each system of the auxiliary systems.
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2.3.3.1 Auxiliary Boiler System

2.3.3.1.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.1, the applicant described the auxiliary boiler system. The auxiliary boiler

system provides heating and miscellaneous steam services within the power house. This

includes the ability to test the HPCI system and the RCIC system turbines while the reactor is

shutdown. This system is a plant-shared system. The turbine building contains three oil-fired,

auxiliary boilers.

The auxiliary boiler system contains SR components that are relied upon to remain functional

during, and following, DBEs. The failure of NSR SSCs in the auxiliary boiler system could

prevent the satisfactory accomplishment of an SR function. 

The intended functions within the scope of license renewal include the following:

 • provides primary and secondary containment boundaries

 • establishes an MSIV pathway to the condenser

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.3.1, the applicant identified the following auxiliary boiler system component

types that are within the scope of license renewal and subject to an AMR: bolting, fittings, pipes,

traps, tubing, and valves.

2.3.3.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.1 and UFSAR Sections 5.2, 5.3, and 10.20 using the

evaluation methodology described in SER Section 2.3. The staff conducted its review in

accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 order to resolve the 10 CFR 54.4(a)(2) issues discussed in RAI 2.1-2A(1) and (2) of SER

Section 2.1 related to NSR piping segments that support secondary containment, the applicant

expanded the system boundaries for the auxiliary boiler system. By letter dated May 31, 2005,

the applicant submitted the results of its review of piping, supports, and other components

outside of the secondary containment required to maintain the structural integrity of the

secondary containment that are within the scope of license renewal in accordance with the

requirements of 10 CFR 54.4(a)(2). In the enclosure to the letter the applicant stated that piping
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was added to scope. The component types do not differ from those listed in LRA Table 2.3.3.1;

therefore, no changes to the auxiliary boiler system portion of the LRA are required.

The staff reviewed the NSR piping segments and found the expanded scope of components to

be acceptable, because the applicant had adequately included NSR components with the

configurations that meet the scoping criterion of 10 CFR 54.4(a)(2) for the cases where NSR

piping or components are directly connected to SR piping or components.

2.3.3.1.3 Conclusion

The staff reviewed the LRA to determine whether any SSCs that should be within the scope of

license renewal had not been 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 had not been 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

had adequately identified the auxiliary boiler system components that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and the auxiliary boiler system components

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

2.3.3.2 Fuel Oil System

2.3.3.2.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.2, the applicant described the fuel oil system. The fuel oil system is a

plant-shared system; two large storage tanks are provided for the entire plant. Pumps transfer

fuel oil to the auxiliary boilers and storage tanks for the various diesel-driven engines. The

standby alternating current (AC) power fuel oil system consists of three interconnected storage

tanks for each of the system’s eight diesel generators (DGs). Transfer pumps are provided to

transfer fuel from a 7-day storage tank to the associated DG day tank. These 7-day storage

tanks can provide sufficient fuel for the operation of the DGs during seven continuous days,

following a LOCA. The system is in standby during normal operation and starts automatically,

when required, to supply fuel to any operating DG. The other plant DGs each have a single

storage tank.

The fuel oil system contains SR components that are relied upon to remain functional during,

and following, DBEs. The failure of NSR SSCs in the fuel oil system could prevent the

satisfactory accomplishment of an SR function. In addition, the fuel oil system performs

functions that support fire protection and SBO. 

The intended functions within the scope of license renewal include the following:

 • provides diesel fuel oil to the DG system

 • maintains a 7-day (long term) supply of fuel oil in storage tanks to support the DG

system

 • provides debris protection

 • restricts flow
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 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.3.2, the applicant identified the following fuel oil system component types that

are within the scope of license renewal and subject to an AMR: bolting, fittings, flex hose,

piping, pumps, restricting orifice, stainers, tanks, tubing, and valves.

2.3.3.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.2 and UFSAR Section 8.5.3.4 using the evaluation

methodology described in SER Section 2.3. The staff conducted its review in accordance with

the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 reviewing LRA Section 2.3.3.2, the staff identified areas in which additional information was

necessary to complete the evaluation of the applicant’s scoping and screening results.

Therefore, by letter to the applicant dated August 31, 2004, the staff issued RAIs concerning

the specific issues to determine whether the applicant had properly applied the scoping criteria

of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs

describe the staff’s RAIs and the applicant’s related responses.

In RAI 2.3.3.2-1. the staff identified that components in the DG low level radioactive waste

(LLRW) fuel oil subsystem and the diesel-driven fire pump LLRW fuel oil subsystem had not

been included in the LRA as being within the scope of license renewal and subject to an AMR.

The UFSAR does not describe either of these two subsystems. The staff is unable to determine

if these subsystems have intended functions that would satisfy any of the criteria in

10 CFR 54.4(a). Therefore, the staff requested that the applicant provide the design functions

and associated licensing bases of these portions of the fuel oil system to determine if they can

be excluded from the scope of license renewal.

In its response, by letter dated October 19, 2004, the applicant stated that the two LLRW fuel

oil subsystems provide fuel oil to the diesels to drive pumps that supply backup water to the

ancillary facilities fire protection system. The areas protected by the ancillary facilities fire

protection system are outside the protected area of the plant and are not required for plant

shutdown. 

Based on its review, the staff found the applicant’s response to RAI 2.3.3.2-1 acceptable. The

intended functions of these subsystems as described in the applicant’s response are outside

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

Therefore, the staff’s concern described in RAI 2.3.3.2-1 is resolved.
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In RAI 2.3.3.2-2, the staff identified that a drain valve and associated piping and fittings on the

diesel fuel tank for the diesel-driven fire pump had not been included in the LRA as being within

the scope of license renewal and subject to an AMR. Failure of this piping could affect the

upstream valve and drain the storage tank. Therefore, the staff requested that the applicant

justify the exclusion of the drain valve and associated piping and fittings from the scope of

license renewal.

In its response, by letter dated October 19, 2004, the applicant stated that none of the piping

shown on the license renewal drawing is SR or seismically qualified; the piping is within the

scope of license renewal for fire protection. Failure of the short section of piping and fittings

downstream of normally closed valve, 0-DRV-703, would not cause the storage tank to drain.

Based on its review, the staff found the applicant’s response to RAI 2.3.3.2-2 acceptable. There

is a normally closed valve within the scope of license renewal upstream of the drain valve in

question; thus, failure of the short section of piping and fittings downstream of this valve would

not affect the intended function of the storage tank. Therefore, the staff’s concern described in

RAI 2.3.3.2-2 is resolved.

2.3.3.2.3 Conclusion

The staff reviewed the LRA and RAI responses described above to determine whether any

SSCs that should be within the scope of license renewal had not been 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 had not been 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 had adequately identified the fuel oil system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the fuel oil system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.3 Residual Heat Removal Service Water System

2.3.3.3.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.3, the applicant described the RHRSW system. The RHRSW system is a

plant-shared system. The system pumps water directly from Wheeler Reservoir through the

RHR heat exchangers and EECW system components and discharges the water back into the

Wheeler Reservoir.

The RHRSW system contains SR components that are relied upon to remain functional during,

and following DBEs. The failure of NSR SSCs in the RHRSW could prevent the satisfactory

accomplishment of an SR function. In addition, the RHRSW performs functions that support fire

protection, EQ, and SBO.

The intended functions within the scope of license renewal include the following:

 • provides cooling water to the RHR system heat exchangers

 • provides cooling water to the EECW system upon start of the RHRSW pumps, given

EECW valve position interlock signals
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 • provides a secondary containment boundary

 • provides sump pump capability for RHRSW pump compartments

 • provides debris protection

 • restricts flow

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.3.3, the applicant identified the following RHRSW system component types

that are within the scope of license renewal and subject to an AMR: bolting, fittings, piping,

pumps, restricting orifice, strainers, tubing, and valves.

2.3.3.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.3 and UFSAR Sections 4.8, 5.3, 7.12.4, 7.18, 10.9,

10.10, 11.6, F.7.7, F.7.15, and F.7.16 using the evaluation methodology described in SER

Section 2.3. The staff conducted its review in accordance with the guidance described in

SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 reviewing LRA Section 2.3.3.3, the staff identified an area in which additional information was

necessary to complete the evaluation of the applicant’s scoping and screening results.

Therefore, by letter to the applicant dated August 31, 2004, the staff issued an RAI concerning

the specific issue to determine whether the applicant had properly applied the scoping criteria of

10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs

describe the staff’s RAI and the applicant’s response.

In RAI 2.3.3.3-1, the staff stated that license renewal drawing 0-47E851-4-LR provides the

drainage flow diagram (identified as system number 40 in the drawing title block). Most of the

piping and valves for system 40 on the drawing are identified with UNIDs; however, the piping

on this drawing is shown in red, but does not identify UNIDs for the piping or pumps. Therefore,

the staff requested the applicant to identify which components on this drawing are part of the

RHRSW system.

In its response, by letter dated October 19, 2004, the applicant stated that the piping and

pumps shown in red on drawing 0-47E851-4-LR are associated with the pumping station and

are part of the RHRSW system (system 23). The pumps are tagged as RHRSW system 23
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components and there are no UNIDs assigned to pipe. These components are part of the

RHRSW and are contained in LRA Table 2.3.3.3.

Based on its review, the staff found the applicant’s response to RAI 2.3.3.3-1 acceptable. It

confirms that the piping and pumps shown in red on the license renewal drawing are part of the

residual heat removal service water system and that the components in question are

appropriately included in LRA Table 2.3.3.3. Therefore, the staff’s concern described in

RAI 2.3.3.3-1 is resolved.

2.3.3.3.3 Conclusion

The staff reviewed the LRA, the accompanying scoping boundary drawing, and RAI response

described above to determine whether any SSCs that should be within the scope of license

renewal had not been 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 had not been 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 had

adequately identified the RHRSW system components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and the RHRSW system components that are subject

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

2.3.3.4 Raw Cooling Water System

2.3.3.4.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.4, the applicant described the raw cooling water (RCW) system. The RCW

system cools plant components (including components in the reactor building) during normal

operations. The Unit 1 and Unit 2 RCW systems share pump suction and discharge headers

and seven RCW pumps. The separate, Unit 3 RCW system has five pumps that have a

separate suction header, but share a common discharge header with Units 1 and 2. Three

pumps per unit are normally required. The RCW system has interfaces with the EECW system,

which is normally inservice. The RCW pumps are located in the turbine building and are

supplied from the condenser circulating water system.

The RCW system contains SR components that are relied upon to remain functional during,

and following, DBEs. The failure of NSR SSCs in the RCW system could prevent the

satisfactory accomplishment of an SR function. 

The intended functions within the scope of license renewal include the following:

 • provides a secondary containment boundary

 • provides pressure boundary integrity for the EECW system

 • provides a flow path through control room chillers A and B for Units 1 and 2 only

 • restricts flow

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support
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In LRA Table 2.3.3.4, the applicant identified the following RCW system component types that

are within the scope of license renewal and subject to an AMR: bolting, expansion joint, fittings,

flex hose, piping, pumps, strainers, tubing and valves.

2.3.3.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.4 and UFSAR Sections 5.3, 10.7, and F.6.5 using the

evaluation methodology described in SER Section 2.3. The staff conducted its review in

accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 reviewing LRA Section 2.3.3.4, the staff identified an area in which additional information was

necessary to complete the evaluation of the applicant’s scoping and screening results.

Therefore, by letter to the applicant dated August 31, 2004, the staff issued an RAI concerning

the specific issue to determine whether the applicant had properly applied the scoping criteria of

10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs

describe the staff’s RAI and the applicant’s response.

In RAI 2.3.3.4-1, the staff identified that water chillers 1A and 1B on license renewal drawing

1-47E844-2-LR are not subject to an AMR, and heat exchangers are not listed as a component

type in LRA Table 2.3.3.4. The shell of the chillers serves as the pressure boundary and

structural support for the attached raw cooling water piping which is subject to an AMR.

Therefore, the staff requested that the applicant justify the exclusion of these chillers from being

subject to an AMR.

In its response, by letter dated October 19, 2004, the applicant stated that the piping on the

shell side of water chillers 1A and 1B had been removed to show these chillers abandoned in

place on drawing 1-47E844-1-LR. Since the raw water piping has been removed, the chillers no

longer perform a pressure boundary or structural support function. The applicant further stated

that the drawing has been revised and will be sent to the staff as part of the annual update.

Based on its review, the staff found the applicant’s response to RAI 2.3.3.4-1 acceptable. Water

chillers 1A and 1B no longer perform an intended function in accordance with the requirements

of 10 CFR 54.4(a) and are outside the scope of license renewal. Therefore, the staff’s concern

described in RAI 2.3.3.4-1 is resolved.

In order to resolve the 10 CFR 54.4(a)(2) issues discussed in RAI 2.1-2A(1) and (2) of SER

Section 2.1 related to NSR piping segments that support secondary containment, the applicant

expanded the system boundaries for the raw cooling water system. By letter dated May 31,

2005, the applicant submitted the results of its review of piping, supports, and other

components outside of the secondary containment required to maintain the structural integrity

of the secondary containment that are within the scope of license renewal in accordance with
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the requirements of 10 CFR 54.4(a)(2). In the enclosure to the letter the applicant stated that

piping was added to scope. The component types do not differ from those listed in LRA

Table 2.3.3.4; therefore, no changes to the raw cooling water system portion of the LRA are

required.

The staff reviewed the NSR piping segments and found the expanded scope of components to

be acceptable, because the applicant had adequately included NSR components with the

configurations that meet the scoping criterion of 10 CFR 54.4(a)(2) for the cases where NSR

piping or components are directly connected to SR piping or components.

2.3.3.4.3 Conclusion

The staff reviewed the LRA and RAI responses described above to determine whether any

SSCs that should be within the scope of license renewal had not been 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 had not been 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 had adequately identified the RCW system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the RCW system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.5 Raw 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 raw service water (RSW) system. The RSW

system furnishes water for yard-watering and the cooling of miscellaneous plant equipment that

requires only small quantities of cooling water. The system also functions as a ‘keep-fill’ system

for the fire protection system. The RSW system is supplied from river water from the condenser

circulating water inlet conduit, through a strainer, and to the main RCW pump suction header

for each unit. Units 1 and 2 each have one RSW pump; Unit 3 has two RSW pumps. Therefore,

four pumps supply the common plant system. Two 10,000-gallon storage tanks are located on

top of the reactor building. These tanks pressurize the high pressure fire protection (HPFP)

system header.

The RSW system contains SR components that are relied upon to remain functional during,

and following, DBEs. In addition, the RSW system performs functions that support fire

protection.

The intended functions within the scope of license renewal include the following:

 • provides a secondary containment boundary

 • provides a keep-fill system for the fire protection system

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support
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In LRA Table 2.3.3.5, the applicant identified the following RSW system component types that

are within the scope of license renewal and subject to an AMR: bolting, fittings, piping, tanks,

tubing, and valves.

2.3.3.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.5 and UFSAR Sections 5.3, 10.8, 10.10, and F.6.6 using

the evaluation methodology described in SER Section 2.3. The staff conducted its review in

accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 reviewing LRA Section 2.3.3.5, the staff identified an area in which additional information was

necessary to complete the evaluation of the applicant’s scoping and screening results.

Therefore, by letter to the applicant dated August 31, 2004, the staff issued an RAI concerning

the specific issue to determine whether the applicant had properly applied the scoping criteria of

10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs

describe the staff’s RAI and the applicant’s related response.

In RAI 2.3.3.5-1, the staff identified that the raw service water components upstream of valve

1-25-703 are not included in the LRA as being within the scope of license renewal and subject

to an AMR. Similar arrangements exist for Units 2 and 3. This normally open, hand-operated

valve is located at the interface between the discharge of RSW pump 1A and the fire service

system. Therefore, the staff requested that the applicant provide the basis for using a normally

open, hand-operated valve as a pressure boundary from the upstream RSW system piping and

components. The staff also requested that the applicant justify the exclusion of these

components from the scope of license renewal. 

In its response, by letter dated October 19, 2004, the applicant stated that the fire protection

capability to control and extinguish fires is not dependent on the operability of the raw service

water pumps. Therefore, these pumps are not in scope, and any piping and valves associated

with the RSW system are also not included within the scope of license renewal. Additionally, the

applicant stated that valve 1-25-703 is the first isolation valve off the 12-inch fire protection

headers tie-in to the RSW pumps, and is within the scope of license renewal as it provides an

isolable point between the RSW and fire protection systems.

Based on its review, the staff found the applicant’s response to RAI 2.3.3.5-1 acceptable. The

RSW pumps and associated components do not perform an intended function in accordance

with the requirements of 10 CFR 54.4(a), and are, therefore, outside the scope of license

renewal. Therefore, the staff’s concern described in RAI 2.3.3.5-1 is resolved.
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2.3.3.5.3 Conclusion

The staff reviewed the LRA and RAI response described above to determine whether any SSCs

that should be within the scope of license renewal had not been 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 had not been 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 had adequately identified the RSW system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the RSW system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.6 High Pressure 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 HPFP system. The HPFP system supplies

water for fixed water spray, pre-action sprinkler, and aqueous foam systems for selected

equipment and areas in the control building, reactor buildings, turbine building, intake pumping

station, hydrogen trailer port, transformer yard, DG buildings, and service buildings.

The HPFP system contains SR components that are relied upon to remain functional during,

and following, DBEs. The failure of NSR SSCs in the HPFP system could prevent the

satisfactory accomplishment of an SR function. In addition, the HPFP system performs

functions that support fire protection.

The intended functions within the scope of license renewal include the following:

 • supports a secondary containment function

 • provides automatic fire protection for known hazardous areas where it is practical

 • provides adequate warning of a fire in hazardous areas where automatic protection is

not feasible to provide adequate manually-actuated fire protection systems for the entire

plant and yard areas (i.e., hose stations, hydrants, etc.)

 • ensures the maintenance of divisional integrity of SR systems to the extent that the

capability for safe shutdown of the reactors is assured during and after a fire

 • provides debris protection

 • provides mechanical closure

 • provides pressure boundary

 • provides spray pattern

 • provides structural support

In LRA Table 2.3.3.6, the applicant identified the following HPFP system component types that

are within the scope of license renewal and subject to an AMR: bolting, fan housing, fire

hydrants, fire hose stations, fittings, flexible connectors, heaters, heat exchangers, piping,

pumps, restricting orifice, silencer, sprinkler heads, strainers, tanks, tubing, and valves.
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2.3.3.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.6 and UFSAR Sections 10.11 and F.6.9 using the

evaluation methodology described in SER Section 2.3. The staff conducted its review in

accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). In addition, the staff also reviewed the BFN Fire Protection

Report (FPR) (Volumes 1 and 2). This report is referenced directly in the BFN fire protection

CLB and summarizes the fire protection program and commitments to 10 CFR 50.48 using the

guidance of Appendix A to Branch Technical Position (BTP) Auxiliary and Power Conversion

Systems Branch (APCSB) 9.5-1. 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 reviewing LRA Section 2.3.3.6, the staff identified areas in which additional information was

necessary to complete the evaluation of the applicant’s scoping and screening results.

Therefore, by letter to the applicant dated August 23, 2004, the staff issued RAIs concerning

the specific issues to determine whether the applicant had properly applied the scoping criteria

of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs

describe the staff’s RAIs and the applicant’s related responses and staff evaluation.

In RAI 2.3.3.6-1, the staff stated that the system description of the HPFP system in LRA

Section 2.3.3.6 includes fixed water spray systems. Such systems typically utilize water spray

nozzles. The staff identified that LRA Table 2.3.3.6 does not include water spray nozzles as a

component subject to an AMR. Therefore, the staff requested that the applicant indicate

whether the fixed water spray systems use spray nozzles other than the sprinkler heads. If so,

staff stated that the nozzles, which are intended to support the system function, are passive

and long-lived and should be subject to an AMR.

In its response, by letter dated September 30, 2004, the applicant stated that fire protection

spray nozzles (including spray nozzles attached to fire hoses) had been included in component

type “sprinkler heads” in LRA Table 2.3.3.6. 

Based on its review, the staff found the applicant’s response to RAI 2.3.3.6-1 acceptable. The

components in question are included in scope and are subject to an AMR. Therefore, the staff’s

concern described in RAI 2.3.3.6-1 is resolved.

In RAI 2.3.3.6-2, the staff stated that the system description of the HPFP system in LRA

Section 2.3.3.6 describes detection and alarm devices that automatically initiate the system or

prompt manual fire fighting. The staff stated that these devices are not identified on the license

renewal drawings, nor are they discussed in the fire protection program. Therefore, the staff

requested that the applicant explain what these devices are and whether they are subject to an

AMR.
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In its response, by letter dated September 30, 2004, the applicant stated that the alarm and

detection devices do not perform a pressure boundary function, are active components, and are

evaluated as electrical commodities. 

Based on its review, the staff found the applicant’s response to RAI 2.3.3.6-2 acceptable. The

components in question are electrical, not mechanical, and are active, and therefore are not

subject to an AMR. Therefore, the staff’s concern described in RAI 2.3.3.6-2 is resolved.

In RAI 2.3.3.6-3, the staff stated that the LRA shows that the boundary of the HPFP system is

the service building wall. The staff stated that the boundary shown is not at an isolated pressure

boundary (e.g., a valve or blank flange). Therefore, the staff requested that the applicant justify

the exclusion of the service building portions of the system from the scope of license renewal.

In its response, by letter dated September 30, 2004, the applicant stated that the boundary

does not end at the service building wall but continues on license renewal drawing

1-47E850-2-LR. BFN drawings depict continuation to other drawings with drawing coordinate

flags. For clarification, the reference to drawing coordinate flag 1-47E850-2 G6 should have

been colored red on license renewal drawing 1-47E850-1-LR. The boundary should end at the

isolation valve 0-26-907 on drawing 1-47E850-2-LR. The boundary extends to an appropriate

isolation valve. 

Based on its review, the staff found the applicant’s response to RAI 2.3.3.6-3 acceptable. The

boundary extends to an appropriate isolation valve. Therefore, the staff’s concern described in

RAI 2.3.3.6-3 is resolved.

In RAI 2.3.3.6-4, the staff stated that the LRA identifies a water curtain around the equipment

hatch at elevation 565 feet. Table 9.3.11.B in Volume 1 of the FPR lists water curtains for the

RHR pump room equipment hatches at elevation 541 feet. The staff identified that the license

renewal drawings do not show anything on elevation 541 feet. Therefore, the staff requested

that the applicant clarify that the water curtain protection for the RHR pump room equipment

hatches are within the scope of license renewal, and identify where they are located on the

license renewal drawings.

In its response, by letter, dated September 30, 2004, the applicant stated that the water

curtains at BFN are typically provided to protect floor openings and include closely spaced

sprinklers and draft stops located around the opening underneath the floor slab. In Unit 3

reactor building elevation 565 feet, as shown on license renewal drawing 3-47E850-5, water

curtains are provided at the following six different locations:

 (1) equipment hatch in floor opening above (between floor elevation 565 feet and 593 feet) 

 (2) stair #22 floor opening above (between floor elevation 565 feet and 593 feet) 

 (3) east RHRSW heat exchanger (HX) room portal (door opening)

 (4) west RHRSW HX room portal (door opening) 

 (5) east RHRSW HX room floor opening below (between elevation 541 feet and 565 feet) 

 (6) west RHRSW HX room floor opening below (between elevation 541 feet and 565 feet)
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The water curtains (5 and 6) in the RHRSW HX room floor opening are located below elevation

565 feet floor slab to protect the opening from the fire effects of elevation 541 feet. These two

water curtains are the ones described in Table 9.3.11.B, Volume 1 of the FPR as the water

curtains for the RHR pump room equipment hatches at elevation 541 feet. These water curtains

are within the scope of license renewal. 

Based on its review, the staff found the applicant’s response to RAI 2.3.3.6-4 acceptable. The

water curtains in question were verified by the applicant to be within the scope of license

renewal. Therefore, the staff’s concern described in RAI 2.3.3.6-4 is resolved.

In reviewing the FPR, the staff identified the need for additional information related to the fire

water supply systems and fire protection coating. In a letter dated August 23, 2004, the staff

asked the applicant to clarify information contained in the FPR Volume 1, Sections 4.4.1.A and

4.4.5. The following paragraphs describe the staff’s RAIs and the applicant’s related responses.

In RAI 4.4.1-1, the staff stated that FPR Section 4.4.1.A addresses a separate water supply

system, including tank and pumps, which does not appear in the LRA or boundary drawings. In

RAI 4.4.1-1, the staff requested the applicant to verify whether these system components are

within the scope of license renewal and provide the justification if they are not.

In its response, by letter dated September 30, 2004, the applicant stated that the separate

water supply ID referring to the outside loop is not within the scope of license renewal, since it

is servicing NSR areas of the plant that provide equipment/property protection and meet the

Nuclear Electric Insurance Limited (NEIL) requirements. Therefore, they do not meet any

criteria of 10 CFR 54.4. 

Based on it review, the staff found the applicant’s response to RAI 4.4.1-1 acceptable. Even

though the separate water supply can be connected to the HPFP system as a backup identified

in plant procedures, it is not connected by fixed piping and valves. Therefore, the staff

concurred that the separate water supply is not within the scope of license renewal, and the

staff concern described in RAI 4.4.1-1 is resolved. 

In RAI 4.4.5-1, the staff stated that FPR Section 4.4.5 states that “Flamemastic” was applied to

cables that did not meet Institute of Electrical and Electronics Engineers (IEEE)-383 flame test

requirements. Inspection Testing and Maintenance of this is not referenced in the FPR. No

reference is made to it in the LRA, either under the Fire Protection Program, LRA

Section B.2.1.23, or in the electrical or structural programs. Therefore, the staff requested that

the applicant supply the AMR and AMP that are applicable to the Flamemastic coating. The

staff also asked the applicant to include program documents and procedures credited for

managing the loss of material for Flamemastic coating.

In its response, by letter dated September 30, 2004, the applicant stated that Flamemastic is

primarily used as a flame retardant on non-IEEE-383 qualified cables. This commitment

originated as part of the post-Fire Recovery Plan. As stated in the FPR, current practice is to

use cables that meet the IEEE-383 requirements for flame retardant and, therefore,

Flamemastic is not applied to these cables. Since Flamemastic is not considered a fire stop or a

fire-resistive barrier, the 10 CFR Part 50, Appendix R, safe-shutdown analysis does not take

credit for it. Some cable tray penetration seal assemblies, however, use a coating of

Flamemastic on the fiber board and cables around the opening to meet the fire barrier function.
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Materials listed in LRA Sections 3.5.2.1.2 and 3.5.2.1.5 should include Flamemastic coatings,

when used in a qualified fire barrier configuration, to include both sides of the reactor

building/turbine building wall cable tray penetrations. 

By letter dated January 25, 2005, applicant stated that the aging effects requiring management

were incorrectly assigned to Flamemastic when used in the qualified fire barrier configuration.

At BFN, fire barrier penetration seal materials and Flamemastic coatings on exposed cables in

open trays are exposed to an inside air environment and, therefore, have no aging effects and

require no AMP. 

The applicant further stated that, based on the above discussion, aging effects were also

incorrectly assigned to fire barrier materials Thermolag, Elastomers, and Gypsum. LRA

Section 3.5 will be revised to update the aging effects requiring management for these fire

barrier materials.

Based on review of the applicant’s response, as supplemented by letter dated January 25,

2005, the staff concurred that the proposed modifications to the LRA are appropriate, because

Flamemastic coating on exposed cable trays are exposed to an inside air environment and

require no AMR and AMP but are included within the scope of license renewal. Therefore, the

staff’s concern described in RAI 4.4.5-1 is resolved.

In addition, the staff, during its audit review held during the week of July 21 - 25, 2004,

discussed the following issue for the Fire Protection Program.

In its letter, dated October 28, 2004, the applicant stated that Procedure FP-0-041-INS008,

Process Computer Room Halon 1301 System Functional Test, identifies a Halon 1301 total

flooding system on elevation 539 feet of the Control Bay (room 594.0-C1). No reference to

Halon systems appears in the LRA (scoping, screening, AMR or AMP.) The applicant was

requested to justify the exclusion of this system from license renewal.

The applicant also stated in its response that the Halon system does not provide fire protection

for any equipment for plant shutdown but is installed to provide equipment/property protection

and meet NEIL requirements. Therefore, this system does not meet any of the criteria of

10 CFR 54.4. Based upon its review, the staff agreed that the Halon 1301 systems identified in

FP-0-041-INS008 are not part of the plant licensing basis and, therefore, are not within the

scope of license renewal. The staff concern described above is resolved. 

2.3.3.6.3 Conclusion

The staff reviewed the LRA and RAI responses described above to determine whether any

SSCs that should be within the scope of license renewal had not been 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 had not been 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 had adequately identified the HPFP system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the HPFP system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
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2.3.3.7 Potable Water System

2.3.3.7.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.7, the applicant described the potable water system. The potable water

system supplies potable water for use in the plumbing systems and is supplied by the city of

Athens, AL. Potable water is supplied to various areas in the plant. Backflow preventers are

installed at each interface between the potable water system and the separate connecting

systems, in order to protect the potable water supply from possible contamination due to

backflow. The potable water system is a plant-shared system.

The potable water system contains SR components that are relied upon to remain functional

during, and following, DBEs. The failure of NSR SSCs in the potable water system could

prevent the satisfactory accomplishment of an SR function. 

The intended functions within the scope of license renewal include the following:

 • provides a secondary containment boundary

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.3.7, the applicant identified the following potable water system component

types that are within the scope of license renewal and subject to an AMR: bolting, fittings,

piping, tubing, and valves.

2.3.3.7.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.7 and UFSAR Sections 5.3, 10.15, and F.6.11 using the

evaluation methodology described in SER Section 2.3. The staff conducted its review in

accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 order to resolve the 10 CFR 54.4(a)(2) issues discussed in RAI 2.1-2A(1) and (2) of SER

Section 2.1 related to NSR piping segments that support secondary containment, the applicant

expanded the system boundaries for the potable water system. By letter dated May 31, 2005,

the applicant submitted the results of its review of piping, supports, and other components

outside of the secondary containment required to maintain the structural integrity of the

secondary containment that are within the scope of license renewal in accordance with the

requirements of 10 CFR 54.4(a)(2). In the enclosure to the letter the applicant stated that new
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component types, valves and tanks, were added to the scope as referenced in new LRA

Tables 2.3.3.7 and 3.3.2.7.

The staff reviewed the NSR piping segments and found the expanded scope of components to

be acceptable, because the applicant had adequately included NSR components with the

configurations that meet the scoping criterion of 10 CFR 54.4(a)(2) for the cases where NSR

piping or components are directly connected to SR piping or components.

2.3.3.7.3 Conclusion

The staff reviewed the LRA and RAI response to determine whether any SSCs that should be

within the scope of license renewal had not been 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 had not been 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 had adequately identified the potable water system components that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and the potable water system

components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.8 Ventilation System

2.3.3.8.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.8, the applicant described the ventilation system. The ventilation system

contains subsystems that provide ventilation and heating for various plant buildings, including

the radioactive waste building and the DG buildings. The ventilation system does not include

the HVAC systems or the reactor building ventilation systems. These systems are discussed in

SER Section 2.3.3.9. The ventilation system is a plant-shared system. 

The radioactive waste building ventilation system consists of two 50-percent capacity

supply fans that filter air to central areas on the various plant floor levels. The ventilation

systems for the DG buildings are designed to maintain the required environmental conditions

for SR equipment located in the Unit 1, 2, and 3 DG buildings.

The ventilation system contains SR components that are relied upon to remain functional

during, and following, DBEs. In addition, the ventilation system performs functions that support

fire protection and SBO.

The intended functions within the scope of license renewal include the following:

 • provides ventilation to the Unit 1, 2, and 3 DG buildings

 • provides ventilation to the 250 volt (V) Battery Room 3EB in the Unit 3 DG building to

prevent the buildup of hydrogen gas during battery charging

 • provides for secondary containment integrity (passive)

 • provides debris protection

 • provides fire barrier
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 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.3.8, the applicant identified the following ventilation system component types

that are within the scope of license renewal and subject to an AMR: bolting, ductwork, fire

dampers, and fittings.

2.3.3.8.2 Staff Evaluation

The staff reviewed LRA Sections 2.3.3.8 and BFN Units 1, 2, and 3 UFSAR Sections 5.3 and

10.12, and F.7.11 using the evaluation methodology described in SER Section 2.3. The staff

conducted its review in accordance with the guidance described in SRP-LR Section 2.3.

In conducting the review, the staff reviewed the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 reviewing LRA Section 2.3.3.8, the staff identified an area in which additional information was

necessary to complete the review of the applicant’s scoping and screening results. Therefore,

by the letter dated October 8, 2004, the staff issued an RAI concerning the specific issues to

determine whether the applicant had properly applied the scoping criteria of 10 CFR 54.4(a)

and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs describe the staff’s

RAI and the applicant’s related responses.

In RAI 2.3.3.8-1, the staff requested that the applicant clarify whether all the system

components such as, but not limited to, damper housings including fire damper housings, fan

housings, air intake and exhaust structures including screens, supply and exhaust grills, 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, by letter dated November 3, 2004, and supplemented by a letter dated

December 3, 2004, the applicant stated that (1) the damper housings and fan housings are

included in component type “ductwork” in LRA Table 2.3.3.8, (2) fire damper housings are

included in component type “fire dampers” in LRA Table 2.3.3.8, (3) screens associated with

the exhaust plenum in the Units 1 & 2 DG building and the Unit 3 DG building are included in

component type “ductwork” in LRA Table 2.3.3.8, and (4) intake/exhaust plenums associated

with the DG buildings are considered part of the structure and are contained in LRA

Table 2.4.3.1 and LRA Table 3.5.2.5. LRA Section 2.3.5, “Notes Associated with the

Section 2.3 Tables,” “Component Types” are revised to reflect these components and,

therefore, are part of LRA Table 2.3.3.8, “ventilation system” and LRA Table 3.3.2.8,

“Ventilation System-Summary of Aging Management Evaluation.”
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Based on its review, the staff found the applicant’s response to RAI 2.3.3.8-1 acceptable. The

applicant clarified that all applicable system components consisting of damper housings

including fire damper housings, fan housings, air intake and exhaust structures including

screens and all other applicable components of the system are within the scope of license

renewal, and subject to an AMR for the ventilation system. Supply and exhaust grills do not

perform any SR function, therefore, are excluded from the scope of license renewal. Therefore,

the staff’s concern described in RAI 2.3.3.8-1 for those “Component Types” in LRA

Tables 2.3.3.8 and 3.3.2.8 is resolved.

2.3.3.8.3 Conclusion

The staff reviewed the LRA and RAI response described above to determine whether any SSCs

that should be within the scope of license renewal had not been 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 had not been 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 had adequately identified the ventilation system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the ventilation system components that are subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.3.3.9 Heating, Ventilation, and Air Conditioning System

2.3.3.9.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.9, the applicant described the HVAC system. The HVAC subsystems

provide air-conditioned ventilation for various plant areas. The various HVAC subsystems

provide environmental control, ventilation, and cooling. Ventilation and cooling is provided so

that the temperatures of the control bay and shutdown electrical board rooms (including those

in the Unit 3 DG building) are maintained within acceptable limits for the operation of

instruments and other equipment during accidents and events. Ventilation is also provided to

the battery room to prevent the buildup of explosive gases. In addition, the HVAC subsystems

provide for the cooling of various electrical equipment rooms (e.g., computer and

communications rooms) so that their temperatures are maintained within acceptable limits for

the operation of instruments and other equipment.

The HVAC system contains SR components that are relied upon to remain functional during,

and following, DBEs. The failure of NSR SSCs in the HVAC system could prevent the

satisfactory accomplishment of an SR function. In addition, the HVAC system performs

functions that support fire protection, EQ, and SBO.

The intended functions within the scope of license renewal include the following:

 • isolates supply ducts and supplies pressurized filtered outdoor air to main control room

on primary containment isolation system group six signal or radiation monitoring system

initiation signal

 • provides ventilation to cable spreading rooms and control bay mechanical equipment

rooms
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 • recirculates cool air to the reactor building board rooms

 • provides ventilation and air conditioning to the board rooms of the Unit 3 DG buildings

and ventilation to the battery rooms

 • provides recirculation air conditioning to control rooms and auxiliary instrument rooms

 • provides manual lineup of HVAC equipment with total loss of control air

 • provides a secondary containment boundary

 • provides debris protection

 • provides fire barrier

 • provides for heat transfer

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.3.9, the applicant identified the following HVAC system component types that

are within the scope of license renewal and subject to an AMR: bolting, ductwork, fire dampers,

fittings, flexible connectors, heat exchangers, heaters, piping, pumps, refrigerant compressor,

strainers, tanks, tubing, and valves.

2.3.3.9.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.9 and UFSAR Sections 10.12 and F.7.11 using the

evaluation methodology described in SER Section 2.3. The staff conducted its review in

accordance with the guidance described in SRP-LR Section 2.3.

In conducting the review, the staff reviewed the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 reviewing LRA Section 2.3.3.9, the staff identified an area in which additional information was

necessary to complete the review of the applicant’s scoping and screening results. Therefore,

by the letter dated October 8, 2004, the staff issued an RAI concerning the specific issues to

determine whether the applicant had properly applied the scoping criteria of 10 CFR 54.4(a)

and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs describe the staff’s

RAI and the applicant’s related responses.

In RAI 2.3.3.9-1, the staff requested that the applicant clarify whether all the system

components such as, but not limited to, fan housings, filter housings, cooling coil housings,

damper housings including fire damper housings, metal lath screens, valve bodies, supply and

return grills, and all other applicable components of the system, including duct sealants, wall

sealants, pressure boundary sealants, screens for intake and exhaust structures, etc., are
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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, by letter dated November 3, 2004, and supplemented by a letter dated

December 3, 2004, the applicant stated the following:

 • Fan housings, filter housings, cooling coil housings, and damper housings are included

in component type “ductwork” in LRA Table 2.3.3.9.

 • Metal lath screens shown on drawings 0-47E865-8-LR and 3-47E865-8-LR are included

in component type “ductwork” in LRA Table 2.3.3.8.

 • Screens and plenums will be included in the component type “ductwork.”

 • LRA Table 3.3.2.9 will be revised to include “outside air (external)” for “ductwork.” A new

row will be added for stainless steel “bolting” category with an outside air environment.

 • Valve bodies are included in component type “valves” in LRA Table 2.3.3.9.

 • Structural sealants such as those required to maintain the control room envelope or

secondary containment are contained in Section 3.5.2.1.2 and in component type

“compression joints and seals” and in component type “caulking and sealants” in LRA

Table 3.5.2.2,

 • Pressure boundary sealants associated with ductwork for HVAC system are included in

component type “ductwork” in LRA Tables 2.3.3.9 and 3.3.2.9, and screens and

plenums are included in the component type “ductwork.” 

The supply and return grilles have 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 are not included in the LRA Tables. LRA Section 2.3.5, “Notes

Associated with the LRA Section 2.3 tables,” “Component Types” is revised to reflect these

components and, therefore, is part of LRA Table 2.3.3.9, “Heating, Ventilation, and Air

Conditioning System,” and LRA Table 3.3.2.9, “Heating, Ventilation, and Air Conditioning

System-Summary of Aging Management Evaluation.”

Based on its review, the staff found the applicant’s response to RAI 2.3.3.9-1 acceptable. The

applicant clarified that all applicable system components consisting of fan housings, filter

housings, cooling coil housings, damper housings, metal lath screens, screens and plenums,

valve bodies, structural sealants to maintain the control room envelope including compression

joints and seals, and pressure boundary sealants associated with ductwork are within the scope

of license renewal, and subject to an AMR for the HVACS and are already included in

“Component Types” in LRA Tables 2.3.3.9 and 3.3.2.9. Therefore, the staff’s concern described

in RAI 2.3.3.9-1 is resolved.

2.3.3.9.3 Conclusion

The staff reviewed the LRA and RAI response described above to determine whether any SSCs

that should be within the scope of license renewal had not been 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 had not been 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 had adequately identified the HVAC system
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components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the HVAC system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.10 Control Air System

2.3.3.10.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.10, the applicant described the control air system. The control air system

provides motive power for numerous plant components during normal operations and

post-accident motive power to the torus vacuum breaker valves. The system also provides

post-accident motive power to the MS isolation valves and the main steam safety relief valves

(MSRVs) for reactor vessel overpressure relief protection and reactor vessel depressurization,

including the ECCS automatic depressurization function.

The control air system contains SR components that are relied upon to remain functional

during, and following, DBEs. The failure of NSR SSCs in the control air system could prevent

the satisfactory accomplishment of an SR function. In addition, the control air system performs

functions that support fire protection, EQ, and SBO.

The intended functions within the scope of license renewal include the following:

 • performs isolation action(s) upon receiving primary containment system (64D) group six

isolation signals

 • provides compressed air to the MS system atmospheric dilution system (ADS) safety

relief valves

 • provides compressed air for closure of the MSIVs

 • provide primary containment boundary

 • provides compressed air to equipment access air lock seals to provide a secondary

containment boundary

 • provides and supports the secondary containment boundary

 • provides for flow path integrity for supply of CAD nitrogen to the torus vacuum breaker

valves

 • provides a flow path for the CAD system to provide nitrogen to MSRVs

 • provides for flow distribution

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.3.10, the applicant identified the following control air system component types

that are within the scope of license renewal and subject to an AMR: bolting, fittings, flexible

connectors, heat exchangers, piping, restricting orifice, tanks, tubing, and valves.
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2.3.3.10.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.10 and UFSAR Sections 5.2.3, 5.3, 10.14, and F.6.3

using the evaluation methodology described in SER Section 2.3. The staff conducted its review

in accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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).

2.3.3.10.3 Conclusion

The staff reviewed the LRA to determine whether any SSCs that should be within the scope of

license renewal had not been 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 had not been 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

had adequately identified the control air system components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and the control air system components that are

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

2.3.3.11 Service Air System

2.3.3.11.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.11, the applicant described the service air system. The service air system

is a plant-shared system and consists of two air compressors that are located in the turbine

building. The system’s primary function is to provide pressurized air to hose connections

throughout the plant yard and to miscellaneous equipment in the standby liquid control (SLC)

system, Amertap condenser tube cleaning system (a subsystem of the condenser circulating

water system), condensate demineralizer air surge system, and the radwaste system.

The service air system contains SR components that are relied upon to remain functional

during, and following, DBEs. 

The intended functions within the scope of license renewal include the following:

 • provides primary and secondary containment boundaries

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support
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In LRA Table 2.3.3.11, the applicant identified the following service air system component types

that are within the scope of license renewal and subject to an AMR: bolting, fittings, piping, and

valves.

2.3.3.11.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.11 and UFSAR Sections 5.2.3, 5.3, 10.14, and F.6.3

using the evaluation methodology described in SER Section 2.3. The staff conducted its review

in accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 order to resolve the 10 CFR 54.4(a)(2) issues discussed in RAI 2.1-2A(1) and (2) of SER

Section 2.1 related to NSR piping segments that support secondary containment, the applicant

expanded the system boundaries for the service air system. By letter dated May 31, 2005, the

applicant submitted the results of its review of piping, supports, and other components outside

of the secondary containment required to maintain the structural integrity of the secondary

containment that are within the scope of license renewal in accordance with the requirements of

10 CFR 54.4(a)(2). In the enclosure to the letter the applicant stated that piping, fittings, and

valves were added to scope. The component types do not differ from those listed in LRA

Table 2.3.3.11; therefore, no changes to the service air system portion of the LRA are required.

The staff reviewed the NSR piping segments and found the expanded scope of components to

be acceptable, because the applicant had adequately included NSR components with the

configurations that meet the scoping criterion of 10 CFR 54.4(a)(2) for the cases where NSR

piping or components are directly connected to SR piping or components.

2.3.3.11.3 Conclusion

The staff reviewed the LRA and RAI response to determine whether any SSCs that should be

within the scope of license renewal had not been 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 had not been 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 had adequately identified the service air system components that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and the service air system

components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
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2.3.3.12 CO2 System

2.3.3.12.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.12, the applicant described the CO2 system. The CO2 system is a fire

suppression system for the DG buildings, turbine building, and control bay spaces that contain

electrical, lubricating oil, or fuel oil components. Units 1 and 2 share a system that includes a

17-ton storage tank. Unit 3 has a separate system with a 6-ton tank. The system is in standby

during normal operation and initiates automatically, as required. When initiated, ventilation

systems that could reduce the effectiveness of the CO2 discharge are isolated. Detection and

alarm devices that automatically initiate the system, or would prompt manual fire firefighting

activities, are also included in the CO2 system. The CO2 system performs functions that support

fire protection.

The intended functions within the scope of license renewal include the following:

 • provides CO2 fire protection for oil and electrical hazards affecting the minimum safe

shutdown system (SSDS) components required to achieve safe shutdown capability

 • provides fire barrier

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.3.12, the applicant identified the following CO2 system component types that

are within the scope of license renewal and subject to an AMR: bolting, ductwork, fire dampers,

fittings, piping, rupture disk, tanks, tubing, and valves.

2.3.3.12.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.12 and UFSAR Sections 10.11 and F.6.9 using the

evaluation methodology described in SER Section 2.3. The staff conducted its review in

accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). In addition, the staff also reviewed BFN FPR volumes 1 and

2. This report is referenced directly in the fire protection CLB and summarizes the Fire

Protection Program and commitments to 10 CFR 50.48 using the guidance of Appendix A to

BTP APCSB 9.5-1. 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 reviewing LRA Section 2.3.3.12, the staff identified areas in which additional information was

necessary to complete the evaluation of the applicant’s scoping and screening results.
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Therefore, by letter to the applicant dated August 23, 2004, the staff issued RAIs concerning

the specific issues to determine whether the applicant had properly applied the scoping criteria

of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs

describe the staff’s RAIs and the applicant’s related responses.

In RAI 2.3.3.12-1, the staff stated that the CO2 system addressed in LRA Section 2.3.3.12

typically requires discharge nozzles to achieve the proper flow rate. The staff identified that the

system description and LRA Table 2.3.3.12 do not include any reference to discharge nozzles.

Therefore, the staff requested the applicant to indicate whether this system includes discharge

nozzles. If so, the staff stated that the nozzles, which perform an intended function for flow

control, are passive and long lived and should be subject to an AMR.

In its response, by letter dated September 30, 2004, the applicant stated that the discharge

nozzles were included within component type “fittings” in Table 2.3.3.12 with an intended

function of pressure boundary and subject to an AMR. 

Based on the response, the staff concurred that the nozzles are within the scope of license

renewal and subject to an AMR, but disagreed that the intended function is pressure boundary.

The nozzles contain open orifices and serve a flow control function rather than a pressure

boundary. The staff reviewed plant procedures 0-SI-4.11.D.1.b, 1/2-SI-4.11.D.1.b, and

3-SI-4.11.D.1.b for CO2 system functional testing and found the nozzles are adequately

addressed in the fire protection AMP. Therefore, the staff concern described in RAI 2.3.3.12-1

is resolved.

In RAI 2.3.3.12-2, the staff stated that the system description of the CO2 system in LRA

Section 2.3.3.12 addresses detection and alarm devices that automatically initiate the system or

prompt manual fire fighting. The staff stated that these devices are not identified on the license

renewal drawings, nor are they discussed in the Fire Protection Program. Therefore, the staff

requested that the applicant explain what these devices are and whether they are subject to an

AMR.

In its response, by letter dated September 30, 2004, the applicant stated that the CO2 system

fire protection detection and alarm devices do not form a pressure boundary and are active

components and evaluated as electrical commodities. 

Based on its review, the staff found the applicant’s response to RAI 2.3.3.12-2 acceptable. The

components in question are electrical, not mechanical, and are therefore active and not subject

to an AMR. Therefore, the staff’s concern described in RAI 2.3.3.12-2 is resolved.

2.3.3.12.3 Conclusion

The staff reviewed the LRA and RAI responses described above to determine whether any

SSCs that should be within the scope of license renewal had not been 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 had not been 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 had adequately identified the CO2 system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the CO2 system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
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2.3.3.13 Station Drainage System

2.3.3.13.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.13, the applicant described the station drainage system. The station

drainage system is a plant-shared system that collects, processes, stores, and disposes of

non-radioactive liquid waste. Portions of the piping within the system penetrate the secondary

containment.

The station drainage system contains SR components that are relied upon to remain functional

during, and following, DBEs. The failure of NSR SSCs in the station drainage system could

prevent the satisfactory accomplishment of an SR function. 

The intended functions within the scope of license renewal include the following:

 • provides a secondary containment boundary

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.3.13, the applicant identified the following station drainage system component

types that are within the scope of license renewal and subject to an AMR: bolting, fittings,

piping, and valves.

2.3.3.13.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.13 and UFSAR Sections 5.3 and 10.16 using the

evaluation methodology described in SER Section 2.3. The staff conducted its review in

accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 reviewing LRA Section 2.3.3.13, the staff identified an area in which additional information

was necessary to complete the evaluation of the applicant’s scoping and screening results.

Therefore, by letter to the applicant dated August 31, 2004, the staff issued an RAI concerning

the specific issue to determine whether the applicant had properly applied the scoping criteria of

10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs

describe the staff’s RAI and the applicant’s related response.

In RAI 2.3.3.13-1, the staff identified a 3-inch roof drain (at roof elevation 667 feet on license

renewal drawing 0-47E851-1-LR,) that is not within the scope of license renewal and subject to

an AMR. This drain provides a pressure boundary function between the standby gas treatment
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system and the off-gas system; thus it should be within the scope of license renewal. The staff

noted that a 4-inch roof drain on the same drawing is shown as being subject to an AMR.

Therefore, the staff requested that the applicant justify the exclusion of the 3-inch roof drain

from the scope of license renewal and from being subject to an AMR.

In its response, by letter dated October 19, 2004, the applicant stated that the 3-inch roof drain

should have been colored in red on drawing 0-47E851-1-LR, since it is within the scope of

license renewal as part of the component type “fittings” in LRA Table 2.3.3.13 and subject to an

AMR. The applicant further stated that drawing 0-47E851-1-LR has been revised to show the

3-inch roof drain highlighted in red and will be resent as part of the annual update.

Based on its review, the staff found the applicant’s response to RAI 2.3.3.13-1 acceptable. It

concurs that the 3-inch roof drain should be within the scope of license renewal and the drain

included in LRA Table 2.3.3.13 as a component type subject to an AMR. Therefore, the staff’s

concern described in RAI 2.3.3.13-1 is resolved.

In order to resolve the 10 CFR 54.4(a)(2) issues discussed in RAI 2.1-2A(1) and (2) of SER

Section 2.1 related to NSR piping segments that support secondary containment, the applicant

expanded the system boundaries for the station drainage system. By letter dated May 31, 2005,

the applicant submitted the results of its review of piping, supports, and other components

outside of the secondary containment required to maintain the structural integrity of the

secondary containment that are within the scope of license renewal in accordance with the

requirements of 10 CFR 54.4(a)(2). In the enclosure to the letter the applicant stated that

piping, fittings, and check valves were added to scope. The component types do not differ from

those listed in LRA Table 2.3.3.13; therefore, no changes to the station drainage system portion

of the LRA are required.

The staff reviewed the NSR piping segments and found the expanded scope of components to

be acceptable, because the applicant had adequately included NSR components with the

configurations that meet the scoping criterion of 10 CFR 54.4(a)(2) for the cases where NSR

piping or components are directly connected to SR piping or components.

2.3.3.13.3 Conclusion

The staff reviewed the LRA, the accompanying scoping boundary drawing, and RAI responses

described above to determine whether any SSCs that should be within the scope of license

renewal had not been 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 had not been 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 had

adequately identified the station drainage system components that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and the station drainage 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 Sampling and Water Quality System

2.3.3.14.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.14, the applicant described the sampling and water quality system. The

sampling and water quality system provides the capability to obtain representative samples for

testing. The data are used to evaluate the performance of the plant, equipment, and systems

during normal plant operations. Using a post-accident sample subsystem, representative

samples of reactor coolant, torus liquid, drywell atmosphere, torus atmosphere, and secondary

containment atmosphere can be obtained after a LOCA to guide post-LOCA actions regarding

Units 2 and 3. Portions of the system are credited in analyses for MSIV alternate leakage

treatment.

The sampling and water quality system contains SR components that are relied upon to remain

functional during, and following, DBEs. The failure of NSR SSCs in the sampling and water

quality system could prevent the satisfactory accomplishment of an SR function. In addition, the

sampling and water quality system performs functions that support fire protection, EQ, and

SBO.

The intended functions within the scope of license renewal include the following:

 • provides RCPB

 • provides primary and secondary containment boundaries

 • maintains residual heat removal service water system pressure boundary integrity

 • provides a pressure boundary of the sampling and water quality system components

connected to the control air system that must maintain a pressure boundary in order to

supply the CAD and MSRVs

 • establishes MSIV leakage pathway to the condenser

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.3.14, the applicant identified the following sampling and water quality system

component types that are within the scope of license renewal and subject to an AMR: bolting,

fittings, RCPB fittings, flexible connectors, heat exchangers, piping, RCPB piping, pumps,

strainers, tanks, tubing, valves, and RCPB valves.

2.3.3.14.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.14 and UFSAR Sections 5.2.3, 5.3, 10.17, and 10.21

using the evaluation methodology described in SER Section 2.3. The staff conducted its review

in accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had
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not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 reviewing LRA Section 2.3.3.14, the staff identified an area in which additional information

was necessary to complete the evaluation of the applicant’s scoping and screening results.

Therefore, by letter to the applicant dated October 8, 2004, the staff issued an RAI concerning

the specific issue to determine whether the applicant had properly applied the scoping criteria of

10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs

describe the staff’s RAI and the applicant’s related response.

In RAI F 2.3.3.14-1, the staff stated that LRA Section 2.3.3.14 states that one of the intended

functions of the sampling and water quality system is to establish an MSIV leakage pathway to

the condenser. The Unit 2 sampling lines from the main steam system are identified as being

within the scope of license renewal and subject to an AMR; however, similar piping and

components for Unit 1 are not identified as being within the scope of license renewal. Based on

the information in the LRA, the staff could not determine why this portion of the Unit 1 sampling

and water quality system is not within the scope of license renewal and subject to an AMR.

Therefore, the staff requested that the applicant explain why this portion of the piping is not

within the scope of license renewal and subject to an AMR.

In its response, by letter dated October 25, 2004, the applicant stated that license renewal

drawings depict components subject to an AMR based on the unit’s CLB. As documented in

LRA Section F.1, the Unit 1 CLB for MSIV leakage does not incorporate an alternate leakage

treatment pathway utilizing main steam piping and the main condenser, because this

modification currently is not physically implemented for Unit 1 to match Units 2 and 3 in their

configuration. 

The LRA was structured to reflect CLB and configuration of all three units. Therefore, scoping

and screening was done based on the CLB and configuration of all three units. The differences

between the units that are relevant to the application and will be resolved prior to Unit 1 restart

are listed in LRA Appendix F. This issue will be discussed in SER Section 2.6.1.1.

In addition, by letter dated January 31, 2005, the applicant provided additional supplementary

information, stating that as each activity identified in LRA Appendix F is completed, the

corresponding bold-bordered text in the LRA will apply to Unit 1. The applicant stated in its

response that the only change to the application will be to remove the bolded border. No

changes are required for scoping and screening, AMR, or TLAAs; however, in some cases,

boundary drawings would change to reflect the bolded bordered text. The applicant committed

to perform a secondary application review for the staff during the annual update after the

modification is implemented in the plant. This will assure that the design changes to implement

this modification do not modify or change the basis of how these components were initially

scoped and screened. 

Based on its review, the staff found the applicant’s response to RAI F 2.3.3.14-1 acceptable.

The Unit 1 CLB for MSIV leakage does not incorporate an alternate leakage treatment pathway

utilizing the main steam piping and main condenser; therefore, this portion of piping is not
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subject to an AMR. Upon completion of the modification discussed in LRA Appendix F and the

January 31, 2005 letter, the CLB for Unit 1 will be the same as that for Units 2 and 3. The

review of LRA Appendix F regarding Unit 1 restart will be addressed in SER Section 2.6.1.1.

Therefore, the staff’s concern described in RAI F 2.3.3.14-1 is resolved.

In order to resolve the seismic Class I/II interface issues discussed in RAI 2.1-2A(3) of SER

Section 2.1, the applicant expanded the system boundaries for the sampling and water quality

system. By letters dated January 31, 2005, and February 28, 2005, the applicant submitted the

result of its review of the seismic Class I qualification documentation to identify the NSR piping,

supports/equivalent anchors, or other components that are within the scope of license renewal

in accordance with the requirements of 10 CFR 54.4(a)(2) for the 10 CFR 54.4(a)(2) cases

where NSR piping or components are directly connected to SR piping or components. In

February 28, 2005, letter, Enclosure 2, “Mechanical Systems,” the applicant stated that

additional components, grab sample boxes, had been added to scope that are credited as

anchorage in the seismic analysis. As a result, the component type panel was added to LRA

Table 2.3.3.14.

The staff reviewed the identify support/equivalent anchors and the seismic Class II piping

segments up to the first anchor point of the seismic Class I piping boundaries provided in the

Enclosure 2 of the letter, dated February 28, 2005. The staff found the expanded scope of

components to be acceptable because the applicant had adequately included NSR components

with the configurations that meet the scoping criterion of 10 CFR 54.4(a)(2) for the cases where

NSR piping or components are directly connected to SR piping or components.

2.3.3.14.3 Conclusion

The staff reviewed the LRA and RAI responses described above to determine whether any

SSCs that should be within the scope of license renewal had not been 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 had not been 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 had adequately identified the sampling and

water quality system components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the sampling and water quality system components that are subject to an

AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.15 Building Heat System

2.3.3.15.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.15, the applicant described the building heat system. The building heat

system is a plant-shared system that maintains the required temperatures for equipment

protection and personnel comfort during the winter months. As required, the system uses

forced, hot water to maintain a minimum temperature of 55 °F in various plant buildings,

including the reactor building. Hot water required for the system is heated by the auxiliary boiler

system and preheats the building intake air.
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The building heat system contains SR components that are relied upon to remain functional

during, and following, DBEs. 

The intended functions within the scope of license renewal include the following:

 • provides a secondary containment boundary

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.3.15, the applicant identified the following building heat system component

types that are within the scope of license renewal and subject to an AMR: bolting, fittings,

heaters, piping, pumps, and valves.

2.3.3.15.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.15 and UFSAR Sections 5.3.3.6 and 10.12.5 using the

evaluation methodology described in SER Section 2.3. The staff conducted its review in

accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 reviewing LRA Section 2.3.3.15, the staff identified an area in which additional information

was necessary to complete the evaluation of the applicant’s scoping and screening results.

Therefore, by letter to the applicant dated August 31, 2004, the staff issued an RAI concerning

the specific issue to determine whether the applicant had properly applied the scoping criteria of

10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs

describe the staff’s RAI and the applicant’s related response.

In RAI 2.3.3.15-1, the staff stated that LRA Section 2.3.3.15 states that the intended function of

the building heat system is to provide a secondary containment boundary. The staff identified

that valves 1-1029, 1-1030, 2-1318, 2-1319, 3-1386, and 3-1387 are included in the scope of

license renewal and subject to an AMR, but the connected piping on one side of these valves is

not included within the scope of license renewal and not subject to an AMR. The staff could not

determine if the piping on both sides of these open valves provides a secondary containment

boundary. Therefore, the staff requested that the applicant provide a basis for these valves

being the boundary of the piping and components that are not subject to an AMR.

In its response, by letter dated October 19, 2004, the applicant stated that valves 1-1029,

1-1030, 2-1318, 2-1319, 3-1386, and 3-1387 were included in the scope of license renewal in

error and that only the piping and valves for the building heat system located in the reactor

building perform a secondary containment function. Valves 1-1029, 1-1030, 2-1318, 2-1319,

3-1386, and 3-1387 are located in the turbine building and, therefore, are not within the scope
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of license renewal. The applicant also stated that drawing 0-47E866-1-LR has been revised to

show the boundary ending at the reactor building wall and will be resent as part of the annual

update.

Based on its review, the staff found the applicant’s response to RAI 2.3.3.15-1 acceptable.

Valves 1-1029, 1-1030, 2-1318, 2-1319, 3-1386, and 3-1387 do not perform an intended

function in accordance with the requirements of 10 CFR 54.4(a) and are outside the scope of

license renewal. Therefore, the staff’s concern described in RAI 2.3.3.15-1 is resolved.

2.3.3.15.3 Conclusion

The staff reviewed the LRA and RAI response described above to determine whether any SSCs

that should be within the scope of license renewal had not been 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 had not been 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 had adequately identified the building heat system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the building heat system components that are subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.3.3.16 Raw Water Chemical Treatment System

2.3.3.16.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.16, the applicant described the raw water chemical treatment system. The

raw water chemical treatment system prevents bio-fouling of systems, including the EECW and

RHRSW systems, that use water directly from Wheeler Reservoir. The raw water chemical

treatment system provides the capability to inject a biocide into the fluid stream.

The raw water chemical treatment system contains SR components that are relied upon to

remain functional during, and following, DBEs. The failure of NSR SSCs in the raw water

chemical treatment system could prevent the satisfactory accomplishment of an SR function. 

The intended functions within the scope of license renewal include the following:

 • provides for pressure boundary integrity to the RHRSW and EECW systems

 • restricts flow

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.3.16, the applicant identified the following raw water chemical treatment

system component types that are within the scope of license renewal and subject to an AMR:

bolting, fittings, piping, restricting orifice, and valves.
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2.3.3.16.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.16 and UFSAR Sections 10.7.3, 10.8.4, and 10.10.4

using the evaluation methodology described in SER Section 2.3. The staff conducted its review

in accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 had not been 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 had not been 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

had adequately identified the raw water chemical treatment system components that are within

the scope of license renewal, as required by 10 CFR 54.4(a), and the raw water chemical

treatment system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.17 Demineralizer Backwash Air System

2.3.3.17.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.17, the applicant described the demineralizer backwash air system. The

demineralizer backwash air system is a plant-shared system that supplies a high volume of low

pressure air for purpose of backwashing plant demineralizers. In addition, the system supplies

the condensate demineralizers in the turbine building and penetrates the secondary

containment to supply the reactor water cleanup (RWCU) and fuel pool cooling and cleanup

(FPC) demineralizers in the reactor building. The demineralizer backwash air system is in

standby operation during normal operation and is operated manually, when required, for

backwashing of the demineralizers.

The demineralizer backwash air system contains SR components that are relied upon to remain

functional during, and following, DBEs. The failure of NSR SSCs in the demineralizer backwash

air system could prevent the satisfactory accomplishment of an SR function. 

The intended functions within the scope of license renewal include the following:

 • provides a secondary containment boundary

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support
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In LRA Table 2.3.3.17, the applicant identified the following demineralizer backwash air system

component types that are within the scope of license renewal and subject to an AMR: bolting,

fittings, piping, traps, and valves.

2.3.3.17.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.17 and UFSAR Section 5.3.3 using the evaluation

methodology described in SER Section 2.3. The staff conducted its review in accordance with

the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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).

2.3.3.17.3 Conclusion

The staff reviewed the LRA to determine whether any SSCs that should be within the scope of

license renewal had not been 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 had not been 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

had adequately identified the demineralizer backwash air system components that are within

the scope of license renewal, as required by 10 CFR 54.4(a), and the demineralizer backwash

air system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.18 Standby Liquid Control System

2.3.3.18.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.18, the applicant described the SLC system. The SLC system provides a

backup method, independent of the control rods, to make the reactor subcritical over the full

range of operating conditions. The SLC system can be manually initiated from the main control

room to pump a boron neutron absorber solution into the reactor. This function is initiated if the

operator determines that the reactor cannot be shut down or kept shut down with the control

rods alone. During normal operation, the SLC system is in standby and must be manually

initiated, if required.

The SLC system contains SR components that are relied upon to remain functional during, and

following, DBEs. The failure of NSR SSCs in the SLC system could prevent the satisfactory

accomplishment of an SR function. In addition, the SLC system performs functions that support

ATWS. 
2-95

The intended functions within the scope of license renewal include the following:

 • provides RCPB

 • provides a primary containment boundary

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.3.18, the applicant identified the following SLC component types that are

within the scope of license renewal and subject to an AMR: bolting, fittings, RCPB fittings,

piping, RCPB piping, pumps, tanks, tubing, valves, and RCPB valves.

2.3.3.18.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.18 and UFSAR Sections 3.8, 5.2.3, and 7.19 using the

evaluation methodology described in SER Section 2.3. The staff conducted its review in

accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 reviewing LRA Section 2.3.3.18, the staff identified an area in which additional information

was necessary to complete the evaluation of the applicant’s scoping and screening results.

Therefore, by letter to the applicant dated August 31, 2004, the staff issued an RAI concerning

the specific issue to determine whether the applicant had properly applied the scoping criteria of

10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs

describe the staff’s RAI and the applicant’s response.

In RAI 2.3.3.18-1, the staff stated that component electric heaters, located inside the SLC tank,

are shown on license renewal drawings 1-47E854-1-LR, 2-47E854-1-LR, and 3-47E854-1-LR

as subject to an AMR. However, LRA Section 2.3.5 lists the component UNID of the heater in

three different component types (fittings, heaters, or tanks). Therefore, the staff requested that

the applicant identify which component type in LRA Table 2.3.3.18 includes the electric heater.

Furthermore, during a telephone conference on October 7, 2004, the staff requested that the

applicant justify the exclusion of a strainer, addressed in UFSAR Section 3.8.3 but not depicted

on the license renewal drawings or included in LRA Table 2.3.3.18, from the scope of license

renewal and from being subject to an AMR.

In its response, by letter dated October 19, 2004, the applicant stated that this heater is

included in the component type “fittings” in LRA Table 2.3.3.18. The staff requested the

applicant to verify that the heaters are, in fact, included in the component type “fittings.” In a

supplemental response, dated June 9, 2005, the applicant confirmed that the heaters are

included in component type “fittings” in LRA Table 2.3.3.18 and are so documented in the
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Standby Liquid Control System Report. The applicant also provided information that the

strainers have been included in LRA Table 2.3.3.18 for being subject to an AMR. 

Based on its review, the staff found the applicant’s response to RAI 2.3.3.18-1 acceptable. It

clarifies that the heater is included in the component type “fittings” in the LRA table, and it

includes the strainer within the scope of license renewal and subject to an AMR. Therefore, the

staff’s concerns described in RAI 2.3.3.18-1 and the October 7, 2004, telephone discussion are

resolved.

In order to resolve the seismic Class I/II interface issues discussed in RAI 2.1-2A(3) of SER

Section 2.1, the applicant expanded the system boundaries for the standby liquid control

system. By letters dated January 31, 2005, and February 28, 2005, the applicant submitted its

review result of the documentation of the seismic Class I qualification to identify the NSR piping,

supports/equivalent anchors, or other components that are within the scope of license renewal

in accordance with the requirements of 10 CFR 54.4(a)(2) for the cases where NSR piping or

components are directly connected to safety-related piping or components. In its February 28,

2005 letter, enclosure 2, “Mechanical Systems,” the applicant stated that additional piping and

components had been added to the scope of the standby liquid control system. However, the

component types do not differ from those listed LRA Table 2.3.3.18; therefore, no changes to

the standby liquid control system portion in the LRA are required.

The staff reviewed the NSR piping up to first equivalent anchor point of seismic Class I piping

boundaries and found the expanded scope of components to be acceptable on the basis that

the applicant had adequately identified all SLC NSR components that meet the scoping criterion

of 10 CFR 54.4(a)(2) for the cases where NSR piping or components are directly connected to

SR piping or components.

2.3.3.18.3 Conclusion

The staff reviewed the LRA, the accompanying scoping boundary drawings, and RAI responses

described above to determine whether any SSCs that should be within the scope of license

renewal had not been 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 had not been 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 had

adequately identified the SLC system components that are within the scope of license renewal,

as required by 10 CFR 54.4(a), and the SLC system components that are subject to an AMR,

as required by 10 CFR 54.21(a)(1).

2.3.3.19 Off-Gas System

2.3.3.19.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.19, the applicant described the off-gas system. Each unit has a separate

off-gas system, which includes subsystems that process and dispose of the gases produced

during normal operation from the main condenser steam jet air ejectors, the startup condenser

vacuum pumps, the condensate drain tank vent, and the steam packing exhauster. The gases

are processed to minimize any release of harmful radioactivity and are then diverted to the plant
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stack for dilution and release to the atmosphere at elevation. Backdraft dampers limit the

amount of radioactive release at ground level during accidents that require operation of the

SGT system.

The off-gas system contains SR components that are relied upon to remain functional during,

and following, DBEs. 

The intended functions within the scope of license renewal include the following:

 • provides flow path integrity for the release of the filtered SGT system gases to the

stacks

 • provides automatic closure of back-draft prevention dampers to prevent back-flow and

potential ground-level release of radiation

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.3.19, the applicant identified the following off-gas system component types

that are within the scope of license renewal and subject to an AMR: bolting, ductwork, fittings,

and piping.

2.3.3.19.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.19 and UFSAR Sections 1.6.1.1.10, 1.6.1.4.4, 5.3.3,

7.12.2, 7.12.3, 9.5, 11.4, 14.6.3.6, and F.7.14 using the evaluation methodology described in

SER Section 2.3. The staff conducted its review in accordance with the guidance described in

SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 order to resolve the seismic Class I/II interface issues discussed in RAI 2.1-2A(3) of SER

Section 2.1, the applicant expanded the system boundaries for the off-gas system. By letters

dated January 31, 2005, and February 28, 2005, the applicant submitted the results of its

review of the seismic Class I qualification documentation to identify the NSR piping,

supports/equivalent anchors, or other components that are within the scope of license renewal

in accordance with the requirements of 10 CFR 54.4(a)(2) for the cases where NSR piping or

components are directly connected to SR piping or components. In the February 28, 2005

letter, enclosure 2, “Mechanical Systems,” the applicant stated that additional components,

valves, had been added to the scope of the off-gas system. The component type valve was

added to LRA Table 2.3.3.19.
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The staff reviewed the NSR piping up to first equivalent anchor point of seismic Class I piping

boundaries and found the expanded scope of components to be acceptable on the basis that

the applicant had adequately identified all SLC NSR components that meet the scoping criterion

of 10 CFR 54.4(a)(2) for the cases where NSR piping or components are directly connected to

SR piping or components.

2.3.3.19.3 Conclusion

The staff reviewed the LRA and RAI response to determine whether any SSCs that should be

within the scope of license renewal had not been 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 had not been 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 had adequately identified the off-gas system components that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and the off-gas system components

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

2.3.3.20 Emergency Equipment Cooling Water System

2.3.3.20.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.20, the applicant described the EECW system. The EECW system is a

plant-shared system, which has two headers that use dedicated RHRSW pumps to supply

water from the Wheeler Reservoir into heat exchangers. The heat exchangers cool equipment

including the DG engine coolers, CS pump room coolers, RHR pump seal coolers and room

coolers, control bay chillers, hydrogen and oxygen containment gas analyzers, and electric

board room chillers. The EECW system provides cooling water to equipment that is essential

for safe shutdown and a backup cooling water supply to the reactor building closed cooling

water heat exchangers.

The EECW system contains SR components that are relied upon to remain functional during,

and following, DBEs. The failure of NSR SSCs in the EECW system could prevent the

satisfactory accomplishment of an SR function. In addition, the EECW system performs

functions that support fire protection, EQ, and SBO.

The intended functions within the scope of license renewal include the following:

 • provides cooling water to the HVAC system chillers, RHR system pump seal coolers,

containment inerting system hydrogen and oxygen gas analyzers, DG, RHR and CS

equipment room coolers, and FPC system

 • provides an EECW valve position interlock signal for automatic start of the RHRSW

pumps

 • provides a secondary containment boundary

 • prevents debris from entering a system or component

 • provides for flow distribution

 • provides for heat transfer
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 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.3.20, the applicant identified the following EECW system component types

that are within the scope of license renewal and subject to an AMR: bolting, fittings, flexible

connectors, heat exchangers, piping, restricting orifice, strainers, tubing, and valves.

2.3.3.20.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.20 and UFSAR Sections 5.3, 7.18, 10.10, and F.7.17

using the evaluation methodology described in SER Section 2.3. The staff conducted its review

in accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 reviewing LRA Section 2.3.3.20, the staff identified an area in which additional information

was necessary to complete the evaluation of the applicant’s scoping and screening results.

Therefore, by letter to the applicant dated August 31, 2004, the staff issued an RAI concerning

the specific issue to determine whether the applicant had properly applied the scoping criteria of

10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs

describe the staff’s RAI and the applicant’s response.

In RAI 2.3.3.20-1, the staff stated that License renewal drawings 1-47E859-1-LR,

2-47E859-1-LR, and 3-47E859-1-LR depict the EECW system. The cooling water return piping

from the SR components terminates at locations designated as “yard drainage.” LRA

Table 3.3.2.20 indicates that buried carbon and low-alloy steel piping has been evaluated for

aging management. However, neither the LRA nor the associated drawings adequately identify

the extent of the buried piping subject to an AMR. Therefore, the staff requested that the

applicant identify the extent of the buried piping and provide an appropriately marked license

renewal drawing, or identify a specific structure where the piping subject to an AMR terminates.

The staff also requested that the applicant justify the exclusion of any buried piping or

structures between the emergency equipment cooling water system and the final discharge

structure from the scope of license renewal and from being subject to an AMR.

In its response, by letter dated October 19, 2004, the applicant stated that a note had been

added to license renewal drawings 1-47E859-1-LR, 2-47E859-1-LR, and 3-47E859-1-LR to

state that the EECW buried piping is within the scope of license renewal up to the catch basins

shown on isometric drawing 0-17W300-9. 

Based on its review, the staff found the applicant’s response to RAI 2.3.3.20-1 acceptable. It

adequately identifies the extent of the buried emergency equipment cooling water piping that is
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within the scope of license renewal and subject to an AMR. Therefore, the staff’s concern

described in RAI 2.3.3.20-1 is resolved.

2.3.3.20.3 Conclusion

The staff reviewed the LRA, the accompanying scoping boundary drawings, and RAI response

described above to determine whether any SSCs that should be within the scope of license

renewal had not been 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 had not been 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 had

adequately identified the EECW system components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and the EECW system components that are subject to

an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.21 Reactor Water Cleanup System

2.3.3.21.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.21, the applicant described the RWCU system. A separate RWCU system

is provided for each unit. The major equipment for the RWCU system is located in the reactor

building and consists of two pumps, regenerative and non-regenerative heat exchangers, and

two filter/demineralizers with supporting equipment. Suction for the system is taken from the

reactor vessel bottom drain and from the RHR system shutdown cooling suction line, which is

supplied by the reactor coolant recirculation system. The system automatically isolates upon

accident initiation and upon SLC system actuation. The RWCU system functions to maintain a

high reactor-water purity to limit corrosion, chemical interactions, fouling, and deposits on

reactor heat transfer surfaces. The system also removes corrosion products to limit impurities

available for activation by neutron flux and the resultant radiation from deposits of corrosion

products. In addition, the system provides a means for removal of water from the reactor vessel

during normal operations.

The RWCU system contains SR components that are relied upon to remain functional during,

and following, DBEs. The failure of NSR SSCs in the RWCU system could prevent the

satisfactory accomplishment of an SR function. In addition, the RWCU system performs

functions that support fire protection, EQ, and SBO. 

The intended functions within the scope of license renewal include the following:

 • provides primary and secondary containment boundaries

 • provides RCPB

 • provides system pressure boundary support (check valve) to HPCI to prevent diversion

of HPCI system core cooling water from the reactor vessel (Unit 3 only)

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support
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In LRA Table 2.3.3.21, the applicant identified the following RWCU system component types

that are within the scope of license renewal and subject to an AMR: bolting, fittings, RCPB

fittings, heat exchangers, piping, RCPB piping, pumps, restricting orifice, strainers, tanks, traps,

tubing, valves, and RCPB valves.

2.3.3.21.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.21 and UFSAR Sections 3.8, 4.1, 4.9, 5.2.3, 5.3, and 7.3

using the evaluation methodology described in SER Section 2.3. The staff conducted its review

in accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 reviewing LRA Section 2.3.3.21, the staff identified areas in which additional information was

necessary to complete the evaluation of the applicant’s scoping and screening results.

Therefore, by letter to the applicant dated April 8, 2005, the staff issued RAIs concerning the

specific issues to determine whether the applicant had properly applied the scoping criteria of

10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs

describe the staff’s RAIs and the applicant’s related responses.

In RAI 2.3.3.21-1, the staff identified thermal tees that are within the scope of license renewal

and subject to an AMR. However, “thermal tees” is not a component type listed in LRA

Table 2.3.3.21-1 as being subject to an AMR, nor it is included in LRA Section 2.3.5 as a

component type. Therefore, the staff requested that the applicant indicate if thermal tees are

already included in LRA Table 2.3.3.21 as a component type subject to an AMR, or justify the

exclusion of the components from being subject to an AMR in accordance with the

requirements of 10 CFR 54.21(a)(1).

In its response, by letter dated April 28, 2005, the applicant stated that thermal tees are

included in LRA Table 2.3.3.21 as component type “fittings.” Thermal tees were not listed in

LRA Section 2.3.5, because these components are not assigned UNID’s on drawings. LRA

Section 2.3.5 was generated to show where UNID’s appearing on the license renewal drawings

were grouped in a component type.

Based on its review, the staff found the applicant’s response to RAI 2.3.3.21-1 acceptable.

because thermal tees are included as a component type that is subject to an AMR. Therefore,

the staff’s concern described in RAI 2.3.3.21-1 is resolved.

In RAI 2.3.3.21-2, the staff identified fusible plugs (FUPG) to be within the scope of license

renewal and subject to an AMR. The drawing note associated with FUPGs states that the

FUPG is a threaded pipe plug with a low temperature eutectic alloy that is attached to the

RWCU pipe upstream of valve FCV-69-94. Eutectic material melts on high temperature, venting

the control air line, which closes isolation valve FCV-69-94. Also, another drawing note states
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that the system shall be qualified for an elevated temperature excursion up to 562 °F during an

Appendix R event from the non-generative heat exchanger outlet to valve FCV-69-94.

 a. The FUPGs are neither listed in LRA Table 2.3.3.21 as a component type subject to an

AMR, nor as a subcomponent of the component types listed in LRA Section 2.3.5.

Therefore, the staff requested that the applicant indicate if FUPGs are already included

in LRA Table 2.3.3.21 as a component type subject to an AMR, or justify the exclusion

of these components from being subject to an AMR in accordance with the requirements

of 10 CFR 54.21(a)(1).

 b. Based on the above mentioned drawing notes, it appears that valve FCV-69-94 satisfies

criterion 10 CFR 54.4(a)(3) for an EQ and fire protection regulated event. However, the

piping and components associated with this valve, including the above-mentioned

FUPG, are shown as within the scope of license renewal in accordance with the

10 CFR 54.4(a)(2) criterion. The staff requested that the applicant explain how valve

FCV-69-94 functions differently from its associated pipeline.

In its response, by letter dated April 28, 2005, the applicant stated that the FUPGs were

inadvertently colored in blue on the drawing but should have been black since they are active

components and are not within the scope of license renewal. The applicant also stated that the

fusible plugs do not form a pressure boundary function for the RWCU system. The license

renewal drawings have been revised to show FUPG-32-5105 black instead of blue, since it is

not subject to an AMR.

Based on its review, the staff found the applicant’s response to RAI 2.3.3.21-2a acceptable.

FUPGs meet the definition for an active component and, therefore, are not subject to an AMR.

Therefore, the staff’s concern described in RAI 2.3.3.21-2a is resolved. 

With regard to RAI 2.3.3.21-2b, the applicant stated that the piping and equipment downstream

of FCV-69-2 up to and including valve FCV-69-94 will be corrected on the drawings to show the

components in scope per the criteria 10 CFR 54.4a(3) and subject to an AMR, since these

components form the reactor coolant pressure boundary during an Appendix R event. The tube

side of the heat exchanger is considered part of the reactor coolant pressure boundary while

the shell side provides the structural support for the tubes. Shell side piping connections will

remain in scope. Also, System 43 in drawing 0-105E3156-1-LR will be corrected to show its

components required for pressure boundary integrity in red instead of blue on the drawing, that

are within the scope of license renewal and subject to an AMR, due to its interface with RWCU

drawings 2-47E810-1-LR and 3-47E810-1-LR.

Based on its review, the staff found the applicant’s response to RAI 2.3.3.21-2b acceptable.

The applicant clarified the function of the piping and valve in question and corrected the

corresponding drawings to reflect the appropriate intended function of the components.

Therefore, the staff’s concern described in RAI 2.3.3.21-2b is resolved.

In RAI 2.3.3.21-3, the staff stated that UFSAR (Revision 20), Section 4.9 states that:

Reactor coolant is continuously removed from the reactor coolant recirculation

system, cooled in the regenerative and non-regenerative heat exchangers,

filtered and demineralized, and returned to the feedwater system through the
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shell side of the regenerative heat exchanger. The Unit 3 RWCU system has the

capability to return process fluid to the feedwater system through both reactor

feedwater lines A and B. The Unit 2 RWCU system only has one return line

through reactor feedwater line B.

Only, the RWCU system return line to the reactor feedwater line B is depicted on license

renewal drawing 3-47E810-1-LR. Therefore, the staff requested that the applicant indicate

whether feedwater line A is within the scope of license renewal and subject to an AMR, or

provide an explanation for its exclusion. The staff also asked the applicant to provide an

alternative drawing that shows the RWCU system return to feedwater line A for Unit 3.

In its response, by letter dated April 28, 2005, the applicant stated that the Unit 3 RWCU

system return to feedwater line A is shown on license renewal drawing 3-47E810-1-LR (at

location G6). The applicant further noted that the return is through a HPCI line shown on

3-47E812-1-LR (location E6) which connects to feedwater line A shown on 3-47E803-1-LR

(location G6). The HPCI and feedwater portions of this return path are within the scope of

license renewal.

Based on its review, the staff found the applicant’s response to RAI 2.3.3.21-3 acceptable. The

applicant identified the return to feedwater line A and stated that it is within the scope of license

renewal as indicated on the provided license renewal drawings. Therefore, the staff’s concern

described in RAI 2.3.3.21-3 is resolved.

In RAI 2.3.3.21-4, the staff identified flow indicators FI-85-75 and FI-85-77, and flow element

FE-69-13 as excluded from the scope of license renewal. The flow indicators and flow element

serve an intended function of pressure boundary and are passive and long-lived components. It

is noted that similar flow indicators and flow elements on drawings 2-47E810-1-LR and

3-47E810-1-LR are shown to be within the scope of license renewal and subject to an AMR.

However, “flow indicators” is not listed in LRA Table 2.3.3.21 as a component type subject to an

AMR, nor as a subcomponent of the component types listed in LRA Section 2.3.5. Therefore,

the staff requested that the applicant:

 a. Justify the exclusion of the aforementioned flow indicators and flow element in Unit 1

from the scope of license renewal and from being subject to an AMR in accordance with

the requirements of 10 CFR 54.4(a) and 10 CFR 54.21(a)(1), respectively.

 b. Clarify whether flow indicators are included in other component types already listed in

LRA Table 2.3.3.21, or justify their exclusion from an AMR in accordance with the

requirements of 10 CFR 54.21(a)(1).

In its response, by letter dated April 28, 2005, the applicant stated that NEI 95-10, Appendix B

indicates that flow indicators are active components. FI 85-75 and FI 85-77 were colored blue in

error on license renewal drawings 2-47E810-1-LR and 3-47E810-1-LR, but have been

corrected to show these components black on the drawings; that is, not subject to an AMR. The

flow element on license renewal drawing 1-47E810-1-LR was included as a fitting in the

evaluation but was inadvertently not colored blue on the drawing. License renewal drawing

1-47E810-1-LR has also been revised to show that FE 69-13 is within the scope of license

renewal and subject to AMR.
2-104

With regard to RAI 2.3.3.21-4b, the applicant stated that “flow indicators” is not a component

type listed in LRA Table 2.3.3.21. Flow indicators were excluded from an AMR based on

guidance provided in NEI 95-10 Appendix B.

On the basis of this review, the staff was unable to find the applicant’s response to

RAI 2.3.3.21-4 acceptable. The applicant follows the guidance in NEI 95-10, which lists flow

indicators as active components. However, the flow indicators in question are in-line indicators.

The indicator portion of the component is an active component, but the piping portion of the

indicator through which reactor water flows provides a pressure boundary function. Therefore,

this portion of the component should be within the scope of license renewal and subject to an

AMR. In a follow-up question, the staff asked the applicant to justify the exclusion of the piping

portion of the flow indicators.

In a follow-up response, by letter dated May 24, 2005, the applicant stated that the pressure

boundary portion of the flow indicators are in scope and are evaluated as fittings in the CRD

system (system 85). License renewal drawings 1-47E810-1-LR, 2-47E810-1-LR, and

3-47E810-1-LR were revised to show that FI-75 and FI-77 are in scope and subject to an AMR

for meeting the10 CFR 54.4(A)(2) criterion. The pressure retaining portion of the flow indicators

are stainless steel with internal environment of treated water, with external environment of

inside air, and are already contained in LRA Table 3.3.2.29. The applicant further stated that all

license renewal drawings were reviewed for in-line flow indicators that provide a pressure

boundary function. This review identified the drawings for systems 43, 68, 69, and 74 that

contain flow indicators with pressure boundary functions. The applicant stated that no changes

to LRA tables are required since fittings contain the material and environment combinations for

the in-line flow indicators, flow indicating controllers, and flow indicating switches that provide a

pressure boundary function. 

Based on its review, the staff found the applicant’s response to RAI 2.3.3.21-4 acceptable. The

applicant included the flow indicators within the scope of license renewal and subject to an

AMR. The applicant also performed a review for all other mechanical systems and identified the

systems with flow indicators that form a pressure boundary. The applicant revised the system

drawings accordingly by adding these flow indicators in scope. Therefore, the staff’s concern

described in RAI 2.3.3.21-4 is resolved 

In RAI 2.3.3.21-5, the staff identified a 4-inch pipeline to the waste collector and surge tank

inside the pipe tunnel to radwaste (location B4) excluded from the scope of license renewal.

However, the same pipeline on the license renewal drawing is shown as being within the scope

of license renewal in accordance with the requirements of 10 CFR 54.4(a)(2). Therefore, the

staff requested that the applicant clarify this apparent discrepancy.

In its response, by letter dated April 28, 2005, the applicant stated that the line was

inadvertently colored in blue but should have been in black. The drawing was corrected to show

the line in black, that is, not within the scope of license renewal.

Based on its review, the staff found the applicant’s response to RAI 2.3.3.21-5 acceptable. The

applicant clarified that the piping in question is not within the scope of license renewal and

corrected the corresponding drawing. Therefore, the staff’s concern described in RAI 2.3.3.21-5

is resolved.
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2.3.3.21.3 Conclusion

The staff reviewed the LRA, the accompanying scoping boundary drawings, and RAI responses

described above to determine whether any SSCs that should be within the scope of license

renewal had not been 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 had not been 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 had

adequately identified the RWCU system components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and the RWCU system components that are subject to

an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.22 Reactor Building Closed Cooling Water System

2.3.3.22.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.22, the applicant described the reactor building closed cooling water

system. The reactor building closed cooling water system provides a continuous supply of

cooling water during normal operation to designated plant equipment located in the primary and

secondary containments. Water cooled in the heat exchangers provides cooling water for

components such as the reactor recirculation system pumps and motor, the RWCU system

pumps and non-regenerative heat exchanger, the fuel pool cooling and cleanup system heat

exchanger, the drywell atmosphere cooling coils, the reactor building equipment drain sump

heat exchanger, the drywell equipment drain sump heat exchanger, the drywell air compressors

and aftercoolers, and the sample coolers in the sampling and water quality system. The system

is normally operational and will automatically trip if an accident initiates it.

The reactor building closed cooling water system contains SR components that are relied upon

to remain functional during, and following, DBEs. The failure of NSR SSCs in the reactor

building closed cooling water system could prevent the satisfactory accomplishment of an SR

function. In addition, the reactor building closed cooling water system performs functions that

support fire protection, EQ, and SBO.

The intended functions within the scope of license renewal include the following:

 • provides primary and secondary containment boundaries

 • provides for a pressure boundary of the reactor building closed cooling water system

components connected to the control air system that must maintain the boundary in

support of supplying CAD to the MSRVs

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.3.22, the applicant identified the following reactor building closed cooling

water system component types that are within the scope of license renewal and subject to an
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AMR: bolting, fittings, flexible connectors, heat exchangers, piping, pumps, strainers, tanks,

tubing, and valves.

As a result of the review of seismic Class I piping boundaries to identify supports and equivalent

anchors in response to RAI 2.1-2A(3) (discussed in SER Section 2.1), the applicant expanded

the system boundaries for the reactor building closed cooling water system. By letters dated

January 31, 2005, and February 28, 2005, the applicant submitted the results of its review of

the seismic Class I qualification documentation to identify the NSR piping, supports and

equivalent anchors, or other components that are within the scope of license renewal in

accordance with the requirements of 10 CFR 54.4(a)(2) for the cases where NSR piping or

components are directly connected to SR piping or components. In its February 28, 2005, letter,

enclosure 2, “Mechanical Systems,” the applicant stated that additional piping and components

had been added to the scope of the reactor building closed cooling water system. However, the

component types do not differ from those listed in LRA Table 2.3.3.22 and no changes to the

reactor building closed cooling water system portion of the LRA are required.

2.3.3.22.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.22 and UFSAR Sections 5.2, 5.3, 10.6, and F.6.19 using

the evaluation methodology described in SER Section 2.3. The staff conducted its review in

accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 reviewing LRA Section 2.3.3.22, the staff identified areas in which additional information was

necessary to complete the evaluation of the applicant’s scoping and screening results.

Therefore, by letter to the applicant dated August 31, 2004, the staff issued RAIs concerning

the specific issues to determine whether the applicant had properly applied the scoping criteria

of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs

describe the staff’s RAIs and the applicant’s related responses.

In RAI 2.3.3.22-1, the staff stated that license renewal drawings 2-47E610-70-1-LR and

3-47E610-70-1-LR show that the flow control valves and the combination of air filter/pressure

regulators for the drywell atmospheric cooling units (A5 and B5) are within the scope of license

renewal and subject to an AMR. However, the flow control valves and combination of the air

filter/pressure regulators for the drywell atmospheric cooling units A4 and B4, A3 and B3, A2

and B2, and A1 and B1 are not identified as being within the scope of license renewal.

Therefore, the staff requested that the applicant justify the exclusion of the flow control valves

and combination air filter/pressure regulators for the drywell atmospheric cooling units A4 and

B4, A3 and B3, A2 and B2, A1 and B1 components from the scope of license renewal and from

being subject to an AMR.
2-107

In its response, by letter dated October 19, 2004, the applicant stated that the air filter/pressure

regulators for drywell atmospheric cooling units A1 and B1, A2 and B2, A3 and B3, and A4 and

B4 are not within the scope of license renewal, because they do not form a pressure boundary

with the control air system (system 32).

Based on its review, the staff was unable to find the applicant’s response to RAI 2.3.3.22-1

acceptable, because a drawing note (Note 6 at location F2 on license renewal drawings

2-47E610-70-1-LR and 3-47E610-70-1-LR) states:

The cooling water enters the drywell, supplying two drywell atmospheric cooling

units (A and B). Each Cooling Unit has five cooling coils, four operating and one

spare. Control is from the main control room by a hand switch (HS-70-16A, etc)

which operates dampers and diaphragm-operated gate valves (FCV-70-16, etc).

Each drywell cooling unit has five fans, any four of them may be used at one

time and the fifth reserved as a spare.

Any cooling unit can be used as a spare unit, and the configuration shown on the license

renewal drawings for cooling units A5 and B5 can be applied to all other cooling units. Hence,

cooling units A1 through A4 and B1 through B4 also form a pressure boundary with the control

air system when they are used as a spare unit. Therefore, the air filter/pressure regulators for

cooling units A1 through A4 and B1 through B4 should be within the scope of license renewal

and subject to an AMR. Considering the above-mentioned drawing note, the staff asked in a

supplemental RAI that the applicant justify the exclusion of cooling units A1 through A4, and B1

through B4 from the scope of license renewal and from being subject to an AMR.

In a supplemental response dated June 9, 2005, the applicant stated that, based upon further

review, the filter/pressure regulators for cooling units A1 through A4, and B1 through B4 will be

included within the scope of license renewal, and that the license renewal drawings will be

revised accordingly.

Based on its review, the staff found the applicant’s response to RAI 2.3.3.22-1 acceptable. The

applicant added the filter/pressure regulators for cooling units A1 through A4, and B1 through

B4 to the scope of license renewal and will correct the corresponding drawings. Therefore, the

staff’s concern described in RAI 2.3.3.22-1 is resolved.

In RAI 2.3.3.22-2, the staff stated that the operators of the two valves FCV 70-24 and FCV

70-34 are shown on license renewal drawings 2-47E610-70-1 and 3-47E822-1 as being within

the scope of license renewal and subject to an AMR. However, license renewal drawings

3-47E610-70-1, 1-47E822-1-LR, and 2-47E822-1-LR show the operators for the same valves

as not within the scope of license renewal and not subject to an AMR. T, the staff requested

that the applicant clarify the inconsistency and justify the exclusion of operators for FCV 70-24

and FCV 70-34 from the scope of license renewal and from being subject to an AMR.

In its response, by letter October 19, 2004, the applicant stated that the operators shown on

drawings 3-47E610-70-1-LR and 2-47E822-1-LR should have been highlighted, (i.e., that they

are in scope and subject to an AMR). The applicant further stated that the modification

identified in Appendix F.2 had not been implemented in Unit 1; therefore, these components are

not within the scope of license renewal for Unit 1. Drawings 3-47E610-70-1-LR and

2-47E822-1-LR have been revised and will be sent to the staff as part of the annual update.
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Based on its review, the staff found the applicant’s response to RAI 2.3.3.22-2 acceptable. It

concurs that the operators addressed in the RAI should be within the scope of license renewal.

Therefore, the staff’s concern described in RAI 2.3.3.22-2 is resolved.

In RAI 2.3.3.22-3, the staff noted that LRA Section 2.3.3.22 states that the operators for the

dampers are within the scope of license renewal as a pressure boundary for the control air.

With regard to this statement, the staff requested the following information:

 a. The UNIDs assigned to various components, in particular, the dampers and the

operators for the dampers, are for the reactor building closed cooling water system.

Therefore, the staff requested that the applicant clarify whether or not the operators for

the dampers are evaluated in the control air system. 

 b. The staff also asked the applicant whether the operators shown on license renewal

drawings 2-47E610-70-1-LR and 3-47E610-70-1-LR are subject to an AMR and, if so,

under what component type.

In its response, by letter dated October 19, 2004, the applicant stated the following: 

 a. The damper operators are part of the reactor building closed cooling water system, and

are evaluated as valves in the reactor building closed cycle cooling water system. As

depicted on license renewal drawings 2-47E610-70-1-LR and 3-47E610-70-1-LR, the

damper operators support the control air system (system 32) pressure boundary. Since

these damper operators are connected to the control air system, they must maintain a

pressure boundary in order for the control air system to maintain its system boundary

(i.e., form a pressure boundary). Therefore, any damper operators that are required to

form a pressure boundary with the control air system are within the scope of license

renewal for the control air system.

Based on its review, the staff found the applicant’s response to RAI 2.3.3.22-3a acceptable. It

clarifies that the damper operators have a pressure boundary intended function and are within

the scope of license renewal and subject to an AMR. Therefore, the staff’s concern described in

RAI 2.3.3.22-3a is resolved.

In its response, by letter dated October 19, 2004, the applicant further stated the following:

 b. The damper operators are subject to an AMR and are included as part of the component

type “valves” in LRA Table 2.3.3.22.

Based on its review, the staff found the applicant’s response to RAI 2.3.3.22-3b acceptable. It

confirms that the damper operators are subject to an AMR and are included in LRA

Table 2.3.3.22. Therefore, the staff’s concern described in RAI 2.3.3.22-3b is resolved.

The staff also reviewed the results of the applicant’s review of seismic Class I piping boundaries

provided in the applicant’s letter, dated February 28, 2005, enclosure 2, to identify supports and

equivalent anchor points in response to RAI 2.1-2A(3). The staff found the expanded scope of

components to be acceptable on the basis that the applicant had adequately identified all

reactor building closed cooling water system NSR components that meet the scoping criterion
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of 10 CFR 54.4(a)(2) for the cases where NSR piping or components are directly connected to

SR piping or components.

2.3.3.22.3 Conclusion

The staff reviewed the LRA, the accompanying scoping boundary drawings, and RAI responses

described above to determine whether any SSCs that should be within the scope of license

renewal had not been 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 had not been 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 had

adequately identified the reactor building closed cooling water system components that are

within the scope of license renewal, as required by 10 CFR 54.4(a), and the reactor building

closed cooling water system components that are subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.3.3.23 Reactor Core Isolation Cooling System

2.3.3.23.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.23, the applicant described the RCIC system. The RCIC system provides

makeup water to the reactor vessel during shutdown and also provides isolation from the main

heat sink to supplement or replace the normal makeup water sources. The system also

includes associated valves and piping capable of delivering makeup water to the reactor vessel.

During normal operation, the system is in standby and initiates, automatically, when required.

The RCIC system has automatic isolation provisions to ensure the integrity of the primary

containment.

The RCIC system contains SR components that are relied upon to remain functional during,

and following, DBEs. In addition, the RCIC system performs functions that support fire

protection, EQ, ATWS, and SBO.

The intended functions within the scope of license renewal include the following:

 • provides RCPB

 • provides primary and secondary containment boundaries

 • provides for a system pressure boundary in support of the residual heat removal system

containment (torus) cooling function

 • establishes MSIV leakage pathway to the condenser

 • provides sufficient reactor coolant makeup to maintain the reactor in a safe condition

 • provides debris protection

 • restricts flow

 • provides for heat transfer

 • provides mechanical closure
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 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.3.23, the applicant identified the following RCIC system component types that

are within the scope of license renewal and subject to an AMR: bolting, condenser, expansion

joint, fittings, RCPB fittings, flexible connector, heat exchangers, piping, RCPB piping, pumps,

restricting orifice, RCPB restricting orifice, strainers, tanks, traps, tubing, turbines, valves, and

RCPB valves.

2.3.3.23.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.23 and the UFSAR Sections 4.1, 4.7, 5.2.3, 5.3, 7.3, and

7.18 using the evaluation methodology described in SER Section 2.3. The staff conducted its

review in accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in

accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not omitted

from the scope of license renewal any components with intended functions delineated under

10 CFR 54.4(a). The staff then reviewed those components that the applicant 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 reviewing LRA Section 2.3.3.23, the staff identified an area in which additional information

was necessary to complete the evaluation of the applicant’s scoping and screening results.

Therefore, by letter to the applicant dated October 8, 2004, the staff issued an RAI concerning

the specific issues to determine whether the applicant had properly applied the scoping criteria

of 10 CFR 54.4 (a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs

describe the staff’s RAIs and the applicant’s related responses.

In RAI 2.3.3.23-1, the staff stated that UFSAR Section 4.7.5, states that the RCIC makeup

water is delivered into the reactor vessel through a connection to the feedwater line and is

distributed within the reactor vessel through the feedwater sparger. The connection to the

feedwater line is provided with a thermal sleeve. It is further stated that the thermal sleeve

(liner) in the feedwater line is designed as a nonpressure-containing liner and is provided to

protect the pressure-containing piping tee from excessive thermal stress. In LRA

Table 2.3.3.23, thermal sleeve (liner) was not identified as a component type within the scope

of license renewal. Therefore, the staff requested the applicant to include this component type

within the scope of license renewal and AMR.

In its response, by letter dated November 3, 2004, the applicant stated that the material for this

component was identified as pipe and pipe fitting in the feedwater system and will be inspected

as part of the One-Time Inspection Program. 

Based on its review, the staff found the applicant’s response to RAI 2.3.3.23-1 acceptable. The

applicant included the subject component and its intended functions within the scope requiring

an AMR. Therefore, the staff’s concern described in RAI 2.3.3.23-1 is resolved.
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2.3.3.23.3 Conclusion

The staff reviewed the LRA and RAI response described above to determine whether any SSCs

that should be within the scope of license renewal had not been 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 had not been 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 had adequately identified the RCIC system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the RCIC system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.24 Auxiliary Decay Heat Removal System

2.3.3.24.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.24, the applicant described the auxiliary decay heat removal (ADHR)

system. The ADHR system can be used to remove residual heat from the spent fuel pool and

reactor cavity during outages. The ADHR system supplements the fuel pool cooling and

cleanup system and consists of two cooling water loops. The primary cooling loop circulates

water from the spent fuel pool entirely inside the reactor building and rejects heat from the

spent fuel pool to a secondary loop via a heat exchanger. The secondary loop transfers heat to

the atmosphere outside of the reactor building by the means of evaporative cooling towers.

The ADHR system contains SR components that are relied upon to remain functional during,

and following, DBEs. The failure of NSR SSCs in the ADHR system could prevent the

satisfactory accomplishment of an SR function. 

The intended functions within the scope of license renewal include the following:

 • provides a secondary containment boundary

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.3.24, the applicant identified the following ADHR system component types

that are within the scope of license renewal and subject to an AMR: bolting, fittings, heat

exchangers, piping, pumps, strainers, tubing, and valves.

2.3.3.24.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.24 and UFSAR Sections 5.3, 10.5, and 10.22 using the

evaluation methodology described in SER Section 2.3. The staff conducted its review in

accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
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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 order to resolve the seismic Class I/II interface issues discussed in RAI 2.1-2A(3) of SER

Section 2.1, the applicant expanded the system boundaries for the ADHR system. By letters

dated January 31, 2005, and February 28, 2005, the applicant submitted the results of its

review of the seismic Class I qualification documentation to identify the NSR piping, supports

and equivalent anchors, or other components that are within the scope of license renewal in

accordance with the requirements of 10 CFR 54.4(a)(2) for the 10 CFR 54.4(a)(2) cases where

NSR piping or components are directly connected to SR piping or components. In its

February 28, 2005, letter, enclosure 2, “Mechanical Systems,” the applicant stated that

additional piping and components had been added to the scope of the ADHR system; however,

the component types do not differ from those listed in LRA Table 2.3.3.24 and no changes to

the ADHD system portion of the LRA are required.

The staff reviewed the NSR piping up to first equivalent anchor point of seismic Class I piping

boundaries and found the expanded scope of components to be acceptable on the basis that

the applicant had adequately identified all SLC NSR components that meet the scoping criterion

of 10 CFR 54.4(a)(2) for the cases where NSR piping or components are directly connected to

SR piping or components.

2.3.3.24.3 Conclusion

The staff reviewed the LRA and RAI response to determine whether any SSCs that should be

within the scope of license renewal had not been 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 had not been 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 had adequately identified the ADHR system components that are within the scope

of license renewal, as required by 10 CFR 54.4(a), and the ADHR system components that are

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

2.3.3.25 Radioactive Waste Treatment System

2.3.3.25.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.25, the applicant described the radioactive waste treatment system. The

radioactive waste treatment system is comprised of subsystems that process solid and liquid

radwaste that is generated during normal plant operation. The subsystems are plant-shared

systems.

The radioactive waste treatment system contains SR components that are relied upon to

remain functional during, and following, DBEs. The failure of NSR SSCs in the radioactive

waste treatment system could prevent the satisfactory accomplishment of an SR function. In

addition, the radioactive waste treatment system performs functions that support fire protection,

EQ, and SBO.
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The intended functions within the scope of license renewal include the following:

 • provides primary and secondary containment boundaries

 • provides piping interface integrity with the SGT system and the off-gas system in

support of the release of filtered SGT gases through the stack

 • provides a pressure boundary of the radioactive waste treatment system components

connected to the control air system that must maintain a pressure boundary in support

of supplying CAD to the MSRVs

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.3.25, the applicant identified the following radioactive waste treatment system

component types that are within the scope of license renewal and subject to an AMR: bolting,

fittings, heat exchangers, piping, pumps, restricting orifices, tanks, strainers, tubing, and valves.

2.3.3.25.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.25 and UFSAR Sections 4.10, 5.2, 5.3, 9.1, 9.2, 9.3, 9.5,

10.16, F.6.7, F.6.8, F.6.20, and F.7.14 using the evaluation methodology described in SER

Section 2.3. The staff conducted its review in accordance with the guidance described in

SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 order to resolve the 10 CFR 54.4(a)(2) issues regarding NSR piping segments that support

secondary containment discussed in RAI 2.1-2A(1) and (2) of SER Section 2.1, the applicant

expanded the system boundaries for the radioactive waste treatment system. By letter dated

May 31, 2005, the applicant submitted the NSR piping, supports, and other components outside

secondary containment required to maintain the structural integrity of secondary containment

that are within the scope of license renewal in accordance with the requirements of

10 CFR 54.4(a)(2) for secondary containment qualification. In the enclosure to its letter dated

May 31, 2005, the applicant stated that additional piping had been added to scope. However,

the component type does not differ from those listed in LRA Table 2.3.3.25; therefore, no

changes to the radioactive waste treatment system portion of the LRA are required.

The applicant also expanded the system boundaries for the radioactive waste treatment system

to resolve seismic Class I/II interface issues discussed in RAI 2.1-2A(3) of SER Section 2.1. By

letters dated January 31, 2005, and February 28, 2005, the applicant submitted the results of its

review of the seismic Class I qualification documentation to identify the NSR piping,
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supports/equivalent anchors, or other components that are within the scope of license renewal

in accordance with the requirements of 10 CFR 54.4(a)(2) for the (a)(2) cases where NSR

piping or components are directly connected to SR piping or components. In its February 28,

2005 letter, enclosure 2, “Mechanical Systems,” the applicant stated that additional piping and

components were added to the scope in the cleanup decant pump room in the radwaste

building. The component types do not differ from those listed in LRA Table 2.3.3.25; therefore,

no changes to the radioactive waste treatment system portion of the LRA are required. In its

response, the applicant explained that notes had been added to the radioactive waste treatment

drawing to clarify that embedded piping is in scope for anchorage when attached to

non-embedded in-scope piping and all the piping between the embedded piping and in-scope

non-embedded piping is within the scope of license renewal.

The staff reviewed the results of the applicant’s evaluation of NSR piping segments that support

secondary containment in response to RAI 2.1-2A(1) and (2), and the results of the applicant’s

evaluation of seismic Class I piping boundaries in its response to RAI 2.1-2A(3). The staff found

the expanded scope of components to be acceptable, because the applicant had adequately

included NSR components with the configurations that meet the scoping criterion of

10 CFR 54.4(a)(2) for the cases where NSR piping or components are directly connected to SR

piping or components.

2.3.3.25.3 Conclusion

The staff reviewed the LRA and RAI response to determine whether any SSCs that should be

within the scope of license renewal had not been 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 had not been 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 had adequately identified the radioactive waste treatment system components that

are within the scope of license renewal, as required by 10 CFR 54.4(a), and the radioactive

waste treatment system components that are subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.3.3.26 Fuel Pool Cooling and Cleanup System

2.3.3.26.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.26, the applicant described the FPC system. The FPC system removes

residual heat from the fuel assemblies and maintains the fuel pool water within the specified

temperature limits. The system minimizes corrosion product buildup and controls water clarity in

the fuel pool so that the fuel assemblies can be efficiently handled underwater. In addition, the

FPC system minimizes fission product concentration in the fuel pool water. The system is in

normal operation and additional provisions can be made to prevent siphoning of the fuel pool. A

cross-connection exists with the RHR system; the RHR system can provide supplemental

cooling, if needed.

The FPC system contains SR components that are relied upon to remain functional during, and

following, DBEs. The failure of NSR SSCs in the FPC system could prevent the satisfactory
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accomplishment of an SR function. In addition, the FPC system performs functions that support

fire protection.

The intended functions within the scope of license renewal include the following:

 • provides a secondary containment boundary

 • provides for pressure boundary integrity at the RHR/FPC interface

 • prevents inadvertent siphoning of the spent fuel pool

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.3.26, the applicant identified the following FPC system component types that

are within the scope of license renewal and subject to an AMR: bolting, expansion joint, fittings,

heat exchangers, piping, pumps, restricting orifice, tanks, tubing, and valves.

2.3.3.26.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.26 and UFSAR Sections 4.8, 5.3, 10.5, 10.17, and 10.22

using the evaluation methodology described in SER Section 2.3. The staff conducted its review

in accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 order to resolve the 10 CFR 54.4(a)(2) issues discussed in RAI 2.1-2A(1) and (2) of SER

Section 2.1 related to NSR piping segments that support secondary containment, the applicant

expanded the system boundaries for the fuel pool cooling and cleanup system. By letter dated

May 31, 2005, the applicant submitted the results of its review of piping, supports, and other

components outside secondary containment required to maintain the structural integrity of

secondary containment that are within the scope of license renewal in accordance with the

requirements of 10 CFR 54.4(a)(2) for secondary containment qualification. In the enclosure to

its letter dated May 31, 2005, the applicant stated that additional piping had been added to

scope. However, the component type does not differ from those listed in LRA Table 2.3.3.26;

therefore, no changes to the fuel pool cooling and cleanup system portion of the LRA are

required.

The applicant also expanded the system boundaries for the FPC system to resolve the seismic

Class I/II interface issues discussed in RAI 2.1-2A(3) of SER Section 2.1. By letters dated

January 31, 2005, and February 28, 2005, the applicant submitted the results of its review of

the seismic Class I qualification documentation to identify the NSR piping, supports/equivalent

anchors, or other qualification documentation to identify the NSR piping, supports/equivalent

anchors, or other components that are within the scope of license renewal in accordance with

the requirements of 10 CFR 54.4(a)(2) for the (a)(2) cases in which NSR piping or components
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are directly connected to SR piping or components. In the February 28, 2005 letter, enclosure

2, “Mechanical Systems,” the applicant stated that additional piping and components had been

added to the scope of the FPC system. However, the component types do not differ from those

listed in LRA Table 2.3.3.26; therefore, no changes to the FPC system portion of the LRA are

required.

The staff reviewed the results of the applicant’s evaluation of NSR piping segments that support

secondary containment in response to RAI 2.1-2A(1) and (2), and the results of the applicant’s

evaluation of seismic Class I piping boundaries in its response to RAI 2.1-2A(3). The staff found

the expanded scope of components to be acceptable, because the applicant had adequately

included NSR components with the configurations that meet the scoping criterion of

10 CFR 54.4(a)(2) for the cases where NSR piping or components are directly connected to SR

piping or components.

2.3.3.26.3 Conclusion

The staff reviewed the LRA and RAI response to determine whether any SSCs that should be

within the scope of license renewal had not been 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 had not been 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 had adequately identified the FPC system components that are within the scope

of license renewal, as required by 10 CFR 54.4(a), and the FPC system components that are

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

2.3.3.27 Fuel Handling and Storage System

2.3.3.27.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.27, the applicant described the fuel handling and storage system. Each

unit is provided with a dry, new fuel storage vault. The new fuel storage racks provide a location

in the vaults where new fuel can be stored. The racks are designed to preclude criticality even if

the new fuel storage vault is flooded. Each reactor also has a spent fuel storage pool. A transfer

canal is provided to join the pools for Units 1 and 2. The spent fuel storage racks provide a

location where spent fuel, received from the reactor vessel, can be stored at the bottom of each

fuel pool. The racks are full length, top entry, and are designed to maintain the spent fuel in a

spatial geometry that precludes the possibility of criticality. The racks are comprised of

staggered, stainless-steel container tubes. Each tube wall has a core of Boral sandwiched

within stainless steel. Servicing equipment is provided to facilitate refueling, fuel inspection, and

fuel maintenance.

The fuel handling and storage system contains SR components that are relied upon to remain

functional during, and following, DBEs. The failure of NSR SSCs in the fuel handling and

storage system could prevent the satisfactory accomplishment of an SR function. 
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The intended functions within the scope of license renewal include the following:

 • provides NSR components that ensure the satisfactory performance of SR components

 • provides structural support

In LRA Table 2.3.3.27, the applicant identified the following fuel handling and storage system

component types that are within the scope of license renewal and subject to an AMR: bolting

and fasteners, fuel preparation machines, and the refueling platform (including the assembly,

rails, and main fuel grapple).

2.3.3.27.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.27 and UFSAR Sections 10.2, 10.3, 10.4, and 10.5 using

the evaluation methodology described in SER Section 2.3. The staff conducted its review in

accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 reviewing LRA Section 2.3.3.27, the staff identified an area in which additional information

was necessary to complete the evaluation of the applicant’s scoping and screening results.

Therefore, by letter to the applicant dated August 31, 2004, the staff issued an RAI concerning

the specific issue to determine whether the applicant had properly applied the scoping criteria of

10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs

describe the staff’s RAI and the applicant’s related response.

In RAI 2.3.3.27-1, the staff stated that LRA Section 2.3.3.27 states that the portions of the fuel

handling and storage system that contain components subject to an AMR are the fuel

preparation machines, refueling platform (assembly, rails, and the main fuel grapple), and the

bolting and fasteners associated with the refueling platform and fuel preparation machines. LRA

Table 2.3.3.27 lists components associated with the fuel handling and storage systems that are

subject to an AMR. UFSAR Section 10.4 (in Table 10.4-1, “Tools and Servicing Equipment”)

lists fuel servicing equipment, including general purpose grapple, channel transfer grapple, fuel

inspection fixture, and new fuel inspection stand, but none of these are referenced in LRA

Section 2.3.3.27. In reviewing LRA Section 2.3.3.27, the staff also found that no drawings are

provided for this system. There is insufficient information for the staff to determine whether

these components are within the scope of license renewal and subject to an AMR. Therefore,

the staff requested that the applicant identify which of these components are within the scope of

license renewal and subject to an AMR.

In its response, by letter dated October 19, 2004, the applicant stated the general purpose

grapple, channel transfer grapple, and fuel inspection fixture are within the scope of license

renewal; however, an AMR is not required for these components since they are active (i.e., they

change configuration). The applicant also stated that the new fuel inspection stand is not SR
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and does not meet the criterion in 10 CFR 54.4(a)(1). The new fuel inspection stand is also not

required for any of the 10 CFR 54.4(a)(3) regulated events. The applicant further stated that the

new fuel inspection stand failure would not prevent the accomplishment of an SR intended

function of an SR component and does not meet the requirements of 10 CFR 54.4(a)(2). 

Based on its review, the staff found the applicant’s response to RAI 2.3.3.27-1 acceptable. The

applicant had adequately clarifies that the components in question are either active or do not

meet any of the requirements of 10 CFR 54.4(a). Therefore, the staff’s concern described in

RAI 2.3.3.27-1 is resolved.

2.3.3.27.3 Conclusion

The staff reviewed the LRA and RAI response described above to determine whether any SSCs

that should be within the scope of license renewal had not been 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 had not been 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 had adequately identified the fuel handling and storage

system components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the fuel handling and storage system components that are subject to an

AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.28 Diesel Generator System

2.3.3.28.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.28, the applicant described the diesel generator (DG) system. The DG

system is a plant-shared system that consists of four independent DG units, coupled as an

alternate independent source of power to four 4160 V shared shutdown boards for

Units 1 and 2. There are four additional DG units that provide an alternate independent source

of power to four Unit 3 4160 V shutdown boards. The DG system provides an alternate source

of power for the ECCS and the safe shutdown systems when the normal power supplies are

unavailable. The DGs are normally in standby and can start automatically, when required.

The DG system contains SR components that are relied upon to remain functional during, and

following, DBEs. The failure of NSR SSCs in the DG system could prevent the satisfactory

accomplishment of an SR function. In addition, the DG system performs functions that support

fire protection, EQ, and SBO.

The intended functions within the scope of license renewal include the following:

 • starts standby AC power source for the 4kV system

 • provides power to the 4kV system upon DG availability and loss of offsite power

 • provides DG power to diesel fuel transfer pumps

 • provides debris protection

 • provides for heat transfer
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 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.3.28, the applicant identified the following DG system component types that

are within the scope of license renewal and subject to an AMR: bolting, ductwork, fan housings,

fittings, flexible connectors, heat exchangers, heaters, piping, pumps, silencer, strainers, tanks,

tubing, valves, and RCPB valves.

2.3.3.28.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.28 and UFSAR, Sections 7.4, 7.18, 8.4, 8.5, 8.10, and

F.7.9 using the evaluation methodology described in SER Section 2.3. The staff conducted its

review in accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 reviewing LRA Section 2.3.3.28, the staff identified an area in which additional information

was necessary to complete the evaluation of the applicant’s scoping and screening results.

Therefore, by letter to the applicant dated August 31, 2004, the staff issued an RAI concerning

the specific issue to determine whether the applicant had properly applied the scoping criteria of

10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs

describe the staff’s RAI and the applicant’s response.

In RAI 2.3.3.28-1, the staff identified two components (governor and drain pan) in the DG lube

oil subsystem that are not subject to an AMR; however, the piping into and out of these

components is subject to an AMR. Therefore, the staff requested that the applicant justify the

exclusion of the subject components from within the scope of license renewal and an AMR.

In its response, by letter dated October 19, 2004, the applicant stated that the governor is a

controller that is an active component based on components listed in Appendix B of NEI 95-10,

Revision 3, and does not require an AMR. With regard to the drain pan, the applicant stated

that the drain pan is not within the scope of license renewal since it does not perform a

10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(3) function. The drain pan would also not be in scope for

10 CFR 54.4(a)(2) since it is not normally fluid-filled and does not present a spray hazard.

During a teleconference on May 11, 2005, the applicant clarified that the drain pan is attached

to the DG frame and is not in any way attached to or functionally associated with the lube oil

system. Its only purpose is to collect any spillage during maintenance when replacing the oil

filter. Additionally, the piping, valves, and fittings attached to the drain pan, as shown in the

license renewal drawings 0-47E861-5-LR through 0-47E861-8-LR and 3-47E861-5-LR through

3-47E861-8-LR, were inadvertently colored as being within the scope of license renewal and

subject to an AMR. These drawings have been revised to reflect that these valves, piping, and
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fittings are not within the scope of license renewal and not subject to an AMR. The changes will

be incorporated in the next annual update. 

Based on its review, the staff found the applicant’s response to RAI 2.3.3.28-1 acceptable. It

justified the exclusion of the governor from an AMR. The applicant also clarifies that the piping,

valves, and fittings attached to the drain pan had been colored inadvertently and that the drain

pan does not perform a license renewal intended function per 10 CFR 54.4. Therefore, the

staff’s concern described in RAI 2.3.3.28-1 is resolved. 

2.3.3.28.3 Conclusion

The staff reviewed the LRA, the accompanying scoping boundary drawings, and RAI response

described above to determine whether any SSCs that should be within the scope of license

renewal had not been 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 had not been 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 had

adequately identified the DG system components that are within the scope of license renewal,

as required by 10 CFR 54.4(a), and the DG system components that are subject to an AMR, as

required by 10 CFR 54.21(a)(1).

2.3.3.29 Control Rod Drive System

2.3.3.29.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.29, the applicant described the CRD system. The CRD system provides

reactivity control by allowing positioning of the control rods at a controlled rate during normal

operation; providing scram and diverse scram functions to ensure rapid shutdown, when

required; limiting the rod drop rate to minimize the consequences of a rod drop accident; and

limiting a rod ejection accident.

From the hydraulic control units, the portions of the system that are subject to an AMR extend

to, and from, each control rod housing. From the hydraulic control units, the portions of the

system that are subject to an AMR extend to, and then include, the scram discharge volume

and associated components. From the hydraulic control units, portions of the system subject to

an AMR extend to an interconnection with the RWCU system. The CRDs themselves are

short-lived components and, hence, are not subject to an AMR; however, the CRD housing

support is subject to an AMR and is included in the component supports commodity group,

which is discussed in another section of this SER.

The CRD system contains SR components that are relied upon to remain functional during, and

following, DBEs. The failure of NSR SSCs in the CRD system could prevent the satisfactory

accomplishment of an SR function. In addition, the CRD system performs functions that support

fire protection, EQ, ATWS, and SBO.
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The intended functions within the scope of license renewal include the following:

 • provides primary and secondary containment boundaries

 • provides RCPB

 • provides housing support to keep the rods in place

 • limits the rod drop rate to less than 3.11 feet per second

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.3.29, the applicant identified the following CRD system component types that

are within the scope of license renewal and subject to an AMR: bolting, fittings, RCPB fittings,

heat exchangers, piping, RCPB piping, pumps, restricting orifice, rupture disk, strainers, RCPB

strainers, tanks, tubing, valves, and RCPB valves.

2.3.3.29.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.29 and UFSAR Sections 3.4, 3.5, 3.7, 5.2.3, 5.3, 7.7,

7.19, and F.7.12 using the evaluation methodology described in SER Section 2.3. The staff

conducted its review in accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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).

2.3.3.29.3 Conclusion

The staff reviewed the LRA to determine whether any SSCs that should be within the scope of

license renewal had not been 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 had not been 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

had adequately identified the CRD system components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and the CRD system components that are subject to

an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.30 Diesel Generator Starting Air System

2.3.3.30.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.30, the applicant described the DG starting air system. The DG starting air

system starts the DGs when required. Each DG has an independent starting air system. Each

system has two independent subsystems that are both capable of starting their respective DG.

Each subsystem consists of an air compressor with associated filters and coolers, and a bank
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of air receivers. The air compressors operate automatically to maintain the receivers in a

pressurized state. The DG starting air system is located in the DG buildings.

The DG starting air system contains SR components that are relied upon to remain functional

during, and following, DBEs. In addition, the DG starting air system performs functions that

support fire protection and SBO.

The intended functions within the scope of license renewal include the following:

 • provides diesel starting air to the DG system

 • provides debris protection

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.3.30, the applicant identified the following DG starting air system component

types that are within the scope of license renewal and subject to an AMR: bolting, diesel air

start motor, fittings, flexible connectors, piping, strainers, tanks, tubing, and valves.

2.3.3.30.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.30 and UFSAR Section 8.5.3.3 using the evaluation

methodology described in SER Section 2.3. The staff conducted its review in accordance with

the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 order to resolve the seismic Class I/II interface issues discussed in RAI 2.1-2A(3) of SER

Section 2.1, the applicant expanded the system boundaries for the diesel generator starting air

system. By letters dated January 31, 2005, and February 28, 2005, the applicant submitted the

results of its review of the seismic Class I qualification documentation to identify the NSR

piping, supports/equivalent anchors, or other components that are within the scope of license

renewal in accordance with the requirements of 10 CFR 54.4(a)(2) for the cases where NSR

piping or components are directly connected to SR piping or components. In the February 28,

2005 letter, enclosure 2, “Mechanical Systems,” the applicant stated that additional piping and

components had been added to scope in association with the outlet filter of the air dryer skid,

which is credited as an anchor in the seismic analysis. However, the component types do not

differ from those listed in LRA Table 2.3.3.30; therefore, no changes to the diesel generator

starting air system portion of the LRA are required. The staff reviewed applicant’s submittals

and found the expanded scope of components to be acceptable, because the applicant had

adequately included NSR components with the configurations that meet the scoping criterion of

10 CFR 54.4(a)(2) for the cases where NSR piping or components are directly connected to SR

piping or components. 
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2.3.3.30.3 Conclusion

The staff reviewed the LRA and RAI response to determine whether any SSCs that should be

within the scope of license renewal had not been 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 had not been 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 had adequately identified the DG starting air system components that are within

the scope of license renewal, as required by 10 CFR 54.4(a), and the DG starting air system

components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.31 Radiation Monitoring System

2.3.3.31.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.31, the applicant described the radiation monitoring system. The radiation

monitoring system consists of a number of radiation monitors and monitoring systems that are

provided on process liquid and gas lines that may serve as discharge routes for radioactive

materials.

The radiation monitoring system contains SR components that are relied upon to remain

functional during, and following, DBEs. The failure of NSR SSCs in the radiation monitoring

system could prevent the satisfactory accomplishment of an SR function. In addition, the

radiation monitoring system performs functions that support EQ.

The intended functions within the scope of license renewal include the following:

 • provides primary and secondary containment boundaries

 • provides system pressure boundary integrity (with all mechanical joints and components

associated with the offline liquid monitors) to RHRSW system cooling water for RHR

system heat exchangers

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.3.31, the applicant identified the following radiation monitoring system

component types that are within the scope of license renewal and subject to an AMR: bolting,

fittings, flex hose, piping, pumps, strainers, traps, tubing, and valves.

2.3.3.31.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.31 and UFSAR Sections 5.2.3, 7.12, 7.13,

7.14, 7.15, and F.7.5 using the evaluation methodology described in SER Section 2.3. The staff

conducted its review in accordance with the guidance described in SRP-LR Section 2.3.
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In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 reviewing LRA Section 2.3.3.31, the staff identified an area in which additional information

was necessary to complete the evaluation of the applicant’s scoping and screening results.

Therefore, by letter to the applicant dated August 31, 2004, the staff issued an RAI concerning

the specific issue to determine whether the applicant had properly applied the scoping criteria of

10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs

describe the staff’s RAI and the applicant’s response.

In RAI 2.3.3.31-1, the staff identified the following monitors as being subject to an AMR:

 • gas monitors

 • RHR heat exchanger A & C service water discharge radiation monitor 

 • RHR heat exchanger B & D service water discharge radiation monitor 

 • raw cooling water radiation monitor

 • reactor building closed cooling water radiation monitor

The monitor housing performs a pressure boundary intended function; however, the housing is

not listed in LRA Table 2.3.3.31 as a component type subject to an AMR. LRA Section 2.3.5

does not include housing as a part of any component group. Therefore, the staff requested that

the applicant clarify whether housings are considered to be part of a component group already

listed in LRA Table 2.3.3.31.

In its response, by letter dated October 19, 2004, the applicant stated that the radiation monitor

sample chambers (housings) are included as part of the component type “fittings” in LRA

Table 2.3.3.31. 

Based on its review, the staff found the applicant’s response to RAI 2.3.3.31-1 acceptable. It

clarifies that the monitor housings are already included in LRA Table 2.3.3.31 in the component

type “fittings” as being subject to an AMR. Therefore, the staff’s concern described in

RAI 2.3.3.31-1 is resolved.

In order to resolve the 10 CFR 54.4(a)(2) issues discussed in RAI 2.1-2A(1) and (2) of SER

Section 2.1 related to NSR piping segments that support secondary containment, the applicant

expanded the system boundaries for the radiation monitoring system. By letter dated May 31,

2005, the applicant submitted the results of its review of piping, supports, and other

components outside secondary containment required to maintain the structural integrity of

secondary containment that are within the scope of license renewal in accordance with the

requirements of 10 CFR 54.4(a)(2) for secondary containment qualification. In the enclosure to

its letter dated May 31, 2005, the applicant stated that additional components associated with

radiation monitor RM 90-250 had been added to scope. However, the component types do not

differ from those listed in LRA Table 2.3.3.31; therefore, no changes to the radiation monitoring

system portion of the LRA are required. The staff reviewed applicant’s submittal and found the
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expanded scope of components to be acceptable, because the applicant had adequately

included NSR components with the configurations that meet the scoping criterion of

10 CFR 54.4(a)(2) for the cases where NSR piping or components are directly connected to SR

piping or components.

2.3.3.31.3 Conclusion

The staff reviewed the LRA and RAI responses described above to determine whether any

SSCs that should be within the scope of license renewal had not been 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 had not been 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 had adequately identified the radiation

monitoring system components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the radiation monitoring system components that are subject to an AMR,

as required by 10 CFR 54.21(a)(1).

2.3.3.32 Neutron Monitoring System

2.3.3.32.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.32, the applicant described the neutron monitoring system. The neutron

monitoring system detects conditions in the core that threaten the overall integrity of the fuel

barrier due to excessive power generation. The system also provides signals to the reactor

protection system so that the release of radioactive material from the fuel barrier is limited. In

addition, the neutron monitoring system provides information for the efficient, expeditious

operation and control of the reactor. Conditions that could lead to local fuel damage are

detected by the system and used to prevent such damage. 

The neutron monitoring system contains SR components that are relied upon to remain

functional during, and following, DBEs. 

The intended functions within the scope of license renewal include the following:

 • provides RCPB

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.3.32, the applicant identified the following neutron monitoring system

component types that are within the scope of license renewal and subject to an AMR: bolting

and RCPB fittings.

2.3.3.32.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.32 and the UFSAR Sections 3.7 and 7.5 using the

evaluation methodology described in SER Section 2.3. The staff conducted its review

in accordance with the guidance described in the NRC’s SRP-LR Section 2.3.
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In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in

accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not omitted

from the scope of license renewal any components with intended functions delineated under

10 CFR 54.4(a). The staff then reviewed those components that the applicant 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 reviewing LRA Section 2.3.3.32, the staff identified an area in which additional information

was necessary to complete the evaluation of the applicant’s scoping and screening results.

Therefore, by letter to the applicant dated October 8, 2004, the staff issued an RAI concerning

the specific issues to determine whether the applicant had properly applied the scoping criteria

of 10 CFR 54.4 (a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs

describe the staff’s RAIs and the applicant’s related responses.

In RAI 2.3.3.32-1, the staff stated that LRA Section 2.3.3.32 states that the average power

range monitor subsystem averages the local power range monitor subsystem signals to provide

an overall indication of reactor power for control and trip functions. A subsystem of the average

power range monitor subsystem, the oscillation power range monitor (OPRM) ensures reactor

operation in a stable thermal-hydraulic region. The rod block monitor (RBM) receives input from

local power range monitors close to a control rod to prevent fuel damage in the event of a rod

withdrawal error. Furthermore, it was stated in the LRA that the portions of the neutron

monitoring system that contain components subject to an AMR are only those that form part of

the reactor coolant pressure boundary. The staff believes that in addition to the portions that

are pressure boundary, OPRM and its functions, as described above, are passive and SR; and

hence meet the criteria delineated in 10 CFR 54.4(a)(1) and 10 CFR 54.21(a)(1). Therefore,

unless the OPRM is subject to replacement based on a "qualified life" or "specified time period,"

or degradation of its ability to perform its intended functions due to aging is readily monitorable,

the component should be within the scope requiring aging management. Therefore, the staff

requested the applicant to provide a justification for why these components are not within the

scope of license renewal. 

The staff also requested the applicant to provide the basis for excluding other neutron

monitoring subsystems in BFN (except portions that perform pressure boundary function) from

within the scope of license renewal.

In its response, by letter dated November 3, 2004, the applicant stated that LRA Section 2.3

lists the mechanical scoping and screening results. The only mechanical SR passive intended

function of the neutron monitoring system is reactor coolant pressure boundary. The scoping

and screening results for the electrical components of the neutron monitoring system are

addressed in LRA Section 2.5. The applicant further stated that the “spaces approach” was

utilized for scoping of electrical components, which does not exclude any electrical components

from the scope of license renewal. The applicant included the subject components and its

intended functions within the scope requiring an AMR. 

Based on its review, the staff found the applicant’s response to RAI 2.3.3.32-1 acceptable. The

applicant included the subject components and their intended functions within the scope

requiring an AMR. Therefore, the staff’s concern described in RAI 2.3.3.32-1 is resolved.
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2.3.3.32.3 Conclusion

The staff reviewed the LRA and RAI response described above to determine whether any SSCs

that should be within the scope of license renewal had not been 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 had not been 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 had adequately identified the neutron monitoring

system components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the neutron monitoring system components that are subject to an AMR, as

required by 10 CFR 54.21(a)(1).

2.3.3.33 Traversing In-Core Probe System

2.3.3.33.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.33, the applicant described the traversing in-core probe (TIP) system. The

TIP system provides a signal proportional to the axial flux distribution at selected core

locations where the local power range monitor detector assemblies are located. This signal

allows reliable calibration of the power range monitor amplifiers. The TIP drive mechanism uses

a detector that is attached to a flexible drive cable, which is driven from outside the primary

containment by a gear box assembly. The flexible cable is contained by guide tubes that

penetrate the reactor vessel and continue into the reactor core through a dry tube in a local

power range monitor assembly. Provisions are made for automatic retraction of the detection

and isolation of the primary containment penetration, when required.

The TIP system contains SR components that are relied upon to remain functional during, and

following, DBEs. 

The intended functions within the scope of license renewal include the following:

 • provides primary containment boundary isolation and integrity (active isolation function

is not required)

 • provides pressure boundary

In LRA Table 2.3.3.33, the applicant identified the following TIP system component types that

are within the scope of license renewal and subject to an AMR: fittings, tubing, and valves.

2.3.3.33.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.33 and the UFSAR 5.2.3, 7.3, and 7.5 using the

evaluation methodology described in SER Section 2.3. The staff conducted its review

in accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR in

accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not omitted

from the scope of license renewal any components with intended functions delineated under

10 CFR 54.4(a). The staff then reviewed those components that the applicant had identified as
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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).

2.3.3.33.3 Conclusion

The staff reviewed the LRA to determine whether any SSCs that should be within the scope of

license renewal had not been 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 had not been 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

had adequately identified the TIP system components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and the TIP system components that are subject to an

AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.34 Cranes System

2.3.3.34.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.34, the applicant described the cranes system. The cranes system

includes numerous plant load-handling devices that are used for maintenance of selected plant

components.

The portions of the cranes system containing components subject to an AMR include the

structural portions of the cranes in structures with SR components.

The failure of SR SSCs in the cranes system could prevent the satisfactory accomplishment of

an SR function. 

The intended functions within the scope of license renewal include the following:

 • provides NSR components that ensure the satisfactory performance of SR components

 • provides structural support

In LRA Table 2.3.3.34, the applicant identified the following cranes system component types

that are within the scope of license renewal and subject to an AMR: bolting and fasteners,

monorails, rail, rail clips, and structural girders.

2.3.3.34.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.34 and UFSAR Section 12.2 using the evaluation

methodology described in SER Section 2.3. The staff conducted its review in accordance with

the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant
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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 reviewing LRA Section 2.3.3.34, the staff identified an area in which additional information

was necessary to complete the evaluation of the applicant’s scoping and screening results.

Therefore, by letter to the applicant dated August 31, 2004, the staff issued an RAI concerning

the specific issue to determine whether the applicant had properly applied the scoping criteria of

10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs

describe the staff’s RAI and the applicant’s related response.

In RAI 2.3.3.34-1, the staff stated that in reviewing the cranes system described in LRA

Section 2.3.3.34, the staff found that no drawings had been provided for this system. There is

insufficient information for the staff to determine which cranes are within the scope of license

renewal in accordance with 10 CFR 54.4(a)(2). In addition, mobile A-frames mentioned in LRA

Section 2.1.2.2 are not mentioned in LRA Section 2.3.3.34 or in the UFSAR. Therefore, the

staff requested that the applicant identify which cranes are within the scope of license renewal

and subject to an AMR, and whether the mobile A-frames are within the scope of license

renewal.

In its response, by letter dated October 19, 2004, the applicant stated that the buildings that

contain NSR cranes and monorails that could prevent SR SSCs from performing their intended

function(s) are the reactor building, primary containment, DG building, intake pumping station,

and the reinforced concrete chimney. All cranes and monorails in these buildings are within the

scope of license renewal. The applicant further stated that the mobile A-frames are cranes on

wheels. These A-frames are within the scope of license renewal since they could be used in an

SR building, they are also subject to an AMR.

Based on its review, the staff found the applicant’s response to RAI 2.3.3.34-1 acceptable. It

identifies the buildings containing the cranes that are within the scope of license renewal to

meet the 10 CFR 54.4(a)(2) requirements, and it confirms that the mobile A-frames are within

the scope of license renewal and subject to an AMR. Therefore, the staff’s concern described in

RAI 2.3.3.34-1 is resolved.

2.3.3.34.3 Conclusion

The staff reviewed the LRA and RAI response described above to determine whether any SSCs

that should be within the scope of license renewal had not been 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 had not been 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 had adequately identified the cranes system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the cranes system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
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2.3.4 Steam and Power Conversion Systems

In LRA Section 2.3.4, the applicant identified the structures and components of the steam and

power conversion systems that are subject to an AMR for license renewal.

The applicant described the supporting structures and components of the steam and power

conversion systems in the following sections of the LRA:

 • 2.3.4.1 main steam system

 • 2.3.4.2 condensate and demineralized water system

 • 2.3.4.3 feedwater system

 • 2.3.4.4 heater drains and vents system

 • 2.3.4.5 turbine drains and miscellaneous piping system

 • 2.3.4.6 condenser circulating water system

 • 2.3.4.7 gland seal water system

The corresponding sections of this SER (2.3.4.1 – 2.3.4.7) present the staff’s review findings

with respect to the steam and power conversion systems for BFN.

2.3.4.1 Main 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 MS system. Each unit has its own MS

system that consists of four MS lines that transfer steam from the reactor vessel to the various

steam loads in the turbine building during normal plant operation. Two MSIVs are provided in

each steam line to isolate the RCPB and the primary containment. A flow restrictor allows for

the measurement of steam flow and also limits the steam flow rate in the event of a

downstream steam line break. MSRVs are provided for overpressure protection and for

depressurization following small-break LOCAs. Main steam components downstream of the

MSIVs are credited in analyses for MSIV alternate leakage treatment.

The MS system contains SR components that are relied upon to remain functional during, and

following, DBEs. The failure of NSR SSCs in the MS system could prevent the satisfactory

accomplishment of an SR function. In addition, the MS system performs functions that support

fire protection, EQ, and SBO.

The intended functions within the scope of license renewal include the following:

 • provides for opening of safety relief valves (SRVs) during high reactor pressure to

provide reactor pressure vessel relief

 • provides MS line flow restrictors to passively limit the mass flow rate of the coolant being

ejected following a steam-line break until MSIV closure occurs

 • provides RCPB

 • provides primary and secondary containment boundaries

 • provides steam for the HPCI turbine
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 • establishes an MSIV leakage pathway to the condenser

 • provides steam for the RCIC turbine

 • restricts flow

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.4.1, the applicant identified the following MS system component types that are

within the scope of license renewal and subject to an AMR: bolting, fittings, RCPB fittings,

piping, RCPB piping, restricting orifice, RCPB restricting orifice, strainers, tubing, valves, and

RCPB valves.

2.3.4.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.1 and UFSAR Sections 3.7, 4.1, 4.4, 4.5, 4.6, 4.11, 5.2.3,

5.3, 6.4.2, 7.2, 7.3, 7.4, 7.10, 7.11, 7.12, 7.18, 11.2, and 11.5 using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 reviewing LRA Section 2.3.4.1, the staff identified areas in which additional information was

necessary to complete the evaluation of the applicant’s scoping and screening results.

Therefore, by letter to the applicant dated October 8, 2004, the staff issued RAIs concerning

the specific issues to determine whether the applicant had properly applied the scoping criteria

of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs

describe the staff’s RAIs and the applicant’s related responses.

In RAI F 2.3.4.1-1, the staff stated that 0roviding a leakage pathway from the MSIVs to the

main condenser is one of the intended functions of the main steam system. Regarding Unit 1,

LRA Appendix F states that the segment of the main steam piping from the outermost isolation

valve up to the turbine stop valve, the bypass/drain piping to the main condenser and the main

condenser itself is being evaluated and modified as required to ensure that structural integrity

during and after a safe shutdown earthquake (SSE) is maintained. The staff identified that

portions of the main steam system (from the turbine building on) are not shown on license

renewal drawing 1-47E801-1-LR as being subject to an AMR. However, similar segments of

piping are shown as being subject to an AMR on license renewal drawings 2-47E801-1-LR and

3-47E801-1-LR. It is not clear to the staff, on the basis of a review of the drawings and the

information provided in LRA Sections 2.1 and F.1 of Appendix F, why the sections of piping on

license renewal drawing 1-47E801-1-LR are not subject to an AMR. Therefore, the staff
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requested that the applicant justify the exclusion of the piping sections in question from being

within the scope of license renewal and from being subject to an AMR.

In its response, by letter dated October 25, 2004, the applicant stated that license renewal

drawings depict components subject to an AMR based on the units’ CLB. As documented in

Appendix F.1 of the LRA, the Unit 1 CLB for MSIV leakage does not incorporate an alternate

leakage treatment pathway utilizing main steam piping and the main condenser because

currently this modification is not physically implemented for Unit 1 to match Units 2 and 3 in

their configuration. 

The LRA was structured to reflect the configuration and CLB of all three units. Scoping and

screening was done based on the CLB and configuration of all three units. The differences

between the units that are relevant to the application and will be resolved prior to Unit 1 restart

are listed in LRA Appendix F. 

In addition, by letter dated January 31, 2005, the applicant provided additional/supplementary

information, stating that as each activity identified in Appendix F is completed, the

corresponding bold-bordered text in the LRA will apply to Unit 1. The applicant stated in its

response that the only change to the application will be to remove the bolded border. No

changes are required for scoping and screening, or AMR results, or TLAAs. However, in some

cases, boundary drawings would change to reflect the bold-bordered text. The applicant

committed to perform a secondary application review after the modification is implemented in

the plant for Unit 1, and license renewal drawing 1-47E801-1-LR will be revised and submitted

during the annual update. This will assure that the design changes that implement this

modification do not modify or change the basis of how these components were initially scoped

and screened.

Based on its review, the staff found the applicant's response to RAI F 2.3.4.1-1 acceptable. The

Unit 1 CLB for MSIV leakage does not incorporate an alternate leakage treatment pathway

utilizing the main steam piping and main condenser and, therefore, this portion of piping is not

subject to an AMR at this time. Upon completion of the modifications discussed in LRA

Appendix F and the January 31, 2005, letter, the CLB for Unit 1 will be the same as Units 2 and

3. The review of LRA Appendix F regarding Unit 1 restart will be addressed in SER

Section 2.6.1.1. Therefore, the staff's concern described in RAI F 2.3.4.1-1 is resolved.

In RAI F 2.3.4.1-2, the staff stated that license renewal drawings 2-47E801-2, 2-47E807-2,

3-47E801-2, and 3-47E807-2 highlight certain main steam system components for Units 2 and

3 associated with the reactor feed pump turbine drivers, the steam air ejector subsystem, and

the steam seal regulator subsystem as being within the scope of license renewal and subject to

an AMR. The corresponding components for Unit 1 should likewise be subject to an AMR.

However, the drawings that show these components, such as license renewal drawings

1-47E801-2 (shown as a continuation line on drawing 1-47E801-1) and 2-47E807-2 and

3-47E807-2 (the corresponding drawings for Unit 1) are not provided. As a result, the staff was

unable to determine if all of the aforementioned Unit 1 components, that are within the scope of

license renewal and subject to an AMR for Units 2 and 3 were identified. Therefore, the staff

requested that the applicant provide license renewal drawing 1-47E801-2 and the Unit 1

drawing that corresponds to drawings 2-47E807-2 and 3-47E807-2.
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In its response, by letter dated October 25, 2004, the applicant stated that the license renewal

drawings depict components subject to an AMR based on the units' CLB. As documented in

LRA Appendix F.1, the Unit 1 CLB for MSIV leakage does not incorporate an alternate leakage

treatment pathway utilizing the main steam piping and main condenser. Appendix F.1 identifies

the activities required to be completed in order to make the subject licensing basis applicable to

Unit 1. Since activities required by LRA Appendix F.1 are not complete, the piping/components

of the subject system are not subject to an AMR at this time.

The applicant further stated that at this time the modification to implement this change into the

plant for Unit 1 has not been implemented. Therefore, the piping for Unit 1 does not perform the

alternate leakage pathway function. The applicant further stated that once the modification has

been implemented in the plant, Unit 1 license renewal drawings addressed in the RAI will be

added to the application and submitted during the annual update with the same components on

Unit 1 requiring an AMR as those shown on the Unit 2 and Unit 3 license renewal drawings.

Based on its review, the staff found the applicant's response to RAI 2.3.4.1-2 acceptable. It

clarifies that the Unit 1 CLB for MSIV leakage does not incorporate an alternate leakage

treatment pathway utilizing main steam piping and the main condenser since the activities

(identified in LRA Appendix F.1) required to make the Unit 1 CLB for MSIV leakage the same

as that for Units 2 and 3 is not subject to an AMR at this time. The applicant also clarifies that

once the modification is implemented, Unit 1 license renewal drawings will be submitted with

the same components on Unit 1 that require an AMR as those shown on the Unit 2 and Unit 3

license renewal drawings. The review of LRA Appendix F regarding Unit 1 restart will be

addressed in SER Section 2.6.1.1. Therefore, the staff's concern described in RAI 2.3.4.1-2 is

resolved.

In order to resolve the 10 CFR 54.4(a)(2) issues discussed in RAI 2.1-2A(1) and (2) of SER

Section 2.1 related to NSR piping segments which support secondary containment, the

applicant expanded the system boundaries for the main steam system. By letter dated May 31,

2005, the applicant submitted the results of its review of piping, supports, and other

components outside secondary containment required to maintain the structural integrity of

secondary containment that are within the scope of license renewal in accordance with the

requirements of 10 CFR 54.4(a)(2) for secondary containment qualification. In the enclosure to

its letter dated May 31, 2005, the applicant stated that additional piping, fittings, and valves had

been added to scope. However, the component types do not differ from those listed in LRA

Table 2.3.4.1; therefore, no changes to the main steam system portion of the LRA are required.

The staff reviewed the NSR piping segments and found the expanded scope of components to

be acceptable, because the applicant had adequately included NSR components with the

configurations that meet the scoping criterion of 10 CFR 54.4(a)(2) for the cases where NSR

piping or components are directly connected to SR piping or components

2.3.4.1.3 Conclusion

The staff reviewed the LRA, the accompanying scoping boundary drawing, and RAI responses

described above to determine whether any SSCs that should be within the scope of license

renewal had not been 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 had not been identified by the applicant. No omissions were identified. On the basis of its
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review, the staff concluded that there is reasonable assurance that the applicant had

adequately identified the MS system components that are within the scope of license renewal,

as required by 10 CFR 54.4(a), and the MS system components that are subject to an AMR, as

required by 10 CFR 54.21(a)(1).

2.3.4.2 Condensate and Demineralized Water System

2.3.4.2.1 Summary of Technical Information in the Application

In LRA Section 2.3.4.2, the applicant described the condensate and demineralized water

system. The main system is the condensate system which provides treated water at required

flow rates for the FW system during normal plant operation. The system is unique to each unit

and the individual systems do not share components with one another. The turbine-generator

condenser provides a heat sink for the closed-loop steam cycle and removes non-condensable

gases. In addition, impurities are removed by a full-flow demineralizer system. The system also

cools the steam jet air ejector intercondenser, the off-gas condenser, and the steam packing

exhauster condenser. The condenser is credited in analyses for MSIV alternate leakage

treatment.

Subsystems of the condensate system are the condensate storage and transfer system, for

radioactive high purity water, and the demineralized water system, for non-radioactive high

purity water. The tanks also provide a surge volume for flow testing of HPCI, RCIC, and CS

systems. The condensate water storage tanks and the demineralized water storage tank

provide high purity water for miscellaneous makeup uses throughout the plant, which includes

the reactor building.

The condensate and demineralized water system contains SR components that are relied upon

to remain functional during, and following, DBEs. The failure of NSR SSCs in the condensate

and demineralized water system could prevent the satisfactory accomplishment of an SR

function. In addition, the condensate and demineralized water system performs functions that

support fire protection, and SBO.

The intended functions within the scope of license renewal include the following:

 • provides a normally open water supply to the RHR system piping flow path, which

continues to the HPCI system piping that is located up-stream of the HPCI system pump

 • provides primary and secondary containment boundaries

 • provides a water supply for both HPCI and RCIC systems during an SBO 

 • retains fission products by plateout on a surface

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support
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In LRA Table 2.3.4.2, the applicant identified the following condensate and demineralized water

system component types that are within the scope of license renewal and subject to an AMR:

bolting, condenser, expansion joint, fittings, piping, pumps, restricting orifice, tanks, tubing, and

valves.

2.3.4.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.2 and UFSAR Sections 10.13, 11.8, 11.9, F.6.10, and

F.6.18 using the evaluation methodology described in SER Section 2.3. The staff conducted its

review in accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 order to resolve the 10 CFR 54.4(a)(2) issues discussed in RAI 2.1-2A(1) and (2) of SER

Section 2.1 related to NSR piping segments that support secondary containment, the applicant

expanded the system boundaries for the condensate and demineralized water system. By letter

dated May 31, 2005, the applicant submitted the results of its review of piping, supports, and

other components outside secondary containment required to maintain the structural integrity of

secondary containment that are within the scope of license renewal in accordance with the

requirements of 10 CFR 54.4(a)(2) for secondary containment qualification. In the enclosure to

the May 31, 2005 letter, the applicant stated that additional piping, fittings, valves, and the

demineralized water tank have been added to scope. However, the component types do not

differ from those listed in LRA Table 2.3.4.2; therefore, no changes to the condensate and

demineralized water system portion of the LRA are required. The staff reviewed applicant’s

submittals and found the expanded scope of components to be acceptable, because the

applicant had adequately included NSR components with the configurations that meet the

scoping criterion of 10 CFR 54.4(a)(2) for the cases where NSR piping or components are

directly connected to SR piping or components.

2.3.4.2.3 Conclusion

The staff reviewed the LRA and RAI response to determine whether any SSCs that should be

within the scope of license renewal had not been 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 had not been 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 had adequately identified the condensate and demineralized water system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the condensate and demineralized water system components that are subject to an AMR, as

required by 10 CFR 54.21(a)(1).
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2.3.4.3 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 FW system. The FW system provides

demineralized water at an elevated temperature to the reactor vessel during normal plant

operations. FW is fed to the reactor vessel through six feedwater inlet nozzles. Suction for the

system is drawn from the condensate system and FW is delivered to the reactor vessel at a

controlled rate in order to maintain a stable reactor vessel water level. The system provides a

flow path to the reactor vessel for the HPCI, RCIC, and RWCU systems.

The FW system contains SR components that are relied upon to remain functional during, and

following, DBEs. The failure of NSR SSCs in the FW system could prevent the satisfactory

accomplishment of an SR function. In addition, the FW system performs functions that support

fire protection, EQ, ATWS, and SBO.

The intended functions within the scope of license renewal include the following:

 • provides RCPB

 • provides primary and secondary containment boundaries

 • provides a path for HPCI system flow to the reactor pressure vessel through the

feedwater spargers

 • provides an injection path for the RCIC system

 • provides a pressure boundary of the FW system components connected to the control

air system that must maintain a pressure boundary in support of supplying containment

atmosphere dilution to the MSRVs

 • restricts flow

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.4.3, the applicant identified the following FW component types that are within

the scope of license renewal and subject to an AMR: bolting, fittings, RCPB fittings, piping,

RCPB piping, RCPB restricting orifice, tubing, valves, and RCPB valves.

2.3.4.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.3 and UFSAR Sections 3.7, 4.2, 4.7.5, 4.9, 4.11, 5.2.3,

5.3, 6.4.1, 7.2, 7.3, 7.4, 7.8, 7.10, 10.17, and 11.8 using the evaluation methodology described

in SER Section 2.3. The staff conducted its review in accordance with the guidance described

in SRP-LR Section 2.3.
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In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant did

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 order to resolve the 10 CFR 54.4(a)(2) issues discussed in RAI 2.1-2A(1) and (2) of SER

Section 2.1 related to NSR piping segments that support secondary containment, the applicant

expanded the system boundaries for the feedwater system. By letter dated May 31, 2005, the

applicant submitted the results of its review of piping, supports, and other components outside

secondary containment required to maintain the structural integrity of secondary containment

that are within the scope of license renewal in accordance with the requirements of

10 CFR 54.4(a)(2) for secondary containment qualification. In the enclosure to its letter dated

May 31, 2005, the applicant stated that additional piping, valves, and heaters were added to

scope. The component type, “heaters,” was added to LRA Table 2.3.4.3.

The staff reviewed the NSR piping segments and found the expanded scope of components to

be acceptable, because the applicant had adequately included NSR components with the

configurations that meet the scoping criterion of 10 CFR 54.4(a)(2) for the cases where NSR

piping or components are directly connected to SR piping or components.

2.3.4.3.3 Conclusion

The staff reviewed the LRA and RAI response to determine whether any SSCs that should be

within the scope of license renewal had not been 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 had not been 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 had adequately identified the FW system components that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and the FW system components that are

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

2.3.4.4 Heater Drains and Vents System

2.3.4.4.1 Summary of Technical Information in the Application

In LRA Section 2.3.4.4, the applicant described the heater drains and vents system. The heater

drains and vents system controls and contains the drains and vent paths from the various

heaters associated with the main turbine cycle.

The heater drains and vents system contains SR components that are relied upon to remain

functional during, and following, DBEs.
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The intended functions within the scope of license renewal include the following:

 • establishes an MSIV leakage pathway to the condenser

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.4.4, the applicant identified the following heater drains and vents system

component types that are within the scope of license renewal and subject to an AMR: bolting,

fittings, piping, traps, valves.

2.3.4.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.4 and UFSAR Section 11.8 using the evaluation

methodology described in SER Section 2.3. The staff conducted its review in accordance with

the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 reviewing LRA Section 2.3.4.4, the staff identified areas in which additional information was

necessary to complete the evaluation of the applicant’s scoping and screening results.

Therefore, by letter to the applicant dated August 31, 2004, the staff issued RAIs concerning

the specific issues to determine whether the applicant had properly applied the scoping criteria

of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs

describe the staff’s RAIs and the applicant’s related responses.

In RAI 2.3.4.4-1, the staff stated that pressure reducing valves PCV-1-151, -153, -166, and -167

are highlighted on license renewal drawing 2-47E801-2-LR as being within the scope of license

renewal and subject to an AMR. However, the piping downstream of these pressure reducing

valves is not within the scope of license renewal. Likewise, the similar arrangement for Unit 3 is

shown on license renewal drawing 3-47E801-2-LR. Pressure reducing valves typically do not

provide isolation capability if the downstream piping fails. Failure of the downsteam piping could

effect the intended function of the heater drains and vents system that is required to establish

MSIV leakage pathway to the condenser per LRA Section 2.3.4.4. Therefore, the staff

requested that the applicant provide a basis for excluding the piping downstream of valves

PCV-1-151, -153, -166, and -167 from the scope of license renewal and from being subject to

an AMR.

In its response, by letter dated October 19, 2004, the applicant stated that a calculation issued

in support of the MSIV leakage path listed these valves as a boundary. These pressure

reducing valves close on loss of power, loss of air, and low steam line pressure. The applicant

stated that TVA will review the qualification of the MSIV leakage path to identify the piping,
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supports and other components past the isolation valve required to maintain the structural

integrity of the MSIV leakage pathway.

In a supplemental response dated May 31, 2005, the applicant provided the results of its review

of the seismic qualification of the MSIV leakage path. As a result of the review, the following

mechanical systems had systems boundary changes:

 • main steam system

 • auxiliary boiler system

However, the component types do not differ from those listed in the corresponding LRA tables;

therefore, no changes to these systems’ portion of the LRA are required.

The following mechanical systems had systems boundary changes; however, new component

types were added that affected the scoping/screening results in the LRA.

 • heaters drains and vents system

 • off-gas system

The effect of these changes is evaluated and discussed in the corresponding sections of the

SER. The remainder of the mechanical systems were not affected by this review.

Based on its review, the staff found the expanded scope of components to be acceptable,

because the applicant had adequately included NSR components with the configurations that

meet the scoping criterion of 10 CFR 54.4(a)(2) for the cases where NSR piping or components

are directly connected to SR piping or components. Therefore, the staff's concern described in

RAI 2.3.4.4-1 is resolved.

In RAI 2.3.4.4-2, the staff stated that check valves 742 and 744 are highlighted on license

renewal drawing 2-47E801-2-LR as being within the scope of license renewal and subject to an

AMR. However, the piping downstream of these check valves is not within the scope of license

renewal. Likewise, the similar arrangement for Unit 3 is shown on license renewal drawing

3-47E801-2-R. Failure of the downstream piping would affect the intended function of the

heater drains and vent system that is required to establish an MSIV leakage pathway to the

condenser per LRA Section 2.3.4.4 and, therefore, should be within scope of license renewal as

per 10 CFR 54.4(a)(2). Furthermore, the check valve orientation as shown on these drawings

will not prevent flow to the downstream piping in the event of a failure. Therefore, the staff

requested that the applicant provide a basis for excluding the piping downstream of check

valves 742 and 744 from being subject to an AMR.

In its response, by letter dated October 19, 2004, the applicant stated that a calculation issued

in support of the MSIV leakage path has these valves listed as a boundary. The applicant

committed to review the qualification of the MSIV leakage path and identify the piping, supports

and other components past the isolation valve required to maintain the structural integrity of the

MSIV leakage pathway.

In a supplemental response dated May 31, 2005, the applicant stated that check valves 742

and 744 on boundary drawings 2-47E801-2-LR and 3-47E801-2-LR are spring-loaded and

close on low pressure upon MSIV closure to prevent backflow through these valves.
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Based on its review, the staff found the applicant’s response to RAI 2.3.4.4-2 acceptable,

because it adequately addressed the intended function of check valves 742 and 744. Failure of

the downstream piping during low-pressure events will not impede the intended function of

these check valves. Therefore, the staff's concern described in RAI 2.3.4.4-2 is resolved.

In order to resolve the 10 CFR 54.4(a)(2) issues discussed in RAI 2.1-2A(1) and (2) of SER

Section 2.1 related to NSR piping segments that support the MSIV leakage path, the applicant

expanded the system boundaries for the heaters drains and vents system. By letter dated

May 31, 2005, the applicant submitted the results of its review of piping, supports, and other

components required to maintain the structural integrity of the MSIV leakage path that are

within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(2).

In the enclosure to the May 31, 2005 letter, the applicant stated that additional piping had been

added to scope. However, the component type does not differ from those listed in LRA

Table 2.3.4.4; therefore, no changes to the heater drains and vents system portion of the LRA

are required. The staff reviewed the NSR piping segments and found the expanded scope of

components to be acceptable because the applicant had adequately included NSR components

with the configuration that meets the scoping criterion of 10 CFR 54.4(a)(2) for the case where

NSR piping or components are directly connected to SR piping segments.

2.3.4.4.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, RAI

responses, and licensing-basis information, the staff did not identify any omissions or

discrepancies in the applicant’s scoping and screening results for the components of the heater

drains and vents system. Therefore, the staff concludes the heater drains and vent system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

that the applicant had adequately identified the heater drains and vents system components

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

2.3.4.5 Turbine Drains and Miscellaneous Piping System

2.3.4.5.1 Summary of Technical Information in the Application

In LRA Section 2.3.4.5, the applicant described the turbine drains and miscellaneous piping

system. The turbine drains and miscellaneous piping system directs controlled leakage from

various MS system components into the condenser.

The turbine drains and miscellaneous piping system contains SR components that are relied

upon to remain functional during, and following, DBEs.

The intended functions within the scope of license renewal include the following:

 • establishes an MSIV leakage pathway to the condenser

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support
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In LRA Table 2.3.4.5, the applicant identified the following turbine drains and miscellaneous

piping system component types that are within the scope of license renewal and subject to an

AMR: bolting and valves.

2.3.4.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.5 using the evaluation methodology described in SER

Section 2.3. The staff conducted its review in accordance with the guidance described in

SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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 reviewing LRA Section 2.3.4.5, the staff identified an area in which additional information was

necessary to complete the evaluation of the applicant’s scoping and screening results.

Therefore, by letter to the applicant dated October 8, 2004, the staff issued an RAI concerning

the specific issues to determine whether the applicant had properly applied the scoping criteria

of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs

describe the staff’s RAI and the applicant’s response.

In RAI F 2.3.4.5-1, the staff stated that LRA Section 2.3.4.5 states that the intended function of

the turbine drains and miscellaneous piping system is to establish MSIV leakage pathway to the

condenser. The entire LRA section is enclosed in a bold text box. LRA Appendix F, Section F.1,

“Main Steam Isolation Valve Alternate Leakage Treatment,” states that the Unit 1 main steam

piping from the outermost isolation valve up to the turbine stop valve, the bypass/drain piping to

the main condenser, and the main condenser is being evaluated and modified as required to

ensure that the structural integrity is retained during, and following, an SSE. However, it is not

clear where the alternate leakage treatment flow path to the condenser exists on license

renewal drawings 2-47E807-2-LR and 3-47E807-2-LR. Therefore, the staff requested that the

applicant identify which portions of these drawings show components that are part of the

leakage pathway to the condenser.

In its response, by letter dated October 25, 2004, the applicant stated that the alternate leakage

path ensures that process lines containing steam have a boundary that contains an isolation

point to form a preferred leakage path to the condenser. The boundary was established at the

first closed valve or fails-closed valve on the red lines continuing from LR drawings

2-47E801-2-LR, 2-47E807-1-LR, 3-47E801-2-LR, and 3-47E807-1-LR.

Based on its review, the staff found the applicant’s response to RAI F 2.3.4.5-1 acceptable. It

adequately identifies the portions of the license renewal drawings showing components that are

part of the leakage pathway to the condenser. Therefore, the staff’s concern described in RAI F

2.3.4.5-1 is resolved.
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2.3.4.5.3 Conclusion

The staff reviewed the LRA, the accompanying scoping boundary drawings, and RAI response

described above to determine whether any SSCs that should be within the scope of license

renewal had not been 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 had not been 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 had

adequately identified the turbine drains and miscellaneous piping system components that are

within the scope of license renewal, as required by 10 CFR 54.4(a), and the turbine drains and

miscellaneous piping system components that are subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.3.4.6 Condenser Circulating Water System

2.3.4.6.1 Summary of Technical Information in the Application

In LRA Section 2.3.4.6, the applicant described the condenser circulating water system. Each

unit contains a condenser circulating water system that does not share any components with

the other units’ systems. Each unit has three circulation water pumps that take water from a

common intake channel in Wheeler Reservoir. After passing through the condensers, the

heated water is cooled by the cooling towers or discharged directly back to Wheeler Reservoir.

Provisions, including a loop in the discharge conduit with a vacuum breaker, are made for the

prevention of the backflow of heated water into the intake channel, which serves as the ultimate

heat sink, if normal offsite power is lost. One condenser circulating water pump has more than

enough capacity to dissipate the shutdown heat for all three of the units.

The condenser circulating water system contains SR components that are relied upon to remain

functional during, and following, DBEs. The failure of NSR SSCs in the condenser circulating

water system could prevent the satisfactory accomplishment of an SR function. 

The intended functions within the scope of license renewal include the following:

 • provides a manual vacuum breaking capability to prevent backflow from cooling tower

warm channel into the forebay upon trip of the condenser circulating water pumps

 • provides mechanical closure

 • provides structural support

In LRA Table 2.3.4.6, the applicant identified the following condenser circulating water system

component types that are within the scope of license renewal and subject to an AMR: bolting,

fittings, piping, strainers, tubing, and valves.

2.3.4.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.6 and UFSAR Sections 2.4.2.2.2, 11.6, 12.2.7, and F.6.4

using the evaluation methodology described in SER Section 2.3. The staff conducted its review

in accordance with the guidance described in SRP-LR Section 2.3.
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In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed the 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 reviewing LRA Section 2.3.4.6, the staff identified areas in which additional information was

necessary to complete the evaluation of the applicant’s scoping and screening results.

Therefore, by letter to the applicant dated August 31, 2004, the staff issued RAIs concerning

the specific issues to determine whether the applicant had properly applied the scoping criteria

of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs

describe the staff’s RAIs and the applicant’s related responses.

In RAI 2.3.4.6-1, the staff stated that LRA Section 2.3.4.6 indicates that a vacuum-breaker

valve, located in a piping loop in the discharge conduit of the condenser circulating water

(CCW) system, is provided to prevent the backflow of heated cooling tower effluent from the

warm water channel into the intake channel which serves as an ultimate heat sink. Backflow

can occur upon loss of offsite power with attendant trip of the CCW pumps if the level in the

warm water channel exceeds that in the intake channel. As indicated in the LRA, the

components comprising this vacuum breaking subsystem require an AMR.

On the license renewal boundary drawings for Unit 1, all components comprising this

subsystem are shown within the scope of license renewal in accordance with

10 CFR 54.4(a)(1). However, the drawings for Units 2 and 3 show only the vacuum-breaker

valves themselves in scope under 10 CFR 54.4(a)(1), while the associated loop piping and

fittings are shown either within scope under 10 CFR 54.4(a)(2) or else outside of scope.

Therefore, the staff requested that the applicant justify why the components comprising this

subsystem had been classified differently for Units 2 and 3 than for Unit 1.

In its response, by letter dated October 19, 2004, the applicant stated that DCN 51360A was

issued to reclassify the loop piping and fittings of the above-mentioned subsystem from SR to

NSR, for all three units. However, at the time of the LRA submittal, implementation of this DCN

had been completed for Units 2 and 3 but not for Unit 1. This resulted in the differences in

classification noted above. Additionally, the applicant stated that the above referenced loop

components for Units 2 and 3, which are classified as outside the scope of license renewal,

should have been classified as within scope under 10 CFR 54.4(a)(2). This error will be

corrected on the drawings for Units 2 and 3. It was further noted that, since DCN 51360A has

now been completed for Unit 1, the drawings for this unit have been revised to be consistent

with those for Units 2 and 3 and will be resubmitted as part of the annual update.

Based on its review, the staff found the applicant's response to RAI 2.3.4.6-1 acceptable. The

differences in component classification noted above have been satisfactorily explained and the

corresponding drawings have been appropriately corrected. Therefore, the staff's concern

described in RAI 2.3.4.6-1 is resolved.
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In RAI 2.3.4.6-2, the staff stated that components of the CCW system that are subject to an

AMR are shown in LRA Table 2.3.4.6. These components described in RAI 2.3.4.6-1 comprise

the vacuum breaking subsystem. For the components listed, the table shows that structural

support is the sole intended function for each (except bolting which has the additional intended

function of mechanical closure). However, it would appear that the pressure boundary of the

components comprising this subsystem must remain intact to effect a break in vacuum.

Accordingly, each of these components should have the additional intended function of

pressure boundary. Therefore, the staff requested that the applicant justify why the intended

function pressure boundary is not included in LRA Table 2.3.4.6 for each of the components

listed.

In its response, by letter dated October 19, 2004, the applicant stated that maintaining an intact

pressure boundary for the components listed in LRA Table 2.3.4.6 is not required, because the

vacuum-breaking valve in this subsystem could perform its intended function, even if leakage

were to occur in the associated piping or fittings.

Based on its review, the staff found the applicant’s response to RAI 2.3.4.6-2 acceptable. It

adequately explains why the intended function of pressure boundary is not required for the

components in question. Therefore, the staff's concern described in RAI 2.3.4.6-2 is resolved.

2.3.4.6.3 Conclusion

The staff reviewed the LRA, the accompanying scoping boundary drawings, and RAI responses

described above to determine whether any SSCs that should be within the scope of license

renewal had not been 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 had not been 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 had

adequately identified the condenser circulating water system components that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and the condenser circulating water

system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.4.7 Gland Seal Water System

2.3.4.7.1 Summary of Technical Information in the Application

In LRA Section 2.3.4.7, the applicant described the gland seal water system. The gland seal

water system provides pressurized sealing water to the condenser and condensate system

components that are under a vacuum in order to prevent air leakage into the condenser. Each

individual system has an elevated gland seal tank that is located in the reactor building and also

contains the associated piping that maintains a static pressure on seals (e.g., packing) of

components of the main condenser and condensate systems that are under a vacuum during

normal plant operations.

The gland seal water system contains SR components that are relied upon to remain functional

during, and following, DBEs. The failure of NSR SSCs in the gland seal water system could

prevent the satisfactory accomplishment of an SR function. 
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The intended functions within the scope of license renewal include the following:

 • provides a secondary containment boundary

 • provides mechanical closure

 • provides pressure boundary

 • provides structural support

In LRA Table 2.3.4.7, the applicant identified the following gland seal water system component

types that are within the scope of license renewal and subject to an AMR: bolting, fittings,

piping, tanks, tubing, and valves.

2.3.4.7.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.7 using the evaluation methodology described in SER

Section 2.3. The staff conducted its review in accordance with the guidance described in

SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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).

2.3.4.7.3 Conclusion

The staff reviewed the LRA to determine whether any SSCs that should be within the scope of

license renewal had not been 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 had not been 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

had adequately identified the gland seal water system components that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and the gland seal water system components

that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
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2.4 Scoping and Screening Results: Structures

This section documents the staff’s review of the applicant’s scoping and screening results for

structures. Specifically, this section discusses the following structures:

 • boiling water reactor containment structures

 • Class I Group 2 structures

 • Class I Group 3 structures

 • Class I Group 6 structures

 • Class I Group 8 structures

 • Class I Group 9 structures

 • non-Class I structures

 • structures and component supports commodities

In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must identify and list

passive, long-lived structural SSCs 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 structures and 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 LRA was

performed in the same manner for all structures. The objective of the review was to determine if

the components and supporting structures for a specific structure that appeared to meet the

scoping criteria specified in the Rule had been 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 license renewal. The staff reviewed relevant licensing basis

documents, including the UFSAR, for each structure and 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.

Screening. Once the staff completed its review of the scoping results, the staff evaluated the

applicant’s screening results. For those structures and components with intended functions, the

staff sought to determine if the functions are performed with moving parts or a change in

configuration or properties, or if they are subject to replacement based on a qualified life or

specified time period, as described in 10 CFR 54.21(a)(1). For those that did not meet either of

these criteria, the staff sought to confirm that these structures and 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.
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2.4.1 Boiling Water Reactor Containment Structures

2.4.1.1 Primary Containment Structure

2.4.1.1.1 Summary of Technical Information in the Application

In LRA Section 2.4.1.1, the applicant described the primary containment structure. The primary

containment structure is a General Electric Mark I containment design. Each unit has a primary

containment structure that is completely enclosed within the unit’s reactor building. The main

function of the primary containment structure is to limit the release of fission products to the

environment in the event of a design-basis LOCA.

The primary containment consists of a drywell, pressure suppression chamber, and a

connecting vent system. The drywell is a steel pressure vessel enclosed in reinforced concrete.

The drywell contains the reactor vessel, reactor recirculation system, and portions of other

systems that form the reactor coolant pressure boundary. Also included within the drywell are

structural steel framing, electrical and mechanical equipment and system supports, a concrete

shield wall around the reactor vessel, a removable steel head, a personnel airlock with two

mechanically interlocked doors, two equipment hatches, and miscellaneous electrical and

mechanical penetrations. The pressure suppression chamber is a steel, toroidal-shaped

pressure vessel. The pressure suppression chamber is commonly referred to as the “torus.”

The torus includes internal steel framing, vent header, supports, access hatches, and

penetrations. The torus is mounted on support structures that transmit loads to the concrete

foundation of the reactor building. The drywell is connected to the pressure suppression

chamber with eight equally spaced vent lines. These vent lines are connected to a header,

which is contained within the air space of the pressure suppression chamber. The pressure

suppression chamber contains a large pool of water that condenses the steam from a failure of

the reactor coolant pressure boundary piping in the drywell. The pool also condenses steam

from the main steam relief valve discharge, high pressure coolant injection, and reactor core

isolation cooling turbine discharge.

The primary containment structure contains SR SSCs that are relied upon to remain functional

during, and following, DBEs to ensure the integrity of the reactor coolant pressure boundary,

shut down the reactor and maintain it in a safe shutdown condition, and prevent or mitigate the

consequences of accidents that could result in potential offsite exposure. The failure of NSR

SSCs in the primary containment structure could prevent the satisfactory accomplishment of an

SR function. In addition, the primary containment structure performs functions that support fire

protection, EQ, ATWS, and SBO.

The intended functions within the scope of license renewal include the following:

 • provides structural support and shelter/protection for components relied upon to

demonstrate compliance with fire protection, EQ, and ATWS regulated events

 • provides structural support and shelter/protection for SR components, NSR

components, and components relied upon to demonstrate compliance with the SBO

regulated event
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 • limits and controls the release of fission products to the secondary containment during

DBAs

 • provides sufficient air and water volumes to absorb the energy released to the

containment during DBAs

 • provides a source of water to the emergency core cooling systems

 • provides protection to personnel and components from radiation

 • provides a pressure boundary

 • shelters and protects a component from the effects of weather or localized

environmental conditions

 • reduces a radiation dose

 • provides structural and functional support for structures and components that are within

the scope of license renewal

In LRA Table 2.4.1.1, the applicant identified the following primary containment structure

component types that are within the scope of license renewal and subject to an AMR:

 • caulking and sealants

 • compressible joints and seals

 • controlled leakage doors

 • hatches/plugs

 • high density shielding concrete

 • electrical and I&C penetrations

 • mechanical penetrations

 • reinforced concrete beams, columns, walls, and slabs

 • steel containment elements

 • structural bellows

 • structural steel beams, columns, plates, and trusses

2.4.1.1.2 Staff Evaluation

The staff reviewed LRA Section 2.4.1.1 and UFSAR Sections 5.2, 12.2.2 and C.5 using the

evaluation methodology described in SER Section 2.4. The staff conducted its review

in accordance with the guidance described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant 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 2.4.1.1 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 RAIs as discussed below. 
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In RAI 2.4-2, dated December 20, 2004, the staff stated that in reviewing LRA Section 2.4.1.1, it

noted that this section of the LRA should address not only the primary containment (drywell,

pressure suppression chamber, and the vent system connecting the two structures), but also all

the structures inside the primary containment, all attachments to the containment, and the

containment supports. The staff also noted that LRA Table 2.4.1.1 identified the primary

containment component types requiring AMR and the associated component intended

function(s). Since LRA Table 2.4.1.1 combined many components under a single component

type, the staff requested that the applicant identify which component type had been intended to

cover the specific components listed in (a) through (k) below, or to identify the location in the

LRA where these specific components had been addressed. If these specific components had

not been considered to be within the scope of license renewal, the applicant was requested to

provide the technical bases for their exclusion.

 a. reactor vessel to biological shield stabilizers

 b. biological shield to containment stabilizer

 c. reactor pressure vessel (RPV) male stabilizer attached to outside of drywell shell

 d. RPV female stabilizer and anchor rods (also referred to as gib) embedded in reactor

building concrete wall 

 e. biological shield wall and anchor bolts 

 f. reactor vessel support skirt and anchor bolts

 g. reactor vessel support ring girder and anchor bolts

 h. reactor vessel support pedestal

 i. drywell internal steel shear ring

 j. drywell steel support skirt and anchor bolts

 k. drywell head closure bolts and double gasket, tongue-and-groove seal arrangement

By letter dated January 24, 2005, the applicant provided the following response: 

The Primary Containment Structure scoping and screening results are presented in LRA

Section 2.4.1.1, the Reactor Vessel scoping and screening results are presented in LRA

Section 2.3.1.1, and the Structures and Component Supports Commodity Group

scoping and screening results are presented in LRA Section 2.4.8.1. The following list of

components roll-up to the listed component groups:

(a) Reactor Vessel to Biological Shield Stabilizers:

 • Table 2.4.8.1, ASME Equivalent Supports and Components;

 • Table 3.5.2.26, ASME Equivalent Supports and Components;

 • Table 2.3.1.1, Stabilizer Bracket;

 • Table 3.1.2.1, Stabilizer Bracket; and

 • LRA Section 3.1.2.2.16.1 BWRVIP-74-A Table 4-1 Items.

 • NOTE: This biological shield wall is internal to the drywell.
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(b) Biological Shield to Containment Stabilizer:

 • Table 2.4.1.1, Steel Containment Elements; and

 • Table 3.5.2.1, Steel Containment Element.

 • NOTE: This biological shield wall is internal to the drywell.

(c) RPV Male Stabilizer Bracket Attached to Outside of Drywell Shell:

 • There is no RPV male stabilizer bracket attached to the outside of the

Drywell shell at BFN. There is a stabilizer from the internal biological

shield wall to the inside containment shell that is a subset of biological

shield to containment stabilizer noted in (b) above.

(d) RPV Female Stabilizer and Anchor Rods (also referred to as Gib) embedded in

Reactor Building concrete wall:

 • There is no RPV female stabilizer and anchor rods (also referred to as

Gib) embedded in Reactor Building concrete wall at BFN. There is a

female stabilizer and anchor rods assembly embedded in Reactor

Building concrete wall (also a biological shield wall external to Drywell)

and is a subset of biological shield to containment stabilizer noted in (b)

above.

(e) Biological Shield Wall and Anchor Bolts:

 • Table 2.4.1.1, High Density Shielding Concrete;

 • Table 3.5.2.1, High Density Shielding Concrete (Un-reinforced shielding

concrete is encased between steel plates and is inaccessible. The steel

plates are included with structural steel internal to drywell);

 • Table 2.4.1.1, Structural Steel Beams, Columns, Plates, Trusses; and

 • Table 3.5.2.1, Structural Steel Beams, Columns, Plates, Trusses.

 • NOTE: This biological shield wall is internal to the drywell.

(f) Reactor Vessel Support Skirt and Anchor Bolts:

 • Table 2.3.1.1, Support Skirt and Attachment Welds;

 • Table 3.1.2.1, Reactor Vessel Support Skirt and Attachment Welds;

 • LRA Section 3.1.2.2.16.1 BWRVIP-74-A Table 4-1 Items;

 • Table 2.4.8.1, ASME Equivalent Supports and Components; and

 • Table 3.5.2.26, ASME Equivalent Supports and Components (includes

anchor bolts).
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(g) Reactor Vessel Support Ring Girder and Anchor Bolts:

 • Table 2.4.8.1, ASME Equivalent Supports and Components; and

 • Table 3.5.2.26, ASME Equivalent Supports and Components (includes

anchor bolts).

(h) Reactor Vessel Support Pedestal:

 • Table 2.4.1.1, Reinforced Concrete Beams, Columns, Walls, and Slabs;

and

 • Table 3.5.2.1, Reinforced Concrete Beams, Columns, Walls, and Slabs.

(i) Drywell Internal Steel Shear Ring:

 • BFN does not have a "Drywell Internal Steel Shear Ring"

(j) Drywell Steel Support Skirt and Anchor Bolts:

 • Table 2.4.1.1, Steel Containment Elements; and

 • Table 3.5.2.1, Steel Containment Elements (Drywell steel support skirt is

part of the Class MC drywell support and the skirt and anchor bolts are

encased in concrete; therefore, they are inaccessible.)

(k) The Drywell Head Closure Bolts and Double Gasket, Tongue and Groove Seal

Arrangement:

 • Table 2.4.1.1, Steel Containment Elements;

 • Table 3.5.2.1, Steel Containment Elements (Includes drywell head

closure bolts);

 • Table 2.4.1.1, Compressible Joints & Seals; and

 • Table 3.5.2.1, Compressible Joints & Seals.

Based on the response to RAI 2.4-2 by letter dated January 24, 2005, the staff found that the

components identified in the RAI are covered under the scope of LRA Section 2.4.1, except

item (f), which is covered under the scope of LRA Section 2.3. However, 10 CFR 54.4(a) and

(b) require identification of all in-scope structures and components and their intended functions.

The staff reviewer assumed that the drywell and suppression chamber supports (items (j) and

(k)) are within the scope of license renewal; however, an absence of all structural components

internal to drywells and suppression chambers (Items (a) to (e), and items (g) and (h)) from

LRA Table 2.4.1.1 implies that they are not within the scope of license renewal. The applicant

was requested to explicitly incorporate the components internal to drywells and suppression

chambers within the scope of license renewal, through cross referencing, if necessary.

In a follow-up response to RAI 2.4-2, by letter dated May 24, 2005, the applicant stated that the

methodology used to determine the components within the scope of license renewal is

described in LRA Section 2.1.4.3.3, “Structural Component Scoping,” and reads as follows: 
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For structures determined to be within the scope of 10 CFR 54, detailed structural

drawings were reviewed to identify structural components (such as structural steel,

foundations, floors, walls, ceilings, penetrations or stairways). For in-scope structures,

all structural components that are required to support the intended functions of the

structure were identified as in-scope of 10 CFR 54. These structural components were

generally evaluated as generic structural commodities, not as individual components.

LRA Section 2.4.1.1 addresses the primary containment structure and includes all component

types, as noted in LRA Table 2.4.1.1. The component type “Reinforced Concrete Beams,

Columns, Walls, and Slabs” includes the concrete of the reactor vessel support pedestal and

other structural concrete located within the primary containment structure. The component type

“High Density Shielding Concrete” includes the concrete of the biological shield wall. The

component type “Structural Steel Beams, Columns, Plates, Trusses” includes the plates that

form the cylindrical shell of the biological shield wall and other structural steel components such

as the steel platforms located within the primary containment structure. The component type

“Steel Containment Elements” includes the stabilizers between the biological shield wall and

containment shell, RPV male stabilizer bracket and RPV female stabilizer and anchor bolts,

drywell, drywell steel support skirt and anchor bolts, drywell head and closure bolts, torus and

torus ring girder, embedded steel, and other components that comprise the primary

containment boundary of the primary containment structure. The component type

“Compressible Joints and Seals” includes the gasket material used in the drywell head seal,

drywell and torus access hatch seals, and personnel access doors and penetration seals

located in the primary containment structure. Components identified as supports that are

located within the primary containment structure were addressed in Section 2.4.8.1, Structures

and Component Supports Commodity Group. The component type “ASME Equivalent Supports

and Components” includes the anchor bolts of the RPV support skirt, RPV ring girder and

anchor bolts and other supports for ASME Code Class 1 and Class 2 piping within the primary

containment structure. 

Based on this detailed description of the commodity groups that are included within the scope

of license renewal, the staff found that all structural as well as non-structural (e.g., seals and

gaskets) components within the primary containment structures have been included within the

scope of license renewal. Therefore, the staff found the applicant’s scoping of the components

within the primary containment acceptable, and the staff’s concern described in RAI 2.4-2 is

resolved.

In RAI 2.4-3, dated December 20, 2004, the staff explained its concern that leakage through

the refueling seals located at the top of the drywell potentially exposes the carbon steel drywell

shell inner and outer surfaces to loss of material due to corrosion. This is a particular concern

for the embedded portion of the drywell shell. Corrosion detected on the outer shell surface in

the sand pocket region in a number of Mark I steel containments has been attributed to leakage

past the drywell-to-reactor building refueling seal, coupled with clogging of the sand pocket

drains. Leakage into the drywell past the reactor vessel-to-drywell refueling seal creates the

potential for corrosion of the inaccessible portion of the inner surface of the drywell shell

embedded in the concrete floor. 

From the information contained in the LRA, the staff stated that it was not clear (1) whether the

refueling seals had been included within the scope of license renewal, and (2) if included, how

aging management of the seals was addressed. Therefore, the staff requested the applicant to
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verify that the BFN plants’ refueling seals were included in a component type that required an

AMR, or a detailed explanation for their exclusion. The staff also requested the applicant to

provide a detailed description of the plant-specific operating experience for the refueling seals

in all three 3 units, including incidences of degradation, method of detection, root cause,

corrective actions, and current inspection procedures.

In its response, by letter dated January 24, 2005, the applicant stated that BFN it had not

included the refueling seals at the top of the drywell within the scope of license renewal, and

explained its logic as follows:

The performance of the drywell-to-reactor building refueling seal is not considered a

safety-related function. The drywell to reactor building refueling seal and the reactor

pressure vessel (RPV)-to-drywell refueling seal, in conjunction with the refueling

bulkhead, provides a watertight barrier to permit flooding above the RPV flange while

preventing water from entering the drywell. Providing a watertight barrier to permit

flooding above the RPV flange in support of refueling operations is not a safety-related

function.

Moreover, the applicant stated that the performance of the drywell-to-reactor building refueling

seal is not considered a II over I issue by quoting 10 CFR 54.4(a)(2): “All non safety-related

systems, structures, and components whose failure could prevent satisfactory accomplishment

of any of the functions identified in paragraphs (a)(1)(i), (ii), or (iii) of this section,” and provided

the following explanation: 

A postulated failure of the drywell-to-reactor building refueling seal can result in water

intrusion into the annulus space around the drywell. This leakage can occur only during

refueling outages when the reactor cavity is flooded to allow movement of fuel between

the reactor and the fuel pool. However, water intrusion does not cause failure of the

drywell’s intended function. Any water leakage resulting from a postulated failure of the

drywell-to-reactor building refueling seal could not remain suspended in the annulus

region for an indefinite period of time and would eventually be routed to the sand-pocket

area drains or would evaporate due to the heat generated in the drywell during

operation.

The staff disagreed with the applicant’s rationale for not including the reactor building-to-drywell

refueling seals within the scope. 

In OI 2.4-3, the staff explained that Supplement 1 of IE IN 86-99 indicates that if leakage from

the flooded reactor cavity is not monitored and managed, there is a potential for corrosion of the

cylindrical portion of the drywell shell. As this corrosion would initiate in the non-inspectible

areas of the drywell, it cannot be monitored by IWE inspections. Moreover, this degradation of

the drywell shell can occur even if there is very little water found in the sand pocket area of the

drywell. Thus, the reactor building-to-drywell refueling seal becomes a nonsafety item, that can

affect the integrity of the drywell shell (which is a pressure boundary component) during the

period of extended operation, and falls under the requirement of 10 CFR 54.4(a)(2).

Furthermore, the staff offered an alternative by citing two BWR plants where the staff had

accepted in the past an alternative to managing the aging of the seal. The alternative is to

periodically perform ultrasonic testing (UT) of the cylindrical portion of the drywell shell with an

acceptable sampling program, as part of the containment ISI program. After reviewing the
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response to RAI 3.5-4 (in the applicant’s letter dated January 31, 2005) related to the operating

experience of drywell shell corrosion at all three units of BFN, the staff came to the conclusion

that the applicant should manage the aging (leakage) of refueling seals. The applicant was

requested to include the refueling seals within the scope of license renewal.

In its response, by letter dated May 31, 2005, the applicant emphasized that BFN does not

include the refueling seals at the top of the drywell in the scope of license renewal and provided

the following technical basis for that conclusion:

The drywell-to-reactor building refueling seal and the reactor pressure vessel

(RPV)-to-drywell refueling seal, in conjunction with the refueling bulkhead, provide a

watertight barrier to permit flooding above the RPV flange while preventing water from

entering the drywell. Providing a watertight barrier to permit flooding above the RPV

flange in support of refueling operations is not a safety-related function. 10 CFR 54.4(a)

sets forth the criteria that determine whether plant systems, structures, and components

are within the scope of license renewal. The refueling seals do not satisfy any of the

requirements set forth in 10 CFR 54.4(a)(1). The refueling seals are not safety related

and they are not relied upon to remain functional during design basis events to ensure

10 CFR 54.4(a)(1)(i) the integrity of the reactor coolant pressure boundary,

10 CFR 54.4(a)(1)(ii) the capability to shut down the reactor and maintain it in a safe

shutdown condition, or 10 CFR 54.4(a)(1)(iii) the capability to prevent or mitigate

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

50.67(b)(2), or 100.11. Thus, the refueling seals are not brought into scope of license

renewal by 10 CFR 54.4(a)(1).

Additionally, the applicant stated that the performance of the drywell-to-reactor building

refueling seal and the RPV-to-drywell refueling seal, in conjunction with the refueling bulkhead

is not considered a II over I issue. 10 CFR 54.4(a)(2) states, "All non-safety-related systems,

structures, and components whose failure could prevent satisfactory accomplishment of any of

the functions identified in paragraphs (a)(1)(i), (ii), or (iii) of this section." A postulated failure of

the drywell-to-reactor building refueling seal can result in water intrusion into the annulus space

around the drywell. This leakage can occur only during refueling outages when the reactor

cavity is flooded to allow movement of fuel between the reactor and the fuel pool. However,

water intrusion does not cause failure of the drywell's intended function. Any water leakage

resulting from a postulated failure of the drywell-to-reactor building refueling seal could not

remain suspended in the annulus region for an indefinite period of time and would eventually be

routed to the sand pocket area drains or would evaporate due to the heat generated in the

drywell during operation. The refueling seals are not relied upon in safety analyses or plant

evaluations to perform a function that demonstrates compliance with the NRC regulations for

fire protection, EQ, PRS (N/A for BWRs), ATWS, or SBO. The applicant discussed in detail the

differences between condition of the BFN units and that of Dresden 3, and emphasized that the

BFN refueling seals are not within the scope of license renewal and do not require aging

management review. The applicant also pointed out that Hatch Units 1 and 2 (NUREG-1803),

Peach Bottom Units 2 and 3 (NUREG-1769) and Dresden Units 2 and 3 and Quad Cities 1 and

2 (NUREG-1796) did not identify refueling seals to be within the scope of license renewal.

Thereafter, the applicant provided a detailed description of the BFN steel shell inspections in

the sand pocket areas (these are discussed in the staff’s evaluation of RAI 3.5-4), and

concluded: “Based on Browns Ferry scoping results, Browns Ferry operating experience, and
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prior industry precedents, Browns Ferry refueling seals are not in the scope of license renewal,

nor are additional drywell inspections warranted at Browns Ferry.”

Follow-up OI RAI 2.4-3 - In a detailed response to the staff’s follow-up item 3.5-4 related to the

seal area near the drywell flange, by letter dated May 31, 2005, the applicant stated: 

This area is exposed to standing water and repeated wetting and drying during refueling

operations. The area is not accessible for detailed visual examination from the outside

surface. There are no documented UT thickness measurements of this area. No

previous problems have been documented relative to degradation of this area. Standing

water was observed in this area during the April, 1998 Unit 3 mid-cycle outage, during a

walkdown performed immediately following drywell head removal and prior to floodup.

Since the true surface condition can not be determined by visual examination or review

of existing data, this area appears to warrant additional investigation to determine

whether it should be included for augmented examination. 

In its response, the applicant also provided a description of the limited number of UT

measurements taken. The staff expressed its belief that 10 CFR 54.4(a)(2) applies to the

uninspectable side of the drywell shell, as significant corrosion of the drywell shell would

jeopardize capability of the primary containment to prevent or mitigate the consequences of

accidents as per 10 CFR 54.4(a)(1)(iii). Based on the applicant’s responses to RAI 2.4-3, and

the follow-up RAI 3.5-4, the staff did not insist on having the drywell-to-reactor building seal

within the scope of license renewal. However, the staff indicated that it needed assurance that

the potential degradation of the uninspectable side of the drywell will be monitored and

managed during the period of extended operation. This remained as OI 2.4-3.

In its letter dated November 16, 2005, the applicant explained that to provide the staff with the

necessary assurance that the potential degradation of the uninspectable side of the drywell is

being monitored and managed, the applicant will perform one-time confirmatory ultrasonic

thickness measurements on a portion of the cylindrical section of the drywell in a region where

the liner plate is 0.75 inches thick. These ultrasonic thickness measurements will be obtained at

four locations, approximately 90° apart, in an area at least three feet by three feet with

measurements taken at intersection points of approximately one-foot grids. This will provide a

bounding condition since the nominal thickness of the wall in this region has the least margin.

These ultrasonic thickness measurements will be obtained on Unit 2 and Unit 3 prior to the

period of extended operation to provide added assurance that the integrity of the drywell shell is

not being compromised by wastage before entering into the renewed licensing period.

For Unit 1, the applicant explained that it will perform one-time confirmatory ultrasonic thickness

measurements on the vertical cylindrical area immediately below the drywell flange. This area is

exposed to standing water and repeated wetting and drying during refueling operations. These

ultrasonic thickness measurements will be obtained on the entire vertical portion of the liner

accessible from inside drywell above elevation 637.0’ (Az 0° - Az 360°) with measurements

taken at intersection points of approximately one-foot grids. These ultrasonic thickness

measurements will be obtained prior to Unit 1 restart. Similar inspections have been performed

on Units 2 and 3 in this area as documented in BFN plant procedure 0-TI-376, Appendix 9.7. A

discussion of the inspection for Units 2 and 3 is contained in the applicant’s response to

follow-up RAI 3.5-4, page E-13 in the letter from TVA to the NRC dated May 31, 2005.
1

 The OI-2.3-3 was discussed in the ACRS 530th full committee meeting on March 9,

2006. Additional discussion on this OI is provided in SER supplement NUREG-xxxx.

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The applicant, further asserted that data from the ultrasonic thickness measurements described

above will be reviewed by its engineering division. If any areas of concern or non-conforming

conditions are identified, a PER will be initiated in accordance with the site Corrective Action

Program, SPP-3.1. A corrective action plan will be developed in accordance with SPP-3.1 and

an extent of condition and applicability to the other BFN units would be considered in the

disposition of the PER.

As part of its response, the applicant emphasized that the BFN configuration of the refueling

cavity-to-drywell seal is different from that of a number of other Mark I containments. There is

no gasket at the drain, and the applicant claimed that it is able to monitor the leakage from the

refueling seal, if it occurs. However, the applicant could not satisfactorily explain the root cause

of water in the sand pocket areas. Therefore, the applicant chose to monitor the cylindrical

inaccessible areas of the three BFN units. For Units 2 and 3, the applicant will perform an

augmented inspection of these areas one time prior to the periods of extended operation; and,

for Unit 1, it will perform the inspection of these areas prior to Unit 1 restart. As part of these

inspections, if the applicant discovers non-conforming conditions, it will take appropriate

corrective actions. After careful review of the applicant’s commitments, the staff considered the

approach proposed by the applicant acceptable; therefore, OI 2.4-3 is closed.1

2.4.1.1.3 Conclusion

The staff reviewed the LRA, related structural components, and RAI responses described

above to determine whether any SSCs that should be within the scope of license renewal had

not been 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

had not been 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 had

adequately identified the primary containment structure components that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and the primary containment structure

components that are subject to an AMR, as required by 10 CFR 54.21(a)(1). 

2.4.2 Class 1 Group 2 Structures

In LRA Section 2.4.2, the applicant identified the structures and components of the Class 1

Group 2 structures that are subject to an AMR for license renewal.

The applicant described the supporting structures and components of the Class 1 Group 2

structures in the following sections of the LRA:

 • 2.4.2.1 reactor buildings

 • 2.4.2.2 equipment access lock

The corresponding subsections of the SER, 2.4.2.1 – 2.4.2.2, present the staff’s review findings

with respect to the Class 1 Group 2 structures for BFN.
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2.4.2.1 Reactor Buildings

2.4.2.1.1 Summary of Technical Information in the Application

In LRA Section 2.4.2.1, the applicant described the reactor buildings. Each unit has its own

reactor building that completely encloses the reactors, the primary containment structures, and

the auxiliary and emergency systems of the nuclear steam supply system (NSSS). A major

substructure of the reactor building is the reinforced concrete biological shield that surrounds

the drywell portion of the primary containment. The reactor buildings house features such as

the spent fuel pool, steam dryer/moisture separator storage pool, reactor cavity, reactor

auxiliary equipment, refueling equipment, reactor servicing equipment, and the control bay. The

control bay houses the main control room that is required for plant operation and the operation

of other important auxiliary systems. The reactor building consists of monolithic, reinforced

concrete floors and walls from the foundation to the refueling floor. The refueling floor is

common for all three units and is enclosed by the steel superstructure with metal siding and a

built-up roof. Blowout or pressure relief panels are installed as part of the reactor building

superstructure to relieve pressure during a DBA or DBE.

The reactor buildings contain SR components that are relied upon to remain functional during

and following DBEs. The failure of NSR SSCs in the reactor buildings could prevent the

satisfactory accomplishment of an SR function. In addition, the reactor buildings perform

functions that support fire protection, EQ, ATWS, and SBO.

The intended functions within the scope of license renewal include the following:

 • provides controls for the potential release of fission products to the external environment

 • provides a secondary containment function when the primary containment is required to

be in service

 • provides a primary containment function during reactor refueling and maintenance

operations when the primary containment systems are open

 • provides radiation shielding protection for personnel, equipment, and components

 • provides structural support and shelter/protection for components relied upon to

demonstrate compliance with the fire protection, EQ, and ATWS regulated events

 • provides structural support and shelter/protection for SR components, NSR

components, and components relied upon to demonstrate compliance with the SBO

regulated event

 • provides protection for the safe storage of new and spent fuel

 • prevents criticality of new and spent fuel

 • allows for expansion of a component

 • provides a rated fire barrier to confine or retard a fire from spreading to or from adjacent

areas of the plant

 • provides flood protection barrier for internal and external flooding events
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 • provides protection against the effects of a high-energy or low-energy (moderate) line

break

 • provides a barrier for protection against internally or externally generated missiles

 • provides a pressure boundary

 • shelters and protects a component from the effects of weather or localized

environmental conditions

 • reduces a radiation dose

 • provides structural and functional support for structures and components within the

scope of license renewal

 • provides structural and functional support, for in-scope structures and components, by

an NSR component

In LRA Table 2.4.2.1, the applicant identified the following reactor buildings component types

that are within the scope of license renewal and subject to an AMR:

 • bolting and fasteners

 • caulking and sealants

 • compressible joints and seals

 • controlled leakage doors

 • expansion joints

 • fire barriers

 • hatches and plugs

 • masonry block

 • metal roofing

 • metal siding

 • electrical and I&C penetrations

 • mechanical penetrations

 • reinforced concrete beams, columns, walls, and slabs

 • roof membrane

 • spent fuel pool liners

 • spent fuel storage racks (includes new fuel storage racks)

 • structural steel, beams, plates, and trusses

2.4.2.1.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2.1 and UFSAR Sections 5.3 and 12.2.2 using the

evaluation methodology described in SER Section 2.4. The staff conducted its review

in accordance with the guidance described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant 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 2.4.2.1 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 RAIs as discussed below. 

The staff noted that LRA drawing 0-10E201-01-LR, "License Renewal Screening for Information

Only Location of Structures," identifies structures that are not within scope of license renewal.

These structures include east access facility, isolation valve pits, radwaste building, south

access retaining walls, water and oil storage building, part of gate structure No.2 adjacent to

diesel high-pressure fire pump house, raw water treatment facility, structural elements within

the transformer yard, and other miscellaneous buildings. It was not clear to the staff that all of

the above listed structures serve no intended function as defined in 10 CFR 54.4(a)(1). 

In RAI 2.4-1, dated December 20, 2004, the staff asked the applicant to provide additional

descriptive information for the above-listed structures, define their function, and describe the

technical bases for exclusion from the license renewal scope. The applicant was also requested

to verify that none of these structures serve a seismic II/I intended function as defined in

10 CFR 54.4(a)(2). 

In its response, by letter dated January 24, 2005, the applicant stated the following:

These five (5) structures; East Access Facility, Radwaste Building, Water and Oil

Storage Building, part of Gate Structure No.2 adjacent to Diesel High Pressure Fire

Pump House, and Raw Water Treatment Facility are groups of Class II (NSR) structures

and major civil features that do not satisfy the requirements of 10 CFR 54.4(a). These

five structures provide structural support and anchorage for NSR equipment and

equipment that is not required to support regulated events (ATWS, fire protection, EQ,

and SBO). None of the five structures and major components in these structural groups

serves a seismic II/I intended function. This was the technical basis for exclusion from

the license renewal scope. A more detailed description and functions is provided below

for each of the five structures. A more detailed description of the South Access

Retaining Walls, the Isolation Valve Pits, and the structural elements within the

Transformer Yard and other miscellaneous buildings is also provided below. 

East Access Facility

This facility is a set of two temporary Class II (non-safetyrelated) buildings built originally

to support the recovery of BFN unit 3. One building provides office space and shop area

for site maintenance personnel. The other building provides access for site personnel,

plant material and plant equipment into the powerhouse (through the unit 3 Turbine

Building) and a radiation control point for same entering or exiting the unit 3 Turbine

Building.

Isolation Valve Pits 

These Class II (non-safety-related) structures are manholes that provide structural

support and shelter protection for the hardened wetwell vent piping and components.

Upon further review, it has been noted that the hardened wetwell vent is in scope for

license renewal per section 2.3.2.1, Containment System (064). The hardened wetwell

vent was a commitment to GL 89-16. These isolation valve pits are Class II (NSR)

structures and since they provide an intended function for an in-scope mechanical
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system (54.4(a)(2)), they should be included within the scope of the LRA. Refer to

Attachment 1 for the affected sections of the application with the required scoping,

screening and aging management review results for these structures (manholes).

Radwaste Building

The Radwaste Building is a Class II (non-safety-related) structure per UFSAR section

12.2.5. The Radwaste Building is a cellular box-type concrete structure extending

approximately 20 feet below grade and 30 feet above grade and is supported by steel

H-piles driven to bedrock. This building houses common services to all three units. The

concrete structure provides shelter/protection and non-safety related structural support

for equipment and components that support the processing of radwaste generated as a

result of plant operation.

South Access Retaining Walls

These retaining walls are safety-related structural features that maintain the stability of

the safety-related Earth Berm. The retaining walls provide retention of the Earth Berm

and allows for removal of a portion of the earth berm to construct a temporary personnel

access building. This temporary personnel access building provides access for site

personnel into the unit 1 Reactor Building and a radiation control point for same entering

or exiting the unit 1 Reactor Building during unit 1 recovery. These retaining walls are

safety-related structural features and should be included in the LRA. Refer to

Attachment 2 for the affected sections of the application with the required scoping,

screening and aging management review results for this structural feature.

Water and Oil Storage Building

The Water and Oil Storage Building is a Class II (non-safety related) of light commercial

construction, housing non-safety related electrical components and equipment for the

non-safety related water and oil storage tanks located east of this building.

Part of Gate Structure No. 2 adjacent to Diesel HPFP House 

Gate Structure No. 2 is part of the Auxiliary Condenser Cooling Water System as shown

on UFSAR Figure 12.2-72a (TVA drawing 0-31E400-1). The system consists of

waterways, control structures (i.e., Discharge Control Structure and Gate Structure No.

2) and cooling towers to permit helper system operation. They are seismically

unclassified and were designed for normal applicable dead, live, and surcharge loads

with appropriate load factors. The Diesel HPFP House is also a Class II structure and

was determined to be in-scope for LR because it houses mechanical and electrical

components that support the regulated event 50.48. Consequently seismic events do

not have to be considered to occur with the regulated event 50.48.

Raw Water Treatment Facility

The Raw Water Treatment Facility is a Class II (non-safetyrelated) prefabricated facility

housing non-safety-related equipment and tanks for chemical injection into the raw

cooling and service water systems. The function of the facility is to provide

shelter/protection and non-safety-related structural support for the equipment and
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components in this facility. A small office space for transit personnel is provided in one

of the buildings.

Structural Elements within the Transformer Yard and other miscellaneous buildings 

The Transformer Yard is in the scope of license renewal based on the criteria of

54.4(a)(3) for Station Blackout. See LRA section 2.4.7.4 for Transformer Yard scoping

and screening results. Note that the 161 kV Switchyard (LRA section 2.4.7.5) and the

500 kV Switchyard (LRA section 2.4.7.6) are also in the scope of license renewal based

on the criteria of 54.4(a)(3) for Station Blackout. There are no permanent buildings

within the license renewal boundary diagram for Transformer Yard or 161 kV Switchyard

or 500 kV Switchyard.

The staff reviewed the above response including the Attachments 1 and 2 of the applicant’s

letter dated January 24, 2005. The applicant committed to include the structural components

discussed in these attachments. The staff provided its evaluation of the structures for isolation

valve pits and south access retaining walls discussed in SER Sections 2.4.7.7 and 2.4.3.9,

respectively. The staff found that the response is adequate and acceptable. Therefore, the

staff’s concern described in RAI 2.4-1 is resolved.

In RAI 2.4-4, dated December 20, 2004, the staff stated that LRA Table 2.4.2.1 presents a list

of component types that are part of the reactor building, the auxiliary and emergency systems

of the NSSS, the biological shield, the spent fuel pool, the steam dryer/moisture separator

storage pool, the reactor cavity reactor auxiliary equipment, the steel superstructure with metal

siding and the built-up roof. Therefore, the staff requested the applicant to provide a description

of the "Neutron-Absorbing Sheets" used for the spent fuel storage racks and confirm that they

are part of the spent fuel storage racks listed in LRA Table 2.4.2.1.

In its response, by letter dated January 24, 2005, the applicant stated:

NUREG 1801, Section VII.A2.1-b, identifies “Spent Fuel Storage Racks – neutron

absorbing sheets” as a component type. In BFN LRA Section 2.3.3.27 “Fuel Handling

and Storage System (079),” it states that the spent fuel pool components are evaluated

as structural components in Section 2.4.2.1 “Reactor Building Structure”. BFN LRA

Table 2.4.2.1 “Reactor Building Structure” identifies “Spent Fuel Storage Racks

(includes new fuel storage racks)” as a component requiring aging management. The

“Neutron Absorbing Sheet” is a component of the BFN spent fuel storage rack container

tube wall and is comprised of Boral sandwiched within the stainless steel wall of each

container tube.

The staff found the above response acceptable. Therefore, the staff’s concern described in

RAI 2.4-4 is resolved. 

In RAI 2.4-5, dated December 20, 2004, referring to LRA Section 2.4.2.1, the staff requested

the applicant to clarify if the reactor buildings are designed to maintain an internal negative

pressure under neutral wind conditions in order to serve as the secondary containment whose

primary purpose is to minimize the ground level release of airborne radioactive materials and to

provide for a controlled, elevated release of the building atmosphere under accident conditions.

If this assumption was correct, the staff wanted to know if reactor building pipe penetrations
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were provided with some type of silicone rubber seals that allow pipe movement and provide a

seal between the pipe and the reactor buildings and maintain the negative internal pressure.

The staff wanted the applicant to confirm that these penetration seals are included within the

scope of licence renewal and are included in LRA Table 2.4.2.1.

In its response, by letter dated January 24, 2005, the applicant stated: 

With the exception of the Control Room, the Reactor Building is designed to maintain an

internal negative pressure under neutral wind conditions in order to serve as the

secondary containment whose primary purpose is to minimize the ground level release

of airborne radioactive materials and to provide for a controlled, elevated release of the

building atmosphere under accident conditions. The Control Room and portions of the

Control Bay that are contained within the Reactor Building are maintained at a positive

pressure to prevent the introduction of fission products during design basis events.

Piping that is not anchored within a reinforced concrete wall is sealed with caulking or

sealants. The reinforced concrete wall, and caulking and sealants are identified as

component type “Reinforced Concrete Beams, Columns, Walls, and Slabs” and

“Caulking & Sealants” respectively in Table 2.4.2.1 as requiring aging management

review with a pressure boundary (PB) intended function.

The staff found the above response adequate and acceptable. Therefore, the staff’s concern

described in RAI 2.4-5 is resolved.

In RAI 2.4-12, dated December 20, 2004, the staff stated that based on information provided in

LRA Sections 2.4.2.1, 2.4.2.2, 2.4.3.1, 2.4.4.1, and 2.4.7.1, it was unclear which cranes and

hoists were determined to be within the scope of license renewal and which subset of the

in-scope items have been screened in as items requiring an AMR. Therefore, the staff

requested the applicant to clarify the treatment of cranes and hoists in the scoping and

screening, and in the AMR. The applicant was requested to submit the following information:

 • A list of all cranes, hoists, rails, and associated components in the scope of license

renewal.

 • Additional information to identify the location within the LRA where cranes, hoists, rails,

and associated components are addressed. If these specific components are not

considered to be within the scope of license renewal, provide the technical bases for

their exclusion.

 • A list of all cranes, hoists, rails, and associated components requiring an AMR (i.e.,

passive, long-lived components).

 • A list of all cranes, hoists, rails, and associated components requiring aging

management and/or TLAA.

In its response, by letter dated January 24, 2005, the applicant stated that the cranes and

hoists are addressed in LRA Section 2.3.3.34 and the AMR results are contained in

Table 3.3.2.34. This same question was asked in RAI 2.3.3.34-1, dated August 31, 2004. In its

response to RAI 2.3.3.34-1 dated October 19, 2004, the applicant stated:
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The following buildings that contain NSR cranes and monorails which could potentially

prevent safety related SSCs from performing their intended function(s) are: Reactor

Building, Primary Containment, Diesel Generator Buildings, Intake Pumping Station, and

Reinforced Concrete Chimney. All cranes and monorails in these buildings are in scope.

The Mobile A-frames is a crane on wheels. The A-frame cranes are in scope since they

could be used in a safety related building. This crane is subject to an AMR. 

The staff found that the applicant had adequately responded to RAI 2.4-12 related to scoping

and screening of cranes, hoists, rails, and associated components. Therefore, the staff’s

concern described in RAI 2.4-12 is resolved.

2.4.2.1.3 Conclusion

The staff reviewed the LRA, related structural components, and RAI responses described

above to determine whether any SSCs that should be within the scope of license renewal had

not been 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

had not been 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 had

adequately identified the reactor buildings components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and the reactor buildings components that are subject

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

2.4.2.2 Equipment Access Lock

2.4.2.2.1 Summary of Technical Information in the Application

In LRA Section 2.4.2.2, the applicant described the equipment access lock. The equipment

access lock is a shared feature for all three reactor buildings. The equipment access lock is a

reinforced concrete structure, supported on piles, located on the south end of the Unit 1 reactor

building. The structure is sized to allow for the passage of a railcar or a tractor trailer within the

structure. This allows for the transit of large equipment into, or out of, the reactor buildings,

while maintaining the secondary containment. The equipment access lock is an airlock with

large equipment doors that open to the outside environment on the south end, and allow access

to the Unit 1 reactor building on the north end.

The equipment access lock contains SR components that are relied upon to remain functional

during and following DBEs. The failure of NSR SSCs in the equipment access lock could

prevent the satisfactory accomplishment of an SR function.

The intended functions within the scope of license renewal include the following:

 • provides controls for the potential release of fission products to the external environment

 • provides a secondary containment envelope between the reactor building and the

outside entrance

 • provides structural support and shelter/protection for SR and NSR components

 • provides flood protection barrier for internal and external flooding events
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 • provides a barrier for protection against internally or externally generated missiles

 • provides a pressure boundary

 • shelters and protects a component from the effects of weather or localized

environmental conditions

 • provides structural and functional support for structures and components within the

scope of license renewal

 • provides structural and functional support, for in-scope structures and components, by

an NSR component

In LRA Table 2.4.2.2, the applicant identified the following equipment access lock component

types that are within the scope of license renewal and subject to an AMR:

 • caulking and sealants

 • compressible joints and seals

 • controlled leakage doors

 • electrical and I&C penetrations

 • mechanical penetrations

 • piles

 • reinforced concrete beams, columns, walls, and slabs

 • structural steel beams, columns, plates, and trusses

2.4.2.2.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2.2 and UFSAR Sections 5.3.3.5 and 12.2.9 using the

evaluation methodology described in SER Section 2.4. The staff conducted its review

in accordance with the guidance described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant 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).

2.4.2.2.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether any SSCs

that should be within the scope of license renewal had not been 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 had not been 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 had adequately identified the equipment access lock

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the equipment access lock components that are subject to an AMR, as required by

10 CFR 54.21(a)(1). 
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2.4.3 Class 1 Group 3 Structures

In LRA Section 2.4.3, the applicant identified the structures and components of the Class 1

Group 3 structures that are subject to an AMR for license renewal.

The applicant described the supporting structures and components of the Class 1 Group 3

structures in the following sections of the LRA:

 • 2.4.3.1 Diesel Generator Buildings

 • 2.4.3.2 Standby Gas Treatment Building

 • 2.4.3.3 Off-gas Treatment Building

 • 2.4.3.4 Vacuum Pipe Building

 • 2.4.3.5 Residual Heat Removal Service Water Tunnels

 • 2.4.3.6 Electrical Cable Tunnel from the Intake Pumping Station to the

Powerhouse

 • 2.4.3.7 Underground Concrete Encased Structures

 • 2.4.3.8 Earth Berm

 • 2.4.3.9 South Access Retaining Walls (added LRA Section)

The corresponding subsections of the SER (2.4.3.1 – 2.4.3.9) present the staff’s review findings

with respect to the Class 1 Group 3 structures for BFN.

2.4.3.1 Diesel Generator Buildings

2.4.3.1.1 Summary of Technical Information in the Application

In LRA Section 2.4.3.1, the applicant described the diesel generator buildings. The diesel

generator buildings provide structural support and shelter/protection for the diesel generators

(DGs) and other components within the scope of license renewal that are essential for the safe

shutdown of the plant when there is a sustained loss of off-site power. The Unit 1 and 2 diesel

generator building houses four DGs that provide power to the four shared Unit 1 and 2

shutdown boards that are located in the reactor buildings. The Unit 3 DG building houses four

DGs that provide power to the four separate unit shutdown boards that are located in the Unit 3

DG building.

The diesel generator buildings contain SR components that are relied upon to remain functional

during and following DBEs. The failure of NSR SSCs in the diesel generator buildings could

prevent the satisfactory accomplishment of an SR function. In addition, the DG buildings

perform functions that support fire protection and SBO.

The intended functions within the scope of license renewal include the following:

 • provides structural support and shelter/protection for SR and NSR components, and

components that are relied upon to demonstrate compliance with the fire protection and

SBO regulated events
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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 flood protection barrier for internal and external flooding events

 • provides a barrier for protection against internally or externally generated missiles

 • provides a pressure boundary

 • shelters and protects a component from the effects of weather or localized

environmental conditions

 • provides structural and functional support for structures and components within the

scope of license renewal

 • provides structural and functional support, for in-scope structures and components, by

an NSR component

In LRA Table 2.4.3.1, the applicant identified the following diesel generator building component

types that are within the scope of license renewal and subject to an AMR: 

 • caulking and sealants

 • compressible joints and seals

 • controlled leakage doors

 • fire barriers

 • hatches/plugs

 • masonry block

 • metal siding

 • electrical and I&C penetrations

 • mechanical penetrations

 • reinforced concrete beams, columns, walls, and slabs

 • structural steel beams, columns, plates, and trusses

2.4.3.1.2 Staff Evaluation

The staff reviewed LRA Section 2.4.3.1 and UFSAR Sections 8.5, 12.2.8 and 12.2.13 using the

evaluation methodology described in SER Section 2.4. The staff conducted its review

in accordance with the guidance described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant 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 2.4.3.1 identified an area in which additional information was

required to complete the review of the applicant’s scoping and screening results. The applicant

responded to the staff’s RAI as discussed below. 
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In RAI 2.4-8, dated December 20, 2004, the staff stated that LRA Section 2.4.3.1 refers to

Units 1 and 2 DG building and Unit 3 DG building. The license renewal drawing

0-10E201-01-LR shows a diesel generator building at the west side of the reactor building and

another DG building at the east side, without indicating which DG building is designated for

Units 1 and 2 shutdown function. The other building is intended for shutdown of the Unit 3

reactor. Therefore, the staff requested the applicant to clarify this ambiguity and explain why the

four separate Unit 3 shutdown boards are located in Unit 3 DG building, whereas the other four

shared Units 1 and 2 shutdown boards are located in the reactor buildings. Also regarding LRA

Table 2.4.3.1, the applicant was asked to identify other items such as structural steel

embedments, carbon steel boltings, reinforced concrete foundation footings, grouted concrete,

and water proofing membrane materials that require an AMR.

In its response, by letter dated January 24, 2005, the applicant stated:

The original layout for Browns Ferry was a two unit site with a common Diesel Generator

Building (DGB). Unit 3 was added after the initial design and provided with its own

Diesel Generator Building and shutdown board rooms within the DGB. The following

components are also located in the Units 1 and 2 Diesel Generator Building and Unit 3

Diesel Generator Building and are evaluated as Structures and Component Supports

commodities in LRA Section 2.4.8: 

 • ASME Equivalent Supports and Components 

 • Cable Trays and Supports

 • Conduit and Supports 

 • Electrical Panels, Racks, Cabinets, and Other Enclosures 

 • Equipment Supports and Foundations 

 • HVAC Duct Supports 

 • Instrument Line Supports 

 • Instrument Racks, Frames, Panels, & Enclosures 

 • Non-ASME Equivalent Supports and Components 

 • Stairs, Platforms, Grating Supports 

 • Tube Track 

The applicant noted that in-scope components evaluated in LRA Section 2.4.8 also include

support structural members, welds, bolting, anchorage and building concrete at anchorage

(including baseplate and grout) to the structure. Waterproofing membranes are not relied on to

support the intended functions of the structural components of the BFN structures.

The staff found the above response provided sufficient information to clarify the ambiguity noted

in RAI 2.4-8. Therefore, the staff’s concern described in RAI 2.4-8 is resolved.

2.4.3.1.3 Conclusion

The staff reviewed the LRA, related structural components, and RAI response described above

to determine whether any SSCs that should be within the scope of license renewal had not

been 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 had not been

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 had adequately identified the
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DG buildings components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the diesel generator buildings components that are subject to an AMR, as

required by 10 CFR 54.21(a)(1). 

2.4.3.2 Standby Gas Treatment Building

2.4.3.2.1 Summary of Technical Information in the Application

In LRA Section 2.4.3.2, the applicant described the SGT building. The SGT building houses

shared components for all three units and provides a protected environment for the SGT

system. The building consists of two double-barreled, reinforced concrete, box-frame structures

with closed ends. The two structures are located side-by-side and adjacent to the southwest

corner of the Unit 1 reactor building. The two structures also lie within the earth berm. One

structure houses two SGT trains, and the other structure houses the remaining SGT train.

The SGT building contains SR components that are relied upon to remain functional during and

following DBEs. The failure of NSR SSCs in the SGT building could prevent the satisfactory

accomplishment of an SR function. 

The intended functions within the scope of license renewal include the following:

 • provides structural support and shelter/protection for SR and NSR components

 • shelters and protects a component from the effects of weather or localized

environmental conditions

 • provides structural and functional support for structures and components within the

scope of license renewal

 • provides structural and functional support, for in-scope structures and components, by

an NSR component

In LRA Table 2.4.3.2, the applicant identified the following SGT building component types that

are within the scope of license renewal and subject to an AMR: 

 • electrical and I&C penetrations

 • mechanical penetrations

 • reinforced concrete beams, columns, walls, and slabs

2.4.3.2.2 Staff Evaluation

The staff reviewed LRA Section 2.4.3.2 and UFSAR Sections 5.3 and 12.2.10 using the

evaluation methodology described in SER Section 2.4. The staff conducted its review

in accordance with the guidance described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant
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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).

2.4.3.2.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether any SSCs

that should be within the scope of license renewal had not been 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 had not been 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 had adequately identified the SGT building

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the SGT building components that are subject to an AMR, as required by 10 CFR 54.21(a)(1). 

2.4.3.3 Off-Gas Treatment Building

2.4.3.3.1 Summary of Technical Information in the Application

In LRA Section 2.4.3.3, the applicant described the off-gas treatment building. The off-gas

treatment building is an underground structure that houses the off-gas system charcoal

adsorbers and the supporting equipment for BFN. The exterior walls and bottom slab are

designed and constructed to maintain their structural integrity if a partial collapse of the

reinforced concrete chimney were to occur during an external event (i.e., seismic, tornadic,

etc.). The maintained structural integrity would not permit water leakage into, or out of, the

building below an elevation of 566.25 feet.

The portions of the off-gas treatment building containing components subject to an AMR

include the exterior walls and bottom slab.

The off-gas treatment building contains SR components that are relied upon to remain

functional during and following DBEs.

The intended functions within the scope of license renewal include the following:

 • prevents the release of radiation into the surrounding groundwater from the failure or

collapse of the activated charcoal beds

 • provides a pressure boundary

In LRA Table 2.4.3.3, the applicant identified the following off-gas treatment building component

types that are within the scope of license renewal and subject to an AMR: 

 • caulking and sealants

 • mechanical penetrations

 • reinforced concrete beams, columns, walls, and slabs
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2.4.3.3.2 Staff Evaluation

The staff reviewed LRA Section 2.4.3.3 and UFSAR Section 12.2.14 using the evaluation

methodology described in SER Section 2.4. The staff conducted its review in accordance with

the guidance described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant 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 2.4.3.3 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. 

In RAI 2.4-9(a), dated December 20, 2004, the staff stated that LRA Section 2.4.3 lists several

structures, that are not shown in drawing 0-10E201-01-LR. In LRA Section 2.4.3.3, the off-gas

treatment building is described to have only exterior walls and bottom slab, implying that there

is no top slab for the building. Therefore, the staff requested the applicant to confirm that the

building has no top slab and no component types (e.g., electrical and I&C penetrations,

structural steel embedments, carbon steel boltings, reinforced concrete foundation footings,

grouted concrete, and water proofing membrane materials, etc.), other than those listed in LRA

Table 2.4.3.3, that require an AMR.

In its response, by letter dated January 24, 2005, the applicant stated:

Section 2.4.3.3 of the LRA identifies the Off-Gas Treatment Building as an underground

structure. The Off-Gas Treatment Building is an underground structure with exterior

walls, interior walls and slabs, bottom or foundation slab and a top slab. The exterior

walls and bottom slab are designed and constructed to maintain their structural integrity

during a partial collapse of the Reinforced Concrete Chimney during a design basis

event (tornado) so that they will not permit water leakage into or out of the building

below elevation 566.25 feet (Reference UFSAR 12.2.14). The top slab is not required

for the intended function of preventing release of radiation from the failure/collapse of

the activated charcoal beds into the surrounding groundwater. Other than the “Caulking

and Sealants,” “Penetrations, Mechanical,” and the “Reinforced Concrete Beams,

Columns, Walls and Slabs” components noted on LRA Table 2.4.3.3, there are no other

components that require an aging management review.

The staff found that the applicant had adequately responded to the part of RAI 2.4-9(a) related

to the off-gas treatment building structure. Therefore the staff’s concern described in

RAI 2.4-9(a) is resolved.
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2.4.3.3.3 Conclusion

The staff reviewed the LRA, related structural components, and RAI response described above

to determine whether any SSCs that should be within the scope of license renewal had not

been 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 had not been

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 had adequately identified the

off-gas treatment building components that are within the scope of license renewal, as required

by 10 CFR 54.4(a), and the off-gas treatment building components that are subject to an AMR,

as required by 10 CFR 54.21(a)(1). 

2.4.3.4 Vacuum Pipe Building

2.4.3.4.1 Summary of Technical Information in the Application

In LRA Section 2.4.3.4, the applicant described the vacuum pipe building. The vacuum pipe

building is a structure shared by all of the units. It is located underground and provides

structural support and shelter/protection for the condenser circulating water system vacuum

breaker components. These components prevent backflow from the warm water channel into

the intake channel. This ensures that the maximum temperature analysis assumptions, for

accident cooling systems, are maintained during accidents and events.

The vacuum pipe building contains SR components that are relied upon to remain functional

during and following DBEs. The failure of NSR SSCs in the vacuum pipe building could prevent

the satisfactory accomplishment of an SR function. 

The intended functions within the scope of license renewal include the following:

 • provides structural support and shelter/protection for SR and NSR components

 • shelters and protects a component from the effects of weather or localized

environmental conditions

 • provides structural and functional support for structures and components within the

scope of license renewal

 • provides structural and functional support, for in-scope structures and components, by

an NSR component

In LRA Table 2.4.3.4, the applicant identified the following vacuum pipe building component

types that are within the scope of license renewal and subject to an AMR: 

 • hatches and plugs

 • electrical and I&C penetrations

 • mechanical penetrations

 • reinforced concrete beams, columns, walls, and slabs
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2.4.3.4.2 Staff Evaluation

The staff reviewed LRA Section 2.4.3.4 and UFSAR Section 12.2.7.8.3 using the evaluation

methodology described in SER Section 2.4. The staff conducted its review in accordance with

the guidance described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant 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 2.4.3.4 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. 

In RAI 2.4-9(b), dated December 20, 2004, the staff stated that LRA Section 2.4.3 lists several

structures that are not shown in drawing 0-10E201-01-LR. Therefore, the staff requested the

applicant to describe the specific location of the vacuum pipe building and confirm that there

are no items such as structural steel embedments, carbon steel boltings, reinforced concrete

foundation footings, grouted concrete, compressible joints and seals, waterproofing membrane

and caulking materials that require an AMR.

In its response, by letter dated January 24, 2005, the applicant stated:

The vacuum pipe building is an underground structure accessed through a manhole and

contains the condenser circulating water system vacuum breaker components that

prevent back flow from the warm water channel to the intake channel (Reference

UFSAR 12.2.7.8.3). The vacuum pipe building is an underground structure located

south-east of the plant administration building as depicted on TVA drawing 0-10E201-01

and LR drawing 0-10E201-01-LR. The following components are also located in the

vacuum pipe building and are evaluated as structures and component supports

commodities in LRA Section 2.4.8:

 • Conduit and Supports 

 • Electrical Panels, Racks, Cabinets, and Other Enclosures 

 • Non-ASME Equivalent Supports and Components 

The applicant noted that for in-scope components evaluated in LRA Section 2.4.8, the

components also include support structural members, welds, bolting, anchorage and building

concrete at anchorage (including base plate and grout) to the structure. Waterproofing

membranes are not relied upon to support the intended functions of the structural components

of BFN structures.
2-173

The staff found that the applicant had adequately responded to RAI 2.4-9(b) concerning the

vacuum pipe building structure. Therefore, the staff’s concern described in RAI 2.4-9(b) is

resolved.

2.4.3.4.3 Conclusion

The staff reviewed the LRA, related structural components, and RAI response described above

to determine whether any SSCs that should be within the scope of license renewal had not

been 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 had not been

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 had adequately identified the

vacuum pipe building components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the vacuum pipe building components that are subject to an AMR, as

required by 10 CFR 54.21(a)(1). 

2.4.3.5 Residual Heat Removal Service Water Tunnels

2.4.3.5.1 Summary of Technical Information in the Application

In LRA Section 2.4.3.5, the applicant described the RHRSW tunnels. The RHRSW tunnels are

underground, multi-plate, arch tunnels that protect SR piping systems. This includes the

RHRSW and EECW supply and discharge piping that penetrates the south wall of the reactor

building and is buried, below grade, near the south end of the tunnel.

The failure of an NSR SSC in the RHRSW tunnel could prevent the satisfactory

accomplishment of an SR function. The RHRSW tunnel also performs functions that support

fire protection. 

The intended functions within the scope of license renewal include the following:

 • provides structural support and shelter/protection for SR and NSR components, and

components that are relied upon to demonstrate compliance with the fire protection

regulated event

 • prevents debris from entering a system or component

 • shelters and protects a component from the effects of weather or localized

environmental conditions

 • provides structural and functional support, for in-scope structures and components, by

an NSR component

In LRA Table 2.4.3.5, the applicant identified the following RHRSW tunnel component types

that are within the scope of license renewal and subject to an AMR: 

 • compressible joints and seals

 • electrical and I&C penetrations

 • piles

 • tunnels
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2.4.3.5.2 Staff Evaluation

The staff reviewed LRA Section 2.4.3.5 using the evaluation methodology described in SER

Section 2.4. The staff conducted its review in accordance with the guidance described in

SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not

omitted from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). The staff then reviewed those components that the applicant 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 2.4.3.5 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. 

In RAI 2.4-9(c), dated December 20, 2004, the staff stated that LRA Section 2.4.3, Class 1

Group 3 Structures, lists several BFN structures that are not shown in drawing

0-10E201-01-LR. Therefore, the staff requested the applicant to describe the specific location

of the RHRSW tunnels including their embedded boundaries in drawing 0-10E201-01-LR. The

staff also requested the applicant to identify, as appropriate, items requiring an AMR that are

part of the service water tunnels, such as structural steel embedments, carbon steel boltings,

reinforced concrete beams, walls, slabs and foundation footings, grouted concrete, mechanical

penetrations, waterproofing membrane and caulking materials.

In its response, by letter dated January 24, 2005, the applicant stated:

The RHRSW tunnels are underground multi-plate arch tunnels that are buried in the

earth berm. The north end of the tunnel terminates at the south wall of the reactor

building. The south end of the tunnel is open to the outside on the south end of the earth

berm. There are two tunnels for each reactor building. The following components are

also located in the RHRSW tunnels and are evaluated as structures and component

supports commodities in LRA Section 2.4.8:

 • ASME Equivalent Supports and Components 

 • Conduit and Supports 

 • Electrical Panels, Racks, Cabinets, and Other Enclosures 

 • Non-ASME Equivalent Supports and Components 

The applicant noted that for in-scope components evaluated in LRA Section 2.4.8, the

components also include support structural members, welds, bolting, anchorage and building

concrete at anchorage (including base plate and grout) to the structure. Waterproofing

membranes are not relied upon to support the intended functions of the structural components

of BFN structures.
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The staff found that the applicant had adequately responded to RAI 2.4-9(c) related to the

RHRSW structure. Therefore, the staff’s concern described in RAI 2.4-9(c) is resolved.

2.4.3.5.3 Conclusion

The staff reviewed the LRA, related structural components, and RAI response described above

to determine whether any SSCs that should be within the scope of license renewal had not

been 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 had not been

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 had adequately identified the

RHRSW tunnels components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the RHRSW tunnels components that are subject to an AMR, as required

by 10 CFR 54.21(a)(1). 

2.4.3.6 Electrical Cable Tunnel from the Intake Pumping Station to the Powerhouse

2.4.3.6.1 Summary of Technical Information in the Application

In LRA Section 2.4.3.6, the applicant described the electrical cable tunnel from the intake

pumping station to the powerhouse, which is a Class I structure. The structure is an

underground, concrete-encased tunnel that provides structural support and shelter/protection

for power cables. These power cables are intended for components in the intake pumping

station and include the RHRSW system, EECW system, and electric fire pumps. The tunnel

runs east-west under the southern portion of the turbine buildings.

The electrical cable tunnel from the intake pumping station to the powerhouse structure

contains SR components that are relied upon to remain functional during and following DBEs.

The failure of NSR SSCs in the electrical cable tunnel from the intake pumping station to the

powerhouse structure could prevent the satisfactory accomplishment of an SR function. In

addition, the electrical cable tunnel from the intake pumping station to the powerhouse structure

performs functions that support fire protection. 

The intended functions within the scope of license renewal include the following:

 • provides structural support and shelter/protection for SR and NSR components, and

components that are relied upon to demonstrate compliance with the fire protection

regulated event

 • provides a rated fire barrier to confine or retard a fire from spreading to or from adjacent

areas of the plant

 • shelters and protects a component from the effects of weather or localized

environmental conditions

 • provides structural and functional support for structures and components within the

scope of license renewal

In LRA Table 2.4.3.6, the applicant identified the following electrical cable tunnel component

types that are within the scope of license renewal and subject to an AMR: 
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 • fire barrier

 • electrical and I&C penetrations

 • tunnels

The electrical cable tunnel from the intake pumping station to the powerhouse is an

underground concrete-encased tunnel that provides structural support and shelter/protection

for the power cables for components (including the RHRSW System, EECW System, and

the electric fire pumps) in the intake pumping station. The tunnel also runs east-west under

the southern portion of the turbine buildings. 

2.4.3.6.2 Staff Evaluation

The staff reviewed LRA Section 2.4.3.6 using the evaluation methodology described in SER

Section 2.4. The staff conducted its review in accordance with the guidance described in

SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not

omitted from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). The staff then reviewed those components that the applicant 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 2.4.3.6 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.

In RAI 2.4-9(d), dated December 20, 2004, the staff stated that LRA Section 2.4.3, Class 1

Group 3 Structures, lists several structures that are not shown in drawing 0-10E201-01-LR.

Therefore, the staff requested the applicant to describe the specific locations of the electrical

cable tunnel from the intake pumping station to the powerhouse, including the portion running

east-west under the southern portion of the turbine buildings. The staff also requested the

applicant to identify items such as structural steel embedments, carbon steel boltings,

reinforced concrete beams, walls, slabs, and foundation footings, grouted concrete, mechanical

penetrations, and waterproofing membrane and caulking materials that require an AMR.

In its response, by letter dated January 24, 2005, the applicant stated:

The Electrical Cable Tunnel is an underground concrete encased tunnel that runs from

the northwest corner of the Intake Pumping Station (IPS) to the southeast corner of the

unit 3 Turbine Building and then east-west along the southern portion of the BFN

Turbine Building. The following components are also located in the Electrical Cable

Tunnel and are evaluated as Structures and Component Supports commodities in LRA

Section 2.4.8:

 • Cable Trays and Supports

 • Conduit and Supports 

 • Electrical Panels, Racks, Cabinets, and Other Enclosures 
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The applicant noted that for in-scope components evaluated in LRA Section 2.4.8, the

components also include support structural members, welds, bolting, anchorage and building

concrete at anchorage (including base plate and grout) to the structure. Waterproofing

membranes are not relied upon to support the intended functions of the structural components

of BFN structures. 

The staff found that the applicant had adequately responded to RAI 2.4-9(d) related to the

electrical cable tunnel structure. Therefore, the staff’s concern described in RAI 2.4-9(d) is

resolved.

2.4.3.6.3 Conclusion

The staff reviewed the LRA, related structural components, and RAI response described above

to determine whether any SSCs that should be within the scope of license renewal had not

been 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 had not been

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 had adequately identified the

electrical cable tunnel components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the electrical cable tunnel components that are subject to an AMR, as

required by 10 CFR 54.21(a)(1). 

2.4.3.7 Underground Concrete Encased Structures

2.4.3.7.1 Summary of Technical Information in the Application

In LRA Section 2.4.3.7, the applicant described the underground concrete encased structures.

The underground concrete encased structures include SR manholes, handholes and duct

banks that span between the SR structures, manholes, and handholes. This group of structures

also includes those manholes, handholes, and duct banks that are required to support the SBO

regulated event.

The underground concrete encased structures contain SR components that are relied upon to

remain functional during and following DBEs. The failure of NSR SSCs in the underground

concrete encased structures could prevent the satisfactory accomplishment of an SR function.

In addition, the underground concrete encased structures performs functions that support fire

protection and SBO.

The intended functions within the scope of license renewal include the following:

 • provides structural support and shelter/protection for SR and NSR components, and

components that are relied upon to demonstrate compliance with the fire protection and

SBO regulated events

 • provides flood protection barrier for internal and external flooding events

 • shelters and protects a component from the effects of weather or localized

environmental conditions
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 • provides structural and functional support for structures and components within the

scope of license renewal

 • provides structural and functional support, for in-scope structures and components, by

an NSR component

In LRA Table 2.4.3.7, the applicant identified the following underground concrete encased

structures component types that are within the scope of license renewal and subject to an AMR: 

 • caulking and sealants

 • duct banks, manholes

 • electrical and I&C penetrations

 • penetrations, mechanical

2.4.3.7.2 Staff Evaluation

The staff reviewed LRA Section 2.4.3.7 using the evaluation methodology described in SER

Section 2.4. The staff conducted its review in accordance with the guidance described in

SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not

omitted from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). The staff then reviewed those components that the applicant 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 2.4.3.7 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

In RAI 2.4-9(e), dated December 20, 2004, the staff stated that LRA Section 2.4.3, Class 1

Group 3 structures lists several BFN structures on page 2.4-12 that are not shown in drawing

0-10E201-01-LR. Therefore, the staff requested the applicant to list the in-scope structures that

have one or more of the underground concrete encased structures described in LRA

Section 2.4.3.7. The staff also requested the applicant to identify items such as structural steel

embedments, carbon steel boltings, reinforced concrete walls, slabs and foundation footings,

grouted concrete, and waterproofing membrane that require an AMR.

In its response, by letter dated January 24, 2005, the applicant stated :

The in-scope structures described in LRA Section 2.4.3.7 include the following:

 • Safety-related handhole (HH) No. 16, located in the yard area north-west of the

Intake Pumping Structure (IPS) and safety-related handhole (HH) No. 26,

located in the yard area north-east of the Unit 3 Diesel Generator Building (DGB)

and south of Condensate Storage Tanks Nos. 1, 2, and 3.
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 • Safety-related concrete duct bank (inaccessible) that spans from the Unit 1 & 2

Diesel Generator Building to the Standby Gas Treatment Building, safety-related

concrete duct bank (inaccessible) that spans from the IPS to HH No. 16 to HH

No. 26 and to the Electrical Cable Tunnel from the IPS to the Powerhouse, SR

concrete duct bank (inaccessible) that spans from the unit 3 Diesel Generator

Building to the Electrical Cable Tunnel from the IPS to the Powerhouse, and the

safety-related concrete duct bank (inaccessible) that spans from the

Containment Atmosphere Dilution Storage Tank’s A and B foundations to the

Reactor Building. 

 • Manholes A and B which provide access to the concrete tunnel located in the

161 kV and 500 kV Switchyards that support the 10 CFR 54.4(a)(3) SBO

regulated event. NOTE: The concrete tunnel located in the 161 kV and 500 kV

switchyards is within the scope of license renewal and identified in LRA

ections 2.4.7.5 and 2.4.7.6, respectively, as component type tunnels.

 • Handholes 1 - 13 and associated duct banks (inaccessible) located in the

transformer yard on the north side of the Turbine Building that support the

10 CFR 54.4(a)(3) SBO regulated event.

 • The following components are also located in the Underground Concrete

Encased Structures and are evaluated as Structures and Component Supports

commodities in LRA Section 2.4.8:

 - Cable Trays and Supports

 - Conduit and Supports 

 - Electrical Panels, Racks, Cabinets, and Other Enclosures 

 - Non-ASME Equivalent Supports and Components 

The applicant also noted that for in-scope components evaluated in LRA Section 2.4.8, the

components also include support structural members, welds, bolting, anchorage and building

concrete at anchorage (including base plate and grout) to the structure. Waterproofing

membranes are not relied upon to support the intended functions of the structural components

of BFN structures. 

The staff found that the applicant had adequately responded to RAI 2.4-9(e) related to

underground concrete encased structures. Therefore, the staff’s concern described in

RAI 2.4-9(e) is resolved.

2.4.3.7.3 Conclusion

The staff reviewed the LRA, related structural components, and RAI response described above

to determine whether any SSCs that should be within the scope of license renewal had not

been 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 had not been

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 had adequately identified the

underground concrete encased structures components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and the underground concrete encased structures

components that are subject to an AMR, as required by 10 CFR 54.21(a)(1). 
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2.4.3.8 Earth Berm

2.4.3.8.1 Summary of Technical Information in the Application

In LRA Section 2.4.3.8, the applicant described the earth berm. The earth berm is classified as

an SR earthen embankment and is common to BFN. The earth berm extends along the west,

south, and east walls of the reactor building from the Unit 1 DG building to the Unit 3 DG

building. The equipment access lock, the RHRSW tunnels, the vent vaults, and the SGT

building are all located within the earth berm.

The earth berm contains SR components that are relied upon to remain functional during and

following DBEs. 

The intended function, within the scope of license renewal, is to provide structural and

functional support for in-scope structures and features.

In LRA Table 2.4.3.8, the applicant identified the following earth berm component type that is

within the scope of license renewal and subject to an AMR: 

 • intake canals, dikes, embankments

2.4.3.8.2 Staff Evaluation

The staff reviewed LRA Section 2.4.3.8 and UFSAR Sections 12.2.9 and 12.2.10 using the

evaluation methodology described in SER Section 2.4. The staff conducted its review

in accordance with the guidance described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant 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).

2.4.3.8.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether any SSCs

that should be within the scope of license renewal had not been 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 had not been 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 had adequately identified the earth berm components

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the earth berm

components that are subject to an AMR, as required by 10 CFR 54.21(a)(1). 

Section 2.4.3.9. In earlier RAI 2.4-1 response, dated January 24, 2005, the applicant stated

that the south access retaining walls were inadvertently omitted. The retaining walls are SR
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structural features that maintain the stability of the earth berm, therefore are included in the

scope of license renewal. In Attachment 2 to its letter, the applicant added LRA Section 2.4.3.9,

as discussed below.

2.4.3.9 South Access Retaining Walls

In added LRA Section 2.4.3.9, the applicant described the south access retaining walls. The

south access retaining walls are required to support the existing earth berm for the construction

of a new temporary access building. This access building will allow Unit 1 recovery personnel

entry into the Unit 1 reactor building during the recovery of Unit 1. These retaining walls have

been classified as SR to match the safety function of the earth berm. These retaining walls are

located east of the equipment access lock.

The south access retaining walls contain SR components that are relied upon to remain

functional during and following DBEs. 

The intended function, within the scope of license renewal, is to provide structural and

functional support, for in-scope structures and components, by an SR component.

In added LRA Table 2.4.3.9, the applicant identified the reinforced concrete beams, columns,

walls, and slabs component type that is within the scope of license renewal and subject to an

AMR.

2.4.3.9.2 Staff Evaluation

The staff reviewed added LRA Section 2.4.3.9 using the evaluation methodology described in

SER Section 2.4. The staff conducted its review in accordance with the guidance described in

SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

added section of the LRA in accordance with the requirements of 10 CFR 54.4(a) to verify that

the applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant 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).

2.4.3.9.3 Conclusion

The staff reviewed the added LRA Section 2.4.3.9 and related structural/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 had adequately identified the

south access retaining walls components that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and that the applicant had adequately identified the south access

retaining walls components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-182

2.4.4 Class 1 Group 6 Structures

In LRA Section 2.4.4, the applicant identified the structures and components of the Class 1

Group 6 structures that are subject to an AMR for license renewal.

The applicant described the supporting structures and components of the Class 1 Group 6

structures in the following sections of the LRA:

 • 2.4.4.1 intake pumping station

 • 2.4.4.2 gate structure No. 3

 • 2.4.4.3 intake channel

 • 2.4.4.4 north bank of cool water channel east of gate structure No. 2

 • 2.4.4.5 south dike of cool water channel between gate structure Nos. 2 and 3

The corresponding subsections of the SER, 2.4.4.1 – 2.4.4.5, present the staff’s review findings

with respect to the Class 1 Group 6 structures.

2.4.4.1 Intake Pumping Station

2.4.4.1.1 Summary of Technical Information in the Application

In LRA Section 2.4.4.1, the applicant described the intake pumping station, which is a Class 1

structure constructed of reinforced concrete. The intake pumping station houses components

for BFN and provides structural support and shelter/protection for the condenser circulating

water pumps, the electric fire pumps, and the pumps that supply the RHRSW and the EECW

systems. The station also protects SR equipment and components, such as the pumps

supplying the RHRSW and EECW systems, from design-basis events such as earthquakes,

floods, and tornadoes.

The intake pumping station contains SR components that are relied upon to remain functional

during and following DBEs. The failure of NSR SSCs in the intake pumping station could

prevent the satisfactory accomplishment of an SR function. In addition, the intake pumping

station performs functions that support fire protection and SBO.

The intended functions within the scope of license renewal include the following:

 • provides structural support and shelter/protection for SR and NSR components, and

components relied upon to demonstrate compliance with the fire protection and SBO

regulated events

 • provides a rated fire barrier to confine or retard a fire from spreading to or from adjacent

areas of the plant

 • provides a flood protection barrier for internal and external flooding events

 • shelters and protects a component from the effects of weather or localized

environmental conditions

 • provides structural and functional support for structures and components within the

scope of license renewal
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 • provides structural and functional support, for in-scope structures and components, by

an NSR component

In LRA Table 2.4.4.1, the applicant identified the following intake pumping station component

types that are within the scope of license renewal and subject to an AMR: 

 • caulking and sealants

 • compressible joints and seals

 • controlled leakage doors

 • fire barriers

 • masonry block

 • electrical and I&C penetrations

 • mechanical penetrations

 • reinforced concrete beams, columns, walls, and slabs

 • structural steel beams, columns, plates, and trusses

2.4.4.1.2 Staff Evaluation

The staff reviewed LRA Section 2.4.4.1 and UFSAR Sections 12.2.7 and 12.2.16 using the

evaluation methodology described in SER Section 2.4. The staff conducted its review

in accordance with the guidance described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant 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 2.4.4.1 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. 

In RAI 2.4-10(a), dated December 20, 2004, the staff requested the applicant to provide

additional information regarding the intake pumping station structure. Specifically, the RAI

requested the applicant to identify, as applicable, items such as hatches and plugs, structural

steel embedments, carbon steel boltings, reinforced concrete foundation footings, grouted

concrete, and waterproofing membrane materials that require an AMR.

In its response, by letter dated January 24, 2005, the applicant stated:

The following components are also located in the intake pumping station and are

evaluated as structures and component supports commodities in LRA Section 2.4.8:

 • ASME Equivalent Supports and Components 

 • Cable Trays and Supports

 • Conduit and Supports 
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 • Electrical Panels, Racks, Cabinets, and Other Enclosures 

 • Equipment Supports and Foundations 

 • Instrument Line Supports 

 • Non-ASME Equivalent Supports and Components 

 • Stairs, Platforms, Grating Supports 

 • Tube Track

The applicant noted that for in-scope components evaluated in LRA Section 2.4.8, the

components also include support structural members, welds, bolting, anchorage and building

concrete at anchorage (including base plate and grout) to the structure. Waterproofing

membranes are not relied upon to support the intended functions of the structural components

of BFN structures. 

The staff found that the applicant had adequately responded to RAI 2.4-10(a) related to the

intake pumping station structure. Therefore, the staff’s concern described in RAI 2.4-10(a) is

resolved.

2.4.4.1.3 Conclusion

The staff reviewed the LRA, related structural components, and RAI response described above

to determine whether any SSCs that should be within the scope of license renewal had not

been 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 had not been

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 had adequately identified the

intake pumping station components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the intake pumping station components that are subject to an AMR, as

required by 10 CFR 54.21(a)(1). 

2.4.4.2 Gate Structure No. 3

2.4.4.2.1 Summary of Technical Information in the Application

In LRA Section 2.4.4.2, the applicant described the gate structure No. 3, which is a Class 1

structure common to all three of the units. The structure acts as a skimmer wall for water drawn

from Wheeler Reservoir and used in the plant for cooling. Gate structure No 3 is designed so

that a sufficient flow of water from Wheeler Reservoir is provided to the intake channel, in order

to supply the RHRSW and the EECW systems. Gate structure No. 3 is located at the southeast

end of the plant, below the intake pumping station and the intake channel.

Gate structure No. 3 contains SR components that are relied upon to remain functional during

and following DBEs. In addition, gate structure No. 3 performs functions that support fire

protection and SBO.

The intended functions within the scope of license renewal include the following:

 • ensures a source of cooling water to SR components
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 • ensures a source of cooling water to components relied upon to demonstrate

compliance with the fire protection and SBO events

 • provides for flow distribution

 • provides structural and functional support for structures and components within the

scope of license renewal

In LRA Table 2.4.4.2, the applicant identified the following gate structure No. 3 component

types that are within the scope of license renewal and subject to an AMR: 

 • piles

 • reinforced concrete beams, columns, walls, and slabs

 • structural steel beams, columns, plates, and trusses

2.4.4.2.2 Staff Evaluation

The staff reviewed LRA Section 2.4.4.2 and UFSAR Sections 11.6 and 12.2.7 using the

evaluation methodology described in SER Section 2.4. The staff conducted its review

in accordance with the guidance described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant 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).

2.4.4.2.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether any SSCs

that should be within the scope of license renewal had not been 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 had not been 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 had adequately identified the gate structure No. 3

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the gate structure No. 3 components that are subject to an AMR, as required by

10 CFR 54.21(a)(1). 

2.4.4.3 Intake Channel

2.4.4.3.1 Summary of Technical Information in the Application

In LRA Section 2.4.4.3, the applicant described the intake channel, which is common to all

three units and provides an excavated channel that extends from the intake pumping station to

the river channel that would exist if the Wheeler Dam failed. The channel provides a source of

water to the condenser circulating water system and the other plant cooling systems during
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normal operation. The channel also provides a source of cooling water, post-transient and

post-accident, for decay heat removal, containment cooling, spent fuel cooling, control bay

cooling, essential equipment cooling, and fire protection. In addition, the channel can provide

sufficient flow and heat sink capacity to maintain a safe shutdown following a failure of the

downstream Wheeler Dam.

The intake channel contains SR components that are relied upon to remain functional during

and following DBEs. In addition, the intake channel performs functions that support fire

protection and SBO.

The intended functions within the scope of license renewal include the following:

 • ensures a source of cooling water to SR components

 • ensures a source of cooling water to components relied upon to demonstrate

compliance with the fire protection and SBO events

 • provides a source of cooling water

 • provides structural and functional support for structures and components within the

scope of license renewal

In LRA Table 2.4.4.3, the applicant identified the following intake channel component type that

is within the scope of license renewal and subject to an AMR: 

 • intake canals, dikes, embankments

2.4.4.3.2 Staff Evaluation

The staff reviewed LRA Section 2.4.4.3 and UFSAR Sections 2.4.2 and 12.2.7 using the

evaluation methodology described in SER Section 2.4. The staff conducted its review

in accordance with the guidance described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant 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).

2.4.4.3.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether any SSCs

that should be within the scope of license renewal had not been 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 had not been 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 had adequately identified the intake channel
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components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the intake channel components that are subject to an AMR, as required by 10 CFR 54.21(a)(1). 

2.4.4.4 North Bank of the Cool Water Channel East of Gate Structure No. 2

2.4.4.4.1 Summary of Technical Information in the Application

In LRA Section 2.4.4.4, the applicant described the north bank of the cool water channel east of

gate structure No. 2. The structure is an earthen embankment that is located on the north side

of the cool water channel and south of the reactor buildings. The structure is SR, with a sloped

portion protected by vegetation and rock rip-rap. The bank is designed to protect the buried

RHRSW system discharge piping that is located within the bank that discharges into the

Wheeler Reservoir.

The north bank of the cool water channel east of gate structure No. 2 contains SR components

that are relied upon to remain functional during and following DBEs. In addition, the structure

performs functions that support fire protection and SBO.

The intended functions within the scope of license renewal include the following:

 • provides for structural support of the buried SR components, namely piping, and

components relied upon to demonstrate compliance with the fire protection and SBO

regulated events

 • provides structural and functional support for structures and components within the

scope of license renewal

In LRA Table 2.4.4.4, the applicant identified the following component type in the north bank of

the cool water chanel east of gate structure No. 2 that is within the scope of license renewal

and subject to an AMR: 

 • intake canals, dikes, embankments

2.4.4.4.2 Staff Evaluation

The staff reviewed LRA Section 2.4.4.4 and UFSAR Section 12.2.7 using the evaluation

methodology described in SER Section 2.4. The staff conducted its review in accordance with

the guidance described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant 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).
2-188

2.4.4.4.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether any SSCs

that should be within the scope of license renewal had not been 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 had not been 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 had adequately identified the components of the north

bank of the cool water channel east of gate structure No. 2 that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and the components of the north bank of the cool

water channel east of gate structure No. 2 that are subject to an AMR, as required by

10 CFR 54.21(a)(1). 

2.4.4.5 South Dike of Cool Water Channel between Gate Structure Nos. 2 and 3

2.4.4.5.1 Summary of Technical Information in the Application

In LRA Section 2.4.4.5, the applicant described the south dike of the cool water channel

between gate structure Nos. 2 and 3. The structure is an earthen dike that is located on the

south side of the cool water channel and forms a boundary with the Wheeler Reservoir on the

north side. The dike is an SR earthen structure that has a sloped portion that is protected with

vegetation and rock rip-rap. The dike is designed to protect the buried RHRSW system

discharge piping that is located within the dike and that discharges into Wheeler Reservoir.

The portions of the south dike of cool water channel between gate structure Nos. 2 and 3

structure containing components subject to an AMR are those portions located above the

RHRSW system discharge piping.

The south dike of the cool water channel between gate structure Nos. 2 and 3 contains SR

components that are relied upon to remain functional during and following DBEs. In addition,

the dike performs functions that support fire protection and SBO.

The intended functions within the scope of license renewal include the following:

 • provides structural support of buried SR components, namely piping, and components

relied upon to demonstrate compliance with the fire protection and SBO regulated

events

 • provides structural and functional support for structures and components within the

scope of license renewal

In LRA Table 2.4.4.5, the applicant identified the following component types in the south dike of

cool water channel between gate structure Nos. 2 and 3 that are within the scope of license

renewal and subject to an AMR:

 • intake canals, dikes, embankments
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2.4.4.5.2 Staff Evaluation

The staff reviewed LRA Section 2.4.4.5 and UFSAR Section 12,2.7 using the evaluation

methodology described in SER Section 2.4. The staff conducted its review in accordance with

the guidance described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant 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 2.4.4.5 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. 

In RAI 2.4-6, dated December 20, 2004, the staff stated that the LRA Section 2.4.4.5 states that

the portion of the structure that contains components requiring an AMR is the portion above the

RHRSW system discharge piping. Therefore, the staff requested applicant to clarify if the entire

south dike of cooling water channel between gate structure Nos. 2 and 3, or only the portion

indicated, is designated to be within the scope requiring an AMR. The staff also stated that, if

the applicant scoped only a portion of the south dike structure as requiring an AMR, the staff

wanted the applicant to discuss the basis for narrowing the scope. The staff required the

applicant to clearly define the boundary within the AMR scope.

In its response, by letter dated January 24, 2005, the applicant stated:

Only the portion of the south dike of the cool water channel between gate structure Nos.

2 and 3 above the RHRSW discharge piping system plus approximately 30 feet on

either side of the piping is within the scope of License Renewal and requires an AMR.

The earthen dike provides a structural support intended function as noted in LRA

Table 2.4.4.5 for the RHRSW discharge piping system and that portion of the dike has

been qualified for a seismic event.

The staff found the above clarification provided by the applicant adequate and acceptable. The

staff’s concern described in RAI 2.4-6 is resolved.

2.4.4.5.3 Conclusion

The staff reviewed the LRA, related structural components, and RAI response described above

to determine whether any SSCs that should be within the scope of license renewal had not

been 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 had not been

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 had adequately identified the

components in the south dike of the cool water channel between gate structure Nos. 2 and 3

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the
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components in the south dike of the cool water channel between gate structure Nos. 2 and 3

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

2.4.5 Class 1 Group 8 Structures

In LRA Section 2.4.5, the applicant identified the structures and components of the Class 1

Group 8 structures that are subject to an AMR for license renewal.

The applicant described the supporting structures and components of the Class 1 Group 8

structures in the following sections of the LRA:

 • 2.4.5.1 condensate water storage tanks’ foundations and trenches

 • 2.4.5.2 containment atmosphere dilution storage tanks’ foundations

The corresponding subsections of the SER 2.4.5.1 – 2.4.5.2, present the staff’s review findings

with respect to the Class 1 Group 8 structures for BFN.

2.4.5.1 Condensate Water Storage Tanks’ Foundations and Trenches

2.4.5.1.1 Summary of Technical Information in the Application

In LRA Section 2.4.5.1, the applicant described the condensate water storage tanks’

foundations and trenches. The condensate water storage tanks’ foundations and trenches are a

shared feature for BFN. Five 500,000-gallon capacity tanks are supported on reinforced

concrete ring foundations or on reinforced concrete slabs, on grade, with a sand bed. Only

condensate water storage tank Nos. 1, 2, and 3 are within the scope of license renewal.

Therefore, the foundations, trenches, and components for these tanks are also within the scope

of license renewal.

The condensate water storage tanks’ foundations and trenches are concrete structures that

provide structural support to ensure that the condensate water storage tanks can provide: (1) a

source of water makeup to the condenser hotwells and the CRD hydraulic system, during

normal operations; (2) high purity water for miscellaneous makeup uses throughout the plant

(e.g., demineralizer backwash and spent fuel pool makeup); and (3) a source of clean water to

the HPCI and RCIC systems, when required for test; for reactor vessel makeup during

accidents and regulated events; and to the core spray systems, when required for test.

The foundations and trenches for the three condensate water storage tanks that provide the

normal water supply to the units, contain components requiring an AMR.

The condensate water storage tanks’ foundations and trenches contain SR components that

are relied upon to remain functional during and following DBEs. In addition, the condensate

water storage tanks’ foundations and trenches perform functions that support fire protection

and SBO.
2-191

The intended functions within the scope of license renewal include the following:

 • provides physical support and shelter/protection for components that are relied upon to

demonstrate compliance with the fire protection and SBO regulated events

 • shelters and protects a component from the effects of weather or localized

environmental conditions

 • provides structural and functional support for structures and components within the

scope of license renewal

 • provides structural and functional support, for in-scope structures and components, by

an NSR component

In LRA Table 2.4.5.1, the applicant identified the following condensate water storage tanks’

foundations and trenches component types that are within the scope of license renewal and

subject to an AMR: 

 • equipment supports and foundations

 • electrical and I&C penetrations

 • mechanical penetrations

 • structural steel beams, columns, plates, and trusses

 • trenches

2.4.5.1.2 Staff Evaluation

The staff reviewed LRA Section 2.4.5.1 and UFSAR Section 11.9 using the evaluation

methodology described in SER Section 2.4. The staff conducted its review in accordance with

the guidance described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant 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 2.4.5.1 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. 

In RAI 2.4-10(b), dated December 20, 2004, the applicant was asked to provide additional

information regarding the condensate water storage tank’s foundation and trenches. The staff

also requested the applicant to confirm that the equipment supports and foundations as well as

the trenches listed in LRA Table 2.4.5.1 consist of reinforced concrete components and to

identify items such as structural steel embedments, carbon steel boltings, grouted concrete,

and waterproofing membrane materials that require an AMR.
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In its response, by letter dated January 24, 2005, the applicant stated:

Regarding the Condensate Water Storage Tank’s Foundation and Trenches,

“Equipment Supports and Foundations” as well as “Trenches” components listed in

Table 2.4.5.1 consist of reinforced concrete and this is confirmed in Table 3.5.2.17 of

the LRA. Note that the Condensate Storage Tanks are supported on a reinforced

concrete ring foundation and the earthen fill material (rock and sand) inside the ring is

identified as Item 1 of Table 3.5.2.17. The following components are also located on the

Condensate Water Storage Tanks Foundations and Trenches and are evaluated as

Structures and Component Supports commodities in LRA Section 2.4.8:

 • Conduit and Supports 

 • Electrical Panels, Racks, Cabinets, and Other Enclosures 

 • Instrument Racks, Frames, Panels, & Enclosures 

 • Non-ASME Equivalent Supports and Components 

The applicant noted that for in-scope components evaluated in LRA Section 2.4.8, the

components also include support structural members, welds, bolting, anchorage and building

concrete at anchorage (including base plate and grout) to the structure. Waterproofing

membranes are not relied upon to support the intended functions of the structural components

of BFN structures.

The staff found that the applicant had adequately responded to RAI 2.4-10(b) related to the

condensate water storage tanks’ foundations and trenches structures. Therefore, the staffs

concern described in RAI 2.4-10(b) is resolved.

2.4.5.1.3 Conclusion

The staff reviewed the LRA, related structural components, and RAI response described above

to determine whether any SSCs that should be within the scope of license renewal had not

been 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 had not been

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 had adequately identified the

condensate water storage tanks’ foundations and trenches components that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and the condensate water storage

tanks’ foundations and trenches components that are subject to an AMR, as required by

10 CFR 54.21(a)(1). 

2.4.5.2 Containment Atmosphere Dilution Storage Tanks’ Foundations

2.4.5.2.1 Summary of Technical Information in the Application

In LRA Section 2.4.5.2, the applicant described the CAD storage tanks’ foundations. The tanks’

foundations are reinforced concrete slabs on grade, or foundations, that provide structural

support for the tanks. These tanks are used by the CAD system to control the concentration of

combustible gases in the primary containment after an accident, and to provide a backup

pneumatic supply to selected components when the control air system is unavailable.
2-193

The CAD system storage tanks’ foundations contain SR components that are relied upon to

remain functional during and following DBEs. In addition, the CAD storage tanks’ foundations

perform functions that support fire protection and SBO.

The intended functions within the scope of license renewal include the following:

 • provides structural support for SR components and components relied upon to

demonstrate compliance with the fire protection and SBO regulated events

 • provides structural and functional support for structures and components within the

scope of license renewal

In LRA Table 2.4.5.2, the applicant identified the following CAD storage tanks’ foundations

component types that are within the scope of license renewal and subject to an AMR:

 • equipment supports and foundations.

2.4.5.2.2 Staff Evaluation

The staff reviewed LRA Section 2.4.5.2 and UFSAR Section 5.2.6 using the evaluation

methodology described in SER Section 2.4. The staff conducted its review in accordance with

the guidance described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant 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 2.4.5.2 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. 

In RAI 2.4-7, dated December 20, 2004, the staff stated that in LRA Section 2.4.5.2, the

applicant discussed the screening results of the CAD storage tank’s foundations. Therefore, for

items included in LRA Table 2.4.5.2, the staff requested the applicant to identify other items that

require an AMR, such as structural steel embedments, carbon steel boltings, reinforced

concrete slabs and foundation footings, and grouted concrete. 

In its response, by letter dated January 24, 2005, the applicant stated:

The reinforced concrete foundation slab for the Containment Atmosphere Dilution (CAD)

Storage Tank’s Foundation is included as part of the “Equipment Supports and

Foundation” component type in Table 2.4.5.2. CAD Storage Tank’s Foundation is a

reinforced concrete foundation slab on grade that provides structural support for the

tank of the CAD system. 
2-194

The following components are also located on the CAD storage tank foundation and are

evaluated as part of the structures and component supports commodity group in LRA

Section 2.4.8: 

 • Electrical Panels, Racks, Cabinets, and Other Enclosures 

 • Conduits and Supports 

 • Non-ASME Equivalent Supports and Components 

 • Instrument Racks, Frames, Panels, & Enclosures 

The applicant noted that for in-scope components evaluated in LRA Section 2.4.8, the

components also include support structural members, welds, bolting, anchorage and building

concrete at anchorage (including base plate and grout) to the structure. 

The staff found that the response adequately clarified LRA Section 2.4.5.2. Therefore, the

staff’s concern described in RAI 2.4-7 is resolved.

2.4.5.2.3 Conclusion

The staff reviewed the LRA, related structural components, and RAI response described above

to determine whether any SSCs that should be within the scope of license renewal had not

been 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 had not been

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 had adequately identified the

CAD storage tanks’ foundations components that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and the CAD storage tanks’ foundations components that are

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

2.4.6 Class 1 Group 9 Structures

2.4.6.1 Reinforced Concrete Chimney

2.4.6.1.1 Summary of Technical Information in the Application

In LRA Section 2.4.6.1, the applicant described the reinforced concrete chimney structure,

which is a Class 1 structure that serves all three units. The chimney is 600 feet in elevation and

provides an elevated release point for radioactive gases. These radioactive gases are released

from the gaseous radwaste processing systems during normal plant operations. They are also

released from the SGT system during secondary containment isolation and during primary

containment venting. The hardened wetwell vent systems also release gaseous radwaste,

following design-basis accidents. The system is designed so that Class 1 structures (with the

exception of the off-gas treatment building) will not be damaged during DBEs.

The reinforced concrete chimney contains SR components that are relied upon to remain

functional during and following DBEs. The failure of NSR SSCs in the reinforced concrete

chimney could prevent the satisfactory accomplishment of an SR function. 
2-195

The intended functions within the scope of license renewal include the following:

 • provides structural support and shelter/protection for SR and NSR components

 • shelters and protects a component from the effects of weather or localized

environmental conditions

 • provides structural and functional support for structures and components within the

scope of license renewal

 • provides structural and functional support, for in-scope structures and components, by

an NSR component

In LRA Table 2.4.6.1, the applicant identified the following reinforced concrete chimney

component types that are within the scope of license renewal and subject to an AMR: 

 • hatches and plugs

 • metal roofing

 • electrical and I&C penetrations

 • mechanical penetrations

 • reinforced concrete beams, columns, walls, and slabs

 • roofing membrane

 • structural steel beams, columns, plates, and trusses

2.4.6.1.2 Staff Evaluation

The staff reviewed LRA Section 2.4.6.1 and UFSAR Section 12.2.4 using the evaluation

methodology described in SER Section 2.4. The staff conducted its review in accordance with

the guidance described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant 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).

2.4.6.1.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether any SSCs

that should be within the scope of license renewal had not been 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 had not been 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 had adequately identified the reinforced concrete

chimney components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the reinforced concrete chimney components that are subject to an AMR,

as required by 10 CFR 54.21(a)(1). 
2-196

2.4.7 Non-Class 1 Structures

In LRA Section 2.4.7, the applicant identified the structures and components of the non-Class 1

structures that are subject to an AMR for license renewal.

The applicant described the supporting structures and components of the non-Class 1

structures in the following sections of the LRA:

 • 2.4.7.1 Turbine Buildings

 • 2.4.7.2 Diesel High Pressure Fire Pump House

 • 2.4.7.3 Vent Vault

 • 2.4.7.4 Transformer Yard

 • 2.4.7.5 161 kV Switchyard

 • 2.4.7.6 500 kV Switchyard

 • 2.4.7.7 Isolation Valve Pits (added LRA Section)

 • 2.4.7.8 Radwaste Building (added LRA Section)

 • 2.4.7.9 Service Building (added LRA Section)

The corresponding subsections of the SER, 2.4.7.1 – 2.4.7.6, present the staff’s review findings

with respect to the non-Class 1 structures for BFN.

2.4.7.1 Turbine Buildings

2.4.7.1.1 Summary of Technical Information in the Application

In LRA Section 2.4.7.1, the applicant described the turbine buildings. The turbine buildings are

a common Class II structure that consist of a reinforced concrete structure with a steel

superstructure. The buildings are compartmentalized; the primary consideration for the design

of the walls within the buildings is for radiation shielding. The turbine buildings provide structural

support and shelter/protection for components required for safe shutdown following the SBO

and fire protection regulated events. The buildings also provide support and shelter/protection

for the outboard main steam isolation valves leakage pathway to condenser.

The failure of NSR SSCs in the turbine buildings could prevent the satisfactory accomplishment

of an SR function. The turbine buildings also perform functions that support fire protection and

SBO.

The intended functions within the scope of license renewal include the following:

 • provides structural support and shelter/protection for the outboard main steam isolation

valves leakage pathway to condenser

 • not adversely impact other Class I structures as a result of a DBE

 • provides structural support and shelter/protection for components relied upon to

demonstrate compliance with the SBO and fire protection regulated events

 • shelters and protects a component from the effects of weather or localized

environmental conditions
2-197

 • provides structural and functional support, for in-scope structures and components, by

an NSR component

In LRA Table 2.4.7.1, the applicant identified the following turbine buildings component types

that are within the scope of license renewal and subject to an AMR: 

 • hatches/plugs

 • metal roofing

 • masonry block (within scope for Unit 2 only)

 • electrical and I&C penetrations

 • mechanical penetrations

 • piles

 • reinforced concrete beams, columns, walls, and slabs

 • roof membrane

 • structural steel beams, columns, plates and trusses

2.4.7.1.2 Staff Evaluation

The staff reviewed LRA Section 2.4.7.1 and UFSAR Section 12.2.3 using the evaluation

methodology described in SER Section 2.4. The staff conducted its review in accordance with

the guidance described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant 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 2.4.7.1 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. 

In RAI 2.4 -11(a), the applicant was requested to provide additional information regarding the

turbine buildings. The staff also requested the applicant to explain the basis for stating that

masonry block utilized for Units 1 and 3 is not in scope for the period of extended operation.

The staff further requested the applicant to identify items that require an AMR, such as

structural steel embedments, carbon steel boltings, grouted concrete, metal sidings, and

waterproofing membrane materials.

In a letter dated January 24, 2005, the applicant responded as follows:

The masonry wall in the unit 2 Turbine Building provides a structural NSR support

intended function for cable tray supports for cables required to support the off-site AC

recovery for SBO requirements. The SBO cables are routed through the unit 2 Turbine

Building in a cable gallery with walls constructed of masonry block, to the north end of

the unit 2 Turbine Building, and then to a concrete tunnel buried in the yard north of the

Turbine Building. The concrete tunnel provides access to the 161 kV and 500kV
2-198

Switchyards. Only the unit 2 Turbine Building masonry walls are in scope due to the

unique cable gallery to tunnel routing of the cables required to support the off-site AC

recovery for SBO requirements for all units. This unique cable gallery does not exist in

the unit 1 or 3 Turbine Buildings. 

The following components are also located in the BFN Turbine Buildings and are

evaluated as Structures and Component Supports commodities in LRA section 2.4.8:

 • ASME Equivalent Supports and Components 

 • Cable Trays and Supports

 • Conduit and Supports 

 • Electrical Panels, Racks, Cabinets, and Other Enclosures 

 • Equipment Supports and Foundations 

 • Instrument Racks, Frames, Panels, & Enclosures 

 • Non-ASME Equivalent Supports and Components 

 • Stairs, Platforms, Grating Supports 

The applicant noted that for in-scope components evaluated in LRA Section 2.4.8, the

components also include support structural members, welds, bolting, anchorage and building

concrete at anchorage (including base plate and grout) to the structure. Waterproofing

membranes are not relied upon to support the intended functions of the structural components

of BFN structures. 

The staff found that the applicant had adequately responded to RAI 2.4 -11(a) related to the

turbine buildings structures. Therefore, the concern described in RAI 2.4-11(a) is resolved.

2.4.7.1.3 Conclusion

The staff reviewed the LRA, related structural components, and RAI response described above

to determine whether any SSCs that should be within the scope of license renewal had not

been 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 had not been

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 had adequately identified the

turbine buildings components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the turbine buildings components that are subject to an AMR, as required

by 10 CFR 54.21(a)(1). 

2.4.7.2 Diesel High Pressure Fire Pump House

2.4.7.2.1 Summary of Technical Information in the Application

In LRA Section 2.4.7.2, the applicant described the diesel high pressure fire pump house. The

diesel high pressure fire pump house is a shared structure for BFN. The pump house provides

structural support and shelter/protection for the diesel high pressure fire pump.
2-199

The entire diesel high pressure fire pump house contains components that are subject to an

AMR. The diesel high pressure fire pump house performs functions that support fire protection. 

The intended functions within the scope of license renewal include the following:

 • provides structural support and shelter/protection for components relied upon to

demonstrate compliance with the fire protection regulated event

 • prevents debris from entering a system or component

 • shelters and protects a component from the effects of weather or localized

environmental conditions

 • provides structural and functional support, for in-scope structures and components, by

an NSR component

In LRA Table 2.4.7.2, the applicant identified the following diesel high pressure fire pump house

component types that are within the scope of license renewal and subject to an AMR: 

 • metal roofing

 • metal siding

 • electrical and I&C penetrations

 • mechanical penetrations

 • piles

 • reinforced concrete beams, columns, walls, and slabs

 • roof membrane

 • structural steel beams, columns, plates, and trusses

2.4.7.2.2 Staff Evaluation

The staff reviewed LRA Section 2.4.7.2 using the evaluation methodology described in SER

Section 2.4. The staff conducted its review in accordance with the guidance described in

SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not

omitted from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). The staff then reviewed those components that the applicant 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 2.4.7.2 identified 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. 

In RAI 2.4 -11(b), dated December 20, 2004, the staff requested the applicant to identify items

that require an AMR, such as structural steel embedments, carbon steel boltings, grouted

concrete, and waterproofing membrane materials. 
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In its response, by letter dated January 24, 2005, the applicant stated:

The following components are also located in the diesel high pressure fire pump house

and are evaluated as structures and component supports commodities in LRA section

2.4.8:

 • Conduit and Supports 

 • Electrical Panels, Racks, Cabinets, and Other Enclosures 

 • Equipment Supports and Foundations 

 • Non-ASME Equivalent Supports and Components

The applicant noted that for in-scope components evaluated in LRA Section 2.4.8, the

components also include support structural members, welds, bolting, anchorage and building

concrete at anchorage (including base plate and grout) to the structure. Waterproofing

membranes are not relied upon to support the intended functions of the structural components

of BFN structures.

The staff found that the applicant had adequately responded to RAI 2.4 -11(b) related to the

diesel high pressure fire pressure fire pump house structure. Therefore, the staff’s concern

described in RAI 2.4-11(b) is resolved.

2.4.7.2.3 Conclusion

The staff reviewed the LRA, related structural components, and RAI response described above

to determine whether any SSCs that should be within the scope of license renewal had not

been 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 had not been

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 had adequately identified the

diesel high pressure fire pump house components that are within the scope of license renewal,

as required by 10 CFR 54.4(a), and the diesel high pressure fire pump house components that

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

2.4.7.3 Vent Vaults

2.4.7.3.1 Summary of Technical Information in the Application

In LRA Section 2.4.7.3, the applicant described the vent vaults. A vent vault is provided for each

unit. Each vent vault is a concrete structure with an open top. The base foundation for each

vent vault is founded on compacted backfill that is located within the earth berm and adjacent to

the respective reactor building. The vent vaults contain components required for the reactor

building ventilation system supply, including the secondary containment isolation dampers.

The portions of the vent vaults containing components subject to an AMR include the east and

west walls and the floor slab. The failure of NSR systems, SSCs in the vent vaults could

prevent the satisfactory accomplishment of an SR function. 
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The intended function within the scope of license renewal is to provide structural and functional

support for in-scope structures and components by an NSR component.

In LRA Table 2.4.7.3, the applicant identified the following vent vaults component types that are

within the scope of license renewal and subject to an AMR: 

 • reinforced concrete beams, columns, walls, and slabs

2.4.7.3.2 Staff Evaluation

The staff reviewed LRA Section 2.4.7.3 using the evaluation methodology described in SER

Section 2.4. The staff conducted its review in accordance with the guidance described in

SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA in accordance with the requirements of 10 CFR 54.4(a) to verify that the applicant had not

omitted from the scope of license renewal any components with intended functions delineated

under 10 CFR 54.4(a). The staff then reviewed those components that the applicant 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 2.4.7.3 identified 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. 

In RAI 2.4-9(a), dated December 20, 2004, the staff stated that LRA Section 2.4.3 lists several

structures that are not shown in drawing 0-10E201-01-LR. Therefore, the staff requested the

applicant to clarify the reason why the three vent vaults shown in drawing 0-10E201-01-LR do

not indicate the specific systems or components contained or sheltered within them.

Additionally, the applicant was requested to identify items that require an AMR, such as

structural steel embedments, carbon steel boltings, grouted concrete, and waterproofing

membrane materials.

In its response, by letter dated January 24, 2005, the applicant stated:

The three vent vaults are open-top concrete structures located within the earth berm

adjacent to their associated reactor building. The vent vaults contain components

required for the reactor building ventilation system supply, including the secondary

containment isolation dampers. Other than the “Reinforced Concrete Beams, Columns,

Walls and Slabs” noted on LRA Table 2.4.7.3, they contain no components that require

an aging management review.

The staff found that the applicant had adequately responded to RAI 2.4-9(a) on the vent vaults

structure. Therefore, the staff’s concern described in RAI 2.4-9(a) is resolved. 
2-202

2.4.7.3.3 Conclusion

The staff reviewed the LRA, related structural components, and RAI response described above

to determine whether any SSCs that should be within the scope of license renewal had not

been 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 had not been

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 had adequately identified the

vent vaults components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the vent vaults components that are subject to an AMR, as required by

10 CFR 54.21(a)(1). 

2.4.7.4 Transformer Yard

2.4.7.4.1 Summary of Technical Information in the Application

In LRA Section 2.4.7.4, the applicant described the transformer yard. The transformer yard is a

shared feature for all three units. The transformer yard supports components required for power

restoration following the SBO regulated event.

The transformer yard performs functions that support SBO.

The intended functions within the scope of license renewal include the following:

 • provides structural support for components relied upon to demonstrate compliance with

the SBO regulated event

 • provides structural and functional support, for in-scope structures and components, by

an NSR component

In LRA Table 2.4.7.4, the applicant identified the following transformer yard component types

that are within the scope of license renewal and subject to an AMR: 

 • piles

 • structural steel beams

 • structural columns

 • structural plates

 • structural trusses

2.4.7.4.2 Staff Evaluation

The staff reviewed LRA Section 2.4.7.4 and UFSAR Sections 8.2, 8.4 and 8.10 using the

evaluation methodology described in SER Section 2.4. The staff conducted its review

in accordance with the guidance described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the
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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 2.4.7.4 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. 

In RAI 2.4 -11(d), dated December 20, 2004, the staff requested the applicant, with respect to

the transformer yard, to identify, items such as structural steel embedments, carbon steel plates

and boltings, reinforced concrete pads and footings, grouted concrete, and waterproofing

membrane materials that require an AMR.

In its response by letter, dated January 24, 2005, the applicant stated:

The following components are also located in the BFN Transformer Yard, and are

evaluated as Structures and Component Supports commodities in LRA section 2.4.8:

 • Equipment Supports and Foundations 

The applicant noted that for in-scope components evaluated in LRA Section 2.4.8, the

components also include support structural members, welds, bolting, anchorage and building

concrete at anchorage (including base plate and grout) to the structure. Waterproofing

membranes are not relied upon to support the intended functions of the structural components

of BFN structures. 

The staff found that the applicant had adequately responded to RAI 2.4-11(d) related to the

transformer yard structure. Therefore, the staff’s concern described in RAI 2.4-11(d) is

resolved.

2.4.7.4.3 Conclusion

The staff reviewed the LRA, related structural components, and RAI response described above

to determine whether any SSCs that should be within the scope of license renewal had not

been 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 had not been

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 had adequately identified the

transformer yard components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the transformer yard components that are subject to an AMR, as required

by 10 CFR 54.21(a)(1). 

2.4.7.5 161 kV Switchyard

2.4.7.5.1 Summary of Technical Information in the Application

In LRA Section 2.4.7.5, the applicant described the 161 kV switchyard, which is a shared

feature for all three units. The switchyard routes power from offsite transmission lines into BFN
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for onsite use. The 161 kV switchyard supports components required for power restoration

following the SBO regulated event.

The 161 kV switchyard performs functions that support SBO.

The intended functions within the scope of license renewal include the following:

 • provides structural support and shelter/protection for components that are relied upon to

demonstrate compliance with the SBO regulated event

 • shelters and protects a component from the effects of weather or localized

environmental conditions

 • provides structural and functional support, for in-scope structures and components, by

an NSR component

In LRA Table 2.4.7.5, the applicant identified the following 161 kV switchyard component types

that are within the scope of license renewal and subject to an AMR: 

 • structural steel beams

 • structural columns

 • structural plates

 • structural trusses

 • tunnels

2.4.7.5.2 Staff Evaluation

The staff reviewed LRA Section 2.4.7.5 and UFSAR Sections 1.5,1.6, 8.1, 8.3, 8.4, and 8.10

using the evaluation methodology described in SER Section 2.4. The staff conducted its review

in accordance with the guidance described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant 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 2.4.7.5 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. 

In RAI 2.4 -11(d)(2), dated December 20, 2004, the staff requested the applicant to identify

items that require an AMR, such as structural steel embedments, carbon steel plates and

boltings, reinforced concrete pads and footings, grouted concrete, and waterproofing

membrane materials.
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In its response, by letter January 24, 2005, the applicant stated:

The following components are also located in the BFN 161 kV Switchyard and are

evaluated as Structures and Component Supports commodities in LRA section 2.4.8:

 • Equipment Supports and Foundations 

 • Cable Trays and Supports

 • Conduit and Supports

 • Electrical Panels, Racks, Cabinets, and Other Enclosures

The applicant noted that for in-scope components evaluated in LRA Section 2.4.8, the

components also include support structural members, welds, bolting, anchorage and building

concrete at anchorage (including base plate and grout) to the structure. Waterproofing

membranes are not relied upon to support the intended functions of the structural components

of BFN structures. 

The staff found that the applicant had adequately responded to RAI 2.4-11(d) related to the 161

kV switchyard structure. Therefore, the staff’s concern described in RAI 2.4-11(d) is resolved.

2.4.7.5.3 Conclusion

The staff reviewed the LRA, related structural components, and RAI response described above

to determine whether any SSCs that should be within the scope of license renewal had not

been 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 had not been

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 had adequately identified the

161 kV switchyard components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the 161 kV switchyard components that are subject to an AMR, as

required by 10 CFR 54.21(a)(1). 

2.4.7.6 500 kV Switchyard

2.4.7.6.1 Summary of Technical Information in the Application

In LRA Section 2.4.7.6, the applicant described the 500 kV switchyard. The 500 kV switchyard

is a shared feature for all three units. The switchyard routes power to offsite transmission lines

and can be used to route power into BFN for onsite use. The 500 kV switchyard supports

components required for power restoration following an SBO regulated event.

The 500 kV switchyard performs functions that support SBO.

The intended functions within the scope of license renewal include the following:

 • provides structural support and shelter/protection for components that are relied upon to

demonstrate compliance with the SBO regulated event

 • shelters and protects a component from the effects of weather or localized

environmental conditions
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 • provides structural and functional support, for in-scope structures and components, by

an NSR component

In LRA Table 2.4.7.6, the applicant identified the following 500 kV switchyard component types

that are within the scope of license renewal and subject to an AMR: 

 • structural steel beams

 • structural columns

 • structural plates

 • structural trusses

 • tunnels

2.4.7.6.2 Staff Evaluation

The staff reviewed LRA Section 2.4.7.6 and UFSAR Sections 1.5, 1.6, 8.1, 8.3, 8.4, and 8.10

using the evaluation methodology described in SER Section 2.4. The staff conducted its review

in accordance with the guidance described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant 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 2.7.4.6 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. 

In RAI 2.4-11(d)(3), dated December 20, 2004, the staff requested the applicant to identify

items that require an AMR, such as structural steel embedments, carbon steel plates and

boltings, reinforced concrete pads and footings, grouted concrete, and waterproofing

membrane materials.

In its response, by letter, dated January 24, 2005, the applicant stated:

The following components are also located in the BFN 500 kV Switchyard and are

evaluated as Structures and Component Supports commodities in LRA section 2.4.8:

 • Equipment Supports and Foundations 

 • Cable Trays and Supports

 • Conduit and Supports

 • Electrical Panels, Racks, Cabinets, and Other Enclosures

The applicant noted that for in-scope components evaluated in LRA Section 2.4.8, the

components also include support structural members, welds, bolting, anchorage and building

concrete at anchorage (including base plate and grout) to the structure. Waterproofing
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membranes are not relied upon to support the intended functions of the structural components

of BFN structures.

The staff found that the applicant had adequately responded to RAI 2.4-11(d) related to the 500

kV switchyard structure. Therefore, the staff’s concern described in RAI 2.4-11(d) is resolved.

2.4.7.6.3 Conclusion

The staff reviewed the LRA, related structural components, and RAI response described above

to determine whether any SSCs that should be within the scope of license renewal had not

been 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 had not been

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 had adequately identified the

500 kV switchyard components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the 500 kV switchyard components that are subject to an AMR, as

required by 10 CFR 54.21(a)(1). 

Section 2.4.7.7. In earlier RAI 2.4-1 response, dated January 24, 2005, the applicant stated

that isolation valve pits are Class II NSR structures that provide structural support and shelter

protection for the hardened wetwell vent piping and components. Since these isolation valve

pits provide an intended function for an in scope mechanical system, therefore, are included

within the scope of license renewal. In Attachment 1 to its letter, the applicant added LRA

Section 2.4.7.7, as discussed below.

2.4.7.7 Isolation Valve Pits

2.4.7.7.1 Summary of Technical Information in the Application

In added LRA Section 2.4.7.7, the applicant described the isolation valve pits, stating that there

is an isolation valve pit for each unit.

The failure of NSR SSCs in the isolation valve pits could potentially prevent the satisfactory

accomplishment of an SR function. 

The intended functions within the scope of license renewal include the following:

 • shelters and protects a component from the effects of weather or localized

environmental conditions

 • provides structural and functional support, for in-scope structures and components, by

an NSR component

In added LRA Table 2.4.7.7, the applicant identified the following isolation valve pits component

types that are within the scope of license renewal and subject to an AMR:

 • caulking & sealants

 • penetrations electrical and I&C

 • penetrations mechanical
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 • reinforced concrete beams, columns, walls, and slabs

 • structural steel beams, columns, plates, and trusses

2.4.7.7.2 Staff Evaluation

The staff reviewed added LRA Section 2.4.7.7 using the evaluation methodology described in

SER Section 2.4. The staff conducted its review in accordance with the guidance described in

SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

added section of the LRA in accordance with the requirements of 10 CFR 54.4(a) to verify that

the applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant 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).

2.4.7.7.3 Conclusion

The staff reviewed the added LRA Section 2.4.7.7 and related structural/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 had adequately identified the

isolation valve pits components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and that the applicant had adequately identified the isolation valve pits

components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

Sections 2.4.7.8 and 2.4.7.9. The staff, in an earlier RAI 2.1-2A(3) dated September 3, 2004,

requested additional information related to seismic Class I piping boundaries for identifying

additional piping segments and supports/equivalent anchors that need to be placed in the

scope of license renewal to satisfy the 10 CFR 54.4(a)(2) criterion. The staff had asked whether

if this review brought into scope any new buildings not in the original application. By response

dated February 28, 2005, the applicant identified two additional buildings brought into the LRA

scope and the added LRA sections are as follows.

2.4.7.8 Radwaste Building

2.4.7.8.1 Summary of Technical Information in the Application

In LRA Section 2.4.7.8, the applicant identified the structures and components of the radwaste

building that are subject to an AMR for license renewal.

The radwaste building is a cellular box-type concrete structure extending approximately 20 feet

below grade and 30 feet above grade and supported by steel H-piles driven to bedrock. This

building houses services common to all three units. The radwaste building is comprised

predominantly of thick walls and slabs, the dimensions of which are determined by shielding
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requirements. In a few instances, walls and slabs are determined by structural requirements.

The roof system is a steel-framed structure with either bracket supports on concrete walls or

steel columns supported by the concrete floor at an elevation of 580.0 feet.

In LRA Table 2.4.7.8, the applicant identified the following radwaste building component types

that are within the scope of license renewal and subject to an AMR:

 • masonry block

 • metal roofing

 • piles

 • reinforced concrete beams, columns, walls, and slabs

 • roof membrane

 • structural steel beams, columns, plates, and trusses

2.4.7.8.2 Staff Evaluation

The staff reviewed LRA Section 2.4.7.8 and UFSAR Section 12.2.5 using the evaluation

methodology described in SER Section 2.4. The staff conducted its review in accordance with

the guidance described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant 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 2.4.7.8 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. 

In RAI 2.4-15, dated March 25, 2005, the staff stated that LRA Section 2.4.7.8 states that “The

portions of the radwaste building that contain components requiring an AMR include the entire

structure and the component supports discussed above.” Therefore, the staff requested the

applicant to confirm that all structural elements of the radwaste building are scoped and

screened in Table 2.4.7.8. If not, the applicant was requested to list those elements of the

radwaste building that are excluded from the table and discuss the basis for their exclusion

including BFN’s assessment of the II/I implication of the excluded elements upon their adjacent

in-scope elements pursuant to 10 CFR 54.4 (a)(2).

In its response, by letter dated April 14, 2005, the applicant stated that all structural elements of

the radwaste building are scoped and screened in LRA Table 2.4.7.8.

The staff found the above response to RAI 2.4-15 acceptable. Therefore, the staff’s concern

described in RAI 2.4-15 is resolved.
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2.4.7.8.3 Conclusion

The staff reviewed the LRA, related structural components, and RAI response described above

to determine whether any SSCs that should be within the scope of license renewal had not

been 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 had not been

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 had adequately identified the

radwaste building components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the radwaste building components that are subject to an AMR, as required

by 10 CFR 54.21(a)(1). 

2.4.7.9 Service Building

2.4.7.9.1 Summary of Technical Information in the Application

In LRA Section 2.4.7.9, the applicant identified the structures and components of the service

building that are subject to an AMR for license renewal.

This structure consists of exterior concrete walls and footings with an interior structural steel

frame supported by concrete footings and floor slabs. The building provides office and shop

areas for various onsite organizations.

In LRA Table 2.4.7.9, the applicant identified the following service building component types

that are within the scope of license renewal and subject to an AMR:

 • masonry block

 • metal roofing

 • reinforced concrete beams, columns, walls, and slabs

 • roof membrane

 • structural steel beams, columns, plates, and trusses

2.4.7.9.2 Staff Evaluation

The staff reviewed LRA Section 2.4.7.9 and UFSAR Section 12.2.6.2 using the evaluation

methodology described in SER Section 2.4. The staff conducted its review in accordance with

the guidance described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant 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 2.4.7.9 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. 

In RAI 2.4-16, dated March 25, 2005, the staff stated that LRA Section 2.4.7.9 seems to

indicate that only a portion of the service building is scoped and screened in LRA Table 2.4.7.9.

Since the LRA provides only a general description of the boundaries between the in-scope and

out-of-scope structural elements of the service building, the staff requested the applicant to list

those elements of the service building that are excluded from the table and discuss the basis

for their exclusion including BFN’s assessment of the II/I implication of the excluded elements

upon their adjacent in-scope elements pursuant to 10 CFR 54.4 (a)(2). 

In its response, by letter dated April 14, 2005, the applicant stated:

During the scoping and screening of the Service Building for the newly identified

mechanical systems discussed in the response to RAI 2.1-2A(3), only a limited area of

the Service Building contained the new in-scope mechanical piping. Based on that fact,

it was determined that the entire structure did not need to be within the scope of license

renewal for the period of extended operation and this is described in the second

paragraph of the response as noted on page E3-9 and reads as following; “The Service

Building contains CO2 piping and a liquid (water) filled piping for the fire protection

system that are required to support fire protection requirements (10 CFR 50.48) based

on the criterion of 10 CFR 54.4 (a)(3). Only those rooms of the Service Building that

contain the fire protection piping are required to provide structural support and

shelter/protection to support the intended function of the fire protection piping.”

In order to maintain the structural integrity of the structure within the scope of license

renewal and provide reasonable assurance that these piping systems will be able to

perform their intended functions, a portion of the structure was required to be in-scope

such that the structure will perform its intended functions of “shelter/protection” and

“structural support“ of 10 CFR 54.4(a)(3) components. The in-scope boundary of the

Service Building is described in the second paragraph on page E3-10 and reads as

following; “In order to maintain the structural integrity of the Service Building to provide

its intended functions for the in-scope components, the building area considered

in-scope for the structure will be extended two column line bays in the west direction to

column line S4 and will include the entire structure in the north-south direction between

the personnel corridors on elevations 565.0’ and 580.0’ and roof at elevation 595.0’

south of column line Sa to the north exterior wall of the Service Building. It should be

noted that column line S7 is the east exterior wall of the Service Building and is located

adjacent and parallel to the west exterior wall of the Unit 1 turbine building. Additionally,

from the foundation slab at El 565.0’ (top of floor slab EL 565.0’) to the general roof

deck of the structure at EL 595.0’ and to EL 605.0’ above the mechanical equipment

room located between column lines S5 and S6 (west to east) and the Pull-Out Space &

Shop Storage between column lines S6 and S7 (west to east) and between column lines

Sb to approximately 6 ft north of column line Sh (south to north) defines the in-scope

height of the structure.” The basis for concluding that the structural integrity boundary of

the in-scope structure will be maintained is based on a review of the design of the

Service Building.
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The structural elements of the Service Building that are listed in Table 2.4.7.9

encompass all the structural elements of the Service Building and none were excluded. 

The staff found the above response to RAI 2.4-16 acceptable. Therefore, the staff’s concern

described in RAI 2.4-16 is resolved.

2.4.7.9.3 Conclusion

The staff reviewed the LRA, related structural components, and RAI response described above

to determine whether any SSCs that should be within the scope of license renewal had not

been 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 had not been

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 had adequately identified the

service building components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the service building components that are subject to an AMR, as required

by 10 CFR 54.21(a)(1). 

2.4.8 Structures and Component Supports Commodities

2.4.8.1 Structures and Component Supports Commodity Group

2.4.8.1.1 Summary of Technical Information in the Application

In LRA Section 2.4.8.1, the applicant described the structures and component supports

commodity group. This group includes specific types of structures and component support

elements located in structures that are within the scope of license renewal. Physical interfaces

exist with the structure, system or component being supported and with the building structural

element to which the support is anchored. The supports located within a structure that are

included within the scope of license renewal are identified under the individual structure’s

description. The in-scope items include support members, welds, bolted connections,

anchorage (including base plate and grout) to the building structure, spring hangers, guides,

and building concrete at bolt locations.

The component supports commodity group includes the following sub-groups: (1) supports for

ASME piping and components (GALL Report Items III.B1); (2) supports for cable trays, conduit,

HVAC ducts, tube track, instrument tubing and non-ASME piping and components (GALL

Report Items III.B2); (3) anchorage of racks, panels, cabinets, and enclosures for electrical

equipment and instrumentation (GALL Report Items III.B3); (4) supports for emergency diesel

generator (EDG), HVAC system components, and miscellaneous mechanical equipment (GALL

Report Items III.B4); and (5) supports for platforms, pipe whip restraints, jet impingement

shields, masonry walls, and other miscellaneous structures (GALL Report Items III.B5). The

first sub-group includes the supports and support anchorage for ASME-equivalent code class

piping and components, or for the components that comprise the interface between the

structure and the mechanical component. The second sub-group includes the supports and

support anchorage for cable trays, conduits, HVAC ducts, tube track, instrument tubing, and

non-ASME piping and components that comprise the interface between the structure and the

mechanical, electrical, or instrument component. The third sub-group includes the supports and
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support anchorage for enclosures of various types that contain and support electrical

equipment. Components evaluated in this group comprise the interface between the structure

and the electrical or instrument component. The fourth sub-group includes the supports and

support anchorage for equipment not addressed in the previous groups that comprise the

boundary between the structure and the component. Finally, the fifth sub-group includes

structures and anchorage for miscellaneous structures as described above that indirectly

support operation. These components comprise the evaluated structure and its anchorage. 

A primary function of a support is to provide anchorage for the supported element for DBEs so

that the supported element can perform its intended function or functions. 

In LRA Table 2.4.8.1, the applicant identified the following structures and component supports

commodity group items that are within the scope of license renewal and subject to an AMR: 

 • ASME-equivalent supports and components

 • bolting and fasteners

 • cable trays and supports

 • conduit and supports

 • duct banks and manholes

 • electrical panels, racks, cabinets, and other enclosures

 • equipment supports and foundations

 • HVAC duct supports

 • instrument line supports

 • instrument racks, frames, panels, and enclosures

 • non-ASME equivalent supports and components

 • pipe whip restraints and jet impingement shields

 • reinforced concrete beams, columns, walls, and slabs

 • stairs, platforms, and grating supports

 • trenches

 • tube rack

 • tunnels

2.4.8.1.2 Staff Evaluation

The staff reviewed LRA Section 2.4.8.1, UFSAR Section 5.2 and Appendix C using the

evaluation methodology described in SER Section 2.4. The staff conducted its review

in accordance with the guidance described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and UFSAR in accordance with the requirements of 10 CFR 54.4(a) to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant 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 2.4.8.1 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. 
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In RAI 2.4-13, dated December 20, 2004, the staff stated that the information provided in LRA

Section 2.4.8.1 did not make it clear to the staff that all component supports within the scope of

license renewal are included in the component supports commodity group. Therefore, the staff

requested clarification for several components listed in LRA Table 2.4.8.1. The staff requested

the applicant to provide the following:

 a. Clarify whether the ASME equivalent supports and components listed in Table 2.4.8.1

include the reactor vessel support skirt/support ring and reactor vessel upper lateral

stabilizer support. If not, the applicant was requested (1) to explain where these

supports were addressed in the LRA, and (2) to submit the technical basis for crediting

an alternate AMP for these supports, if they are not managed by ASME Section XI,

Subsection IWF. 

 b. Clarify whether the ASME Equivalent Supports and Components of LRA Table 2.4.8.1

include the drywell lower ring support and the drywell upper lateral support. If the drywell

supports are not managed by ASME Section XI, Subsection IWF, the applicant was

requested to submit the AMR for them, including the technical basis for this exception. 

 c. Since LRA Section 2.4.8.1 is not referenced anywhere in LRA Sections 2.3 or 2.4, the

applicant was requested to verify that all supports associated with components listed in

LRA Sections 2.3 and 2.4.1 through 2.4.7 are included in the component types listed in

LRA Table 2.4.8.1. If not, the applicant was requested to identify the supports not

included and submit the AMR, including credited AMPs. 

 d. Confirm that the "Bolting and Fasteners" listed in LRA Table 2.4.8.1 includes anchors

directly installed into concrete. 

In its response, by letter dated January 24, 2005, the applicant stated:

 a. The reactor vessel support skirt, reactor vessel support ring girder and reactor

vessel upper lateral stabilizer are included with “ASME Equivalent Supports and

Components” component group as listed in LRA Table 2.4.8.1. See response to

RAI 2.4-2 (f), RAI 2.4-2 (g) and 2.4-2 (a) for AMR results for these components

respectfully. 

 b. The ASME Equivalent Supports and Components of Table 2.4.8.1 do not include

the drywell lower ring support and the drywell upper lateral support. Steel

Containment Elements in Table 2.4.1.1 include the drywell lower ring support

(drywell support skirt) and the drywell upper lateral supports. These components

are classified as part of Class MC and BFN is not required to inspect MC

supports in accordance with ASME Section XI. Refer to NRC RAIs B.2.1.33-1

and B.2.1.33-2 and TVA’s responses to those RAIs for justification of why they

are not inspected to ASME Section XI, Subsection IWF. The drywell lower ring

support is inaccessible (embedded in the Reactor Building concrete). 

 c. LRA Section 2.4.8, “Structures and Component Supports Commodities,” includes

all supports associated with the components listed in LRA Sections 2.3 and 2.4.1

through 2.4.7, with one exception: 

(1) LRA Table 2.3.1.2 of Section 2.3.1.2 identifies various components

internal to the reactor vessel that provide support for other internal
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components. Aging management of reactor vessel internals components

is presented in LRA Table 3.1.2.2. 

 d. In LRA Table 2.4.8.1, the component group “Bolting and Fasteners” was

included in error and should be deleted from the table. LRA Table 2.4.8.1 should

read as shown below: 

LRA Table 2.4.8.1 - Structures and Component Supports 

Component Type Intended Functions 

ASME Equivalent Supports and Components SS

Cable Trays and Supports SS, and/or SS(NSR)

Conduit and Supports SP, SS, and/or SS(NSR)

Duct Banks, Manholes SS

Electrical Panels, Racks, Cabinets, and Other Enclosures SP, SS, and/or SS(NSR)

Equipment Supports and Foundations SS, and/or SS(NSR)

HVAC Duct Supports SS, and/or SS(NSR)

Instrument Line Supports SS, and/or SS(NSR)

Instrument Racks, Frames, Panels & Enclosures SP, SS, and/or SS(NSR)

Non-ASME Equivalent Supports and Components SS, and/or SS(NSR)

Pipe Whip Restraints and Jet Impingement Shields PW and/or HE/ME

Reinforced Concrete Beams, Columns, Walls, and Slabs SS, and/or SS(NSR)

Stairs, Platforms, Grating Supports SS, and/or SS(NSR)

Trenches SS(NSR)

Tube Track SS, and/or SS(NSR)

Tunnels SS, and/or SS(NSR)

Each of the component support commodity groups identified in LRA section 2.4.8.1

includes bolting and anchors, including anchors installed into concrete. This information

has been provided in the discussion for the five Structures and Component Supports

Commodity Groups in LRA Section 2.4.8, pages 2.4-55 and 2.4-56.

Item (b) of the above response refers to the applicant’s response to RAIs B.2.1.33-1 and

B.2.1.33-2, and the applicant’s justification for why the drywell lower ring support and the

drywell upper lateral support are not inspected to ASME Section XI, Subsection IWF. The staff

evaluation covering the applicant’s response to RAIs B.2.1.33-1 and B.2.1.33-2 is provided in

SER Section 3.0.3.2.21.

The staff found that the applicant response, above, fully addressed the concerns identified in

RAI 2.4-13; therefore, the staff’s concern described in RAI 2.4-13 is resolved.

In RAI 2.4-14, dated December 20, 2004, the staff stated that based on information provided in

LRA Section 2.4, the staff could not identify the insulation and insulation jacketing included

within the scope of license renewal nor the specific subsets of insulation and insulation

jacketing that are included in LRA Section 2.4 tables. It was also unclear whether insulation and

jacketing on the reactor coolant system had been included; therefore, the staff requested the

following of the applicant: 
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 • Identify the structures and structural components designated as within the license

renewal scope that have insulation and/or insulation jacketing, and identify their location

in the plant. 

 • List all insulation and insulation jacketing materials associated with the item (a) above

that require an AMR and the results of the AMR for each. 

 • For insulation and insulation jacketing materials associated with the item (a) above that

do not require aging management, submit the technical basis for this conclusion,

including plant-specific operating experience. 

 • For insulation and insulation jacketing materials associated with the item (a) above that

require aging management, identify the AMP(s) credited to manage aging. 

In its response, by letter dated January 24, 2005, the applicant stated:

As stated in Section 2.1.7.2 of the Application, Insulation at BFN does not have an

intended function within the scope of 10 CFR 54.4(a)(3).

In its response, by letter May 18, 2005, the applicant provided follow-up information to address

the staff’s concern that insulation was not in scope and subject to an AMR, as stated below:

Thermal insulation is in scope and meets the criteria of 10 CFR 54.4(a)(2) and

10 CFR 54.4(a)(3). 

The AMR results for insulation/insulation jacketing are provided in the new

Section 3.0.2, shown in Attachment 2 to this response.

The staff found the above response to RAI 2.4-14 acceptable. Therefore, the staff’s concern

described above is resolved.

2.4.8.1.3 Conclusion

The staff reviewed the LRA, related structural components, and RAI responses described

above to determine whether any SSCs that should be within the scope of license renewal had

not been 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

had not been 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 had

adequately identified the structures and component supports commodity group components

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the structures

and component supports commodity group components that are subject to an AMR, as

required by 10 CFR 54.21(a)(1). 

2.4.9 Conclusion

On the basis of its review, the staff concluded that the applicant had adequately identified the

structures and components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the BFN structures and components that are subject to an AMR, as

required by 10 CFR 54.21(a)(1).
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2.5 Scoping and Screening Results: Electrical and Instrumentation and Controls

Systems

This section documents the staff’s review of the applicant’s scoping and screening results for

electrical and I&C systems.

In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must identify and list

passive, long-lived electrical and I&C SSCs 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 I&C system 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 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 had been 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 license renewal. The staff reviewed relevant licensing basis

documents, including the UFSAR, for each electrical and I&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) had been specified in the

LRA. If omissions were identified, the staff requested additional information to resolve the

discrepancies.

Screening. Once the staff completed its review of the scoping results, it evaluated the

applicant’s screening results. For those systems and components with intended functions, the

staff sought to determine (1) if the functions are performed with moving parts or a change in

configuration or properties, or (2) if they are subject to replacement based on a qualified life or

specified time period, as described in 10 CFR 54.21(a)(1). For those that did not meet either of

these criteria, the staff sought to confirm that these electrical and I&C systems and components

were subject to an AMR as required by 10 CFR 54.21(a)(1). If discrepancies were identified, the

staff requested additional information to resolve them.

2.5.1 Electrical and Instrumentation and Control Commodities

2.5.1.1 Summary of Technical Information in the Application

In LRA Section 2.5.1, the applicant described the electrical and I&C commodities. The electrical

and I&C commodities have intended functions to power and control components that meet the

requirements of 10 CFR 54.4. For this section, the applicant performed component-level

scoping, evaluating by commodities rather than by system components.
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The electrical and I&C commodities contain SR components that are relied on to remain

functional during, and following, design-basis events. The failure of NSR SSCs in the electrical

and I&C commodities could prevent the satisfactory accomplishment of an SR function. In

addition, the electrical and I&C commodities perform functions that support fire protection, EQ,

ATWS, and SBO.

The intended functions within the scope of license renewal include the following:

 • conducts electrical current

 • provides electrical insulation

 • provides structural support

In LRA Table 2.5.1, the applicant identified the following electrical and I&C commodities

component types that are within the scope of license renewal and subject to an AMR: 

 • bus (with enclosures), transmission conductors, and high-voltage insulators (metallic

portions)

 • bus and high-voltage insulators (non-metallic portions)

 • electrical cables and connections not subject to 10 CFR 50.49 EQ requirements

(connections include connectors, splices, terminal blocks, fuse blocks/clips, and

electrical/I&C penetration assembly pigtails and connectors)

 • various electrical equipment subject to 10 CFR 50.49 EQ requirements

2.5.1.2 Staff Evaluation

The staff reviewed LRA Section 2.5.1 using the evaluation methodology described in SER

Section 2.5. The scoping and screening of electrical and I&C components were performed

using the spaces approach described in LRA Section 2.1. The staff conducted its review in

accordance with the guidance described in SRP-LR Section 2.5, "Scoping and Screening

Results - Electrical and Instrumentation and Controls Systems."

In the performance of the review, the staff reviewed the UFSAR for any functions delineated

under 10 CFR 54.4(a) that had not been identified as intended functions in the LRA, to verify

that the SSCs with such functions will be adequately managed to maintain the functions

consistent with the CLB for the extended period of operation. The staff then reviewed the LRA

to verify that passive or long-lived components were subject to an AMR in accordance with

10 CFR 54.21(a)(1).

In LRA Section 2.5.1, the applicant said that the electrical commodities meet the requirements

of 10 CFR 54.4(a)(1), 10 CFR 54.4(a)(2), and 10 CFR 54.4(a)(3) and the related requirements

for fire protection, EQ, ATWS, and SBO. During its review, the staff identified AMRs for

components that are not explicitly addressed for Unit 1. These AMR items are those identified

in the scoping and screening evaluation corresponding to LRA Appendices F3, F4, and F7,

items shown with a bold-bordered enclosures in LRA Appendix F (see SER Sections 2.6.1.3,

2.6.1.4, and 2.6.1.7). In a letter dated October 8, 2004, the staff requested additional

information required for the AMR with respect to these Unit 1 items.
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In response to a generic RAI dated January 31, 2005, the applicant provided additional

information concerning integration of Unit 1 Restart and License Renewal Activities, which

states 

The license renewal application was structured to reflect the configuration and current

licensing basis of all three units. Scoping and screening as well as aging management

reviews were done based on the current licensing bases and configuration of all three

units. The differences between the units that are relevant to the application and will be

resolved prior to Unit 1 restart, are listed in Appendix F. As each activity identified in

Appendix F is completed, the corresponding highlighted (bolded bordered) text in the

license renewal application will apply to Unit 1. The only change to the application will be

to remove the bolded border. No changes are required to scoping and screening results,

aging management review results, or TLAAs. In some cases, boundary drawings would

change to reflect the bolded bordered text.

The staff reviewed the applicant’s response for these items and accepts the methodology as

proposed by the applicant for these bold-bordered items throughout the LRA. These

modifications are currently not physically implemented for Unit 1 to match Units 2 and 3 CLB.

However, the applicant stated in its response that the scoping and screening as well as the

AMRs are done forward-looking for these bold-bordered enclosure items, based on the CLB for

Units 2 and 3, which will also apply to Unit 1 when the modifications are completed. As each

activity identified in Appendix F is completed, the corresponding bold-bordered text in the LRA

will apply to Unit 1. The applicant commits to update the status of this implementation in a

future submittal and through the annual LRA update to the CLB, the next one in January 2006.

This commitment will be tracked through a temporary instruction (TI)-2509-01 as a part of the

license application verification that this commitment will be completed prior to Unit 1 restart. The

applicant also committed to inform the staff as these activities are completed and to reflect the

status in annual and other periodic updates. Based on the above, the staff finds this issue for

the electrical and I&C resolved.

In reviewing LRA Section 2.5, the staff identified areas in which additional information was

necessary to com

plete the evaluation of the applicant’s scoping and screening results. Therefore, the staff issued

RAIs concerning the specific issues to determine whether the applicant had properly applied the

scoping criteria of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1). The

following discussion describes the staff’s RAIs and the applicant’s related responses.

In RAI 2.5-1, dated November 1, 2004, the staff stated that in LRA Section 2.5-1, the applicant

stated that scoping and screening of electrical and I&C components was performed using the

spaces approach described in LRA Section 2.1. Therefore, the staff requested the applicant to

specify if all plant spaces had been evaluated using this methodology. If any spaces had been

excluded from this evaluation, the staff asked the applicant to identify the excluded spaces and

to explain why the spaces were excluded. 

In its response, by letter December 1, 2004, the applicant stated:

The “spaces” approach was used for scoping and screening of all plant spaces. The

only time the “spaces” approach was not utilized was scoping and screening of the SBO
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recovery path. The “intended function” approach was utilized to identify which specific

components were required for SBO recovery. 

The staff found this response acceptable; therefore, the staff’s concern described in RAI 2.5-1

is resolved.

In RAI 2.5-2, dated November 1, 2004, the staff noted that in LRA Section 2.1.5.2 the applicant

had stated that if a component in a commodity group existed in an area where the area

conditions exceeded the commodity group’s limiting environmental parameters, a further

evaluation could be performed to determine if the component was required for an intended

function of a system within the scope of license renewal. Therefore, the staff requested the

applicant to identify all the components that were excluded from the scope of license renewal

as a result of these further evaluations and to provide the basis used for excluding each

component.

By letter of December 1, 2004, the applicant responded as follows:

The following cables or cable types were scoped in by the “spaces” approach but

screened out of the scope of license renewal using further evaluations:

Cable Type THHN is PVC [polyvinyl chloride] insulated lighting wire - THHN

lighting wire was used in one circuit in the Drywell for normal lighting. This circuit

is not required for Appendix R or SBO lighting and was screened out of the

scope of license renewal.

Cable Type TW is a PVC insulated ground wire - BFN uses an ungrounded

electrical system thus equipment grounds are for personnel protection only and

degradation of the PVC insulation would not adversely affect equipment

operation.

The Safe Shutdown Analysis does not list any safety-related intended functions

for Source Range Monitors (SRMs) and Intermediate Range Monitors (IRMs)

Nuclear Instrumentation. Therefore, the Source Range and the Intermediate

Range Nuclear Instrumentation circuitry are screened out and are not subject to

an AMR.

The Safe Shutdown Analysis does not list any safety-related functions

associated with the Rod Block Monitors (RBMs). Therefore, the RBM circuitry is

screened out and is not subject to an AMR.

The only safety-related functions listed in the Safe Shutdown Analysis for the

Traversing Incore Probe system (TIP) is provide a reactor coolant pressure

boundary. Therefore, TIP circuitry is screened out and is not subject to an AMR.

The following inaccessible medium-voltage cables located in underground

conduit duct banks were screened out and not subject to an AMR since they do

not perform an intended function for license renewal as specified by

10 CFR 54.4.
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 • Cables routed to Off-gas Treatment Building Transformers A & B

 • Cables routed from the Condensate Circulating Water Pumps to the

Condensate Circulating Water Pump (CCWP) capacitor banks

 • Cables routed to Cooling Tower equipment

The staff found the exclusions and the reasons for the exclusions from the scope of license

renewal acceptable for all the components except the source range monitor (SRM) and

intermediate range monitor (IRM) cables, and the cables routed to off-gas treatment building

transformers A and B. In an email dated December 15, 2004, the staff asked the applicant for a

further response to RAI 2.5-2, clarifying why these components had been excluded from the

scope of license renewal.

The staff contended that nuclear instrumentation circuits cannot be screened out since these

circuits perform a safety function and provide trip signals to prevent any fuel damage during low

power operations. The staff, in support of this item, cited the applicant’s statement in LRA

Section 2.3.3.32: “The Neutron Monitoring System detects conditions that could lead to local

fuel damage and provides signals that can be used to prevent such damage.” 

With regard to the SRM circuit cables, the staff concurred with the applicant that, because the

SRM circuit cables are not designated as SR and they are not in the technical specification for

BFN, they do not require an AMR.

With regard to the IRM nuclear instrumentation circuitry, the applicant agreed with the staff that

IRM instrumentation circuit cables should be within the scope of license renewal because they

are part of the BFN technical specification. Because of this inclusion, the applicant confirmed

that their aging effects should be managed by the Electrical Cables Not Subject to

10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits

Program. All other accessible neutron monitoring subsystem cables and connections will be

managed by the Accessible Non-Environmental Qualification Cables and Connections

Inspection Program. This inclusion impacts the scope of the AMP’s elements "Program

Description" and "NUREG-1801 Consistency." These changes have been added to the SER

Appendix A commitment table, and the applicant will modify the UFSAR supplement to reflect

these changes. 

With regard to the exclusion of cables routed to off-gas treatment building transformers A and B

because they did not serve any intended function, the staff identified technical information in

LRA Section 2.3.3.19 that stated that the off-gas system is within the scope of license renewal

in accordance with 10 CFR 54.4(a). The SR functions of the off-gas system are to provide flow

path integrity for the release of the filtered standby gas treatment system gases to the stack,

and to provide automatic closure of back-draft prevention dampers to prevent back flow and

potential ground-level release of radiation. Therefore, the staff contended that cables routed to

off-gas treatment building transformers A & B cannot be screened out.

In its response dated January 18, 2005, the applicant stated that in performing SR functions the

off-gas system relies solely on mechanical components that do not require electrical power.

Therefore, the applicant stated that medium-voltage cables routed to off-gas treatment building

transformers A and B are screened out and not subject to an AMR. 
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The staff concurred with the applicant’s response dated January 18, 2005, that the intended

functions of the off-gas system addressed in LRA Section 2.3.3.19 are accomplished through

mechanical means without electrical power. However, the fans of the standby gas treatment

system listed in LRA Section 2.3.2.2 are within the scope of license renewal and are powered

by these transformers. Therefore, the cables listed in LRA Section 2.3.2.2 as being in the

standby gas treatment system should be within the scope of license renewal. 

Based on the above, the staff identified additional follow-up to RAI 2.5-2. In an informal request

on January 31, 2005, the staff requested clarifications on why these medium-voltage cables to

off-gas treatment building transformers A and B had been screened out.

In its response to clarifications to follow up to RAI 2.5-2, by letter dated March 2, 2005, the

applicant stated that standby gas treatment blowers, which are within the scope for license

renewal, are not powered from off-gas treatment building transformer A and B. The applicant

stated that the standby gas treatment system and the off-gas treatment system are completely

different systems, independent of each other and located in different buildings that do not share

power distribution systems or equipment. Standby gas treatment blowers, which are in scope

for license renewal, are not powered from off-gas treatment building transformers A and B. In

its response dated March 2, 2005, the applicant also provided details of the electrical circuits

that support its contention that these blowers are not powered from the above transformers.

The staff was satisfied with the explanation and considers this issue resolved.

On the basis of its review, the staff found that the applicant had adequately addressed all of the

staff's concerns raised in RAI 2.5-2. Therefore, the staff’s concerns described in RAI 2.5-2 are

resolved.

In RAI 2.5-3, dated November 1, 2004, the staff requested additional information regarding the

three license renewal drawings identified in LRA Section 2.5.1 that depict the recovery path for

SBO and identify the location of each commodity group component in the recovery path circuit. 

In its response, by letter December 1, 2004, the applicant properly identified the location of

each commodity group component in the SBO recovery path. The response includes details

from the 500 kV switchyard to the 4kV shutdown boards for all three units, transmission

conductor runs between breakers, and isolated phase bus runs between the main transformers

and the unit station service transformers. The applicant also stated that the SBO recovery path

circuits include control circuit wiring. The low-voltage power and control circuit wiring associated

with the power circuit breakers and disconnects are included within the scope of license

renewal, and there are no 500kV, 161kV, or 4kV underground power circuits used in SBO

recovery paths. These details are documented in its response. 

The staff found these details were in order and on the basis of its review, the staff found the

applicant’s response acceptable. Therefore, the staff’s concern described in RAI 2.5-3 is

resolved.

In RAI 2.5-4, dated November 1, 2004, the staff stated that during a teleconference held on

July 28, 2004, in response to a request for additional information, RAI 3.6-3, the applicant

stated that in 1997 a cross-linked polyethylene (XLPE)-insulated CCWP capacitor bank cable

failed in-service at BFN. Therefore, the staff requested that the applicant explain why these
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cables were not included within the scope of license renewal and identified as a component that

requires an AMR.

In its response to RAI 2.5-4, the applicant stated that the condensate circulating water (CCW)

system (system 027) is within the scope of license renewal because it provides manual vacuum

breaking capability to prevent backflow from the cooling tower warm channel into the forebay

upon trip of the CCW pumps. The capacitor bank provides additional starting power for the

condenser circulating water pumps to minimize loading on the electrical distribution system.

But, as previously stated in the response to RAI 2.5-2, above, the CCWP capacitor bank cables

are medium-voltage cables that do not perform an intended function for license renewal as

specified in 10 CFR 54.4. The staff had previously accepted the applicant’s position that these

cables are screened out and not subject to an AMR.

On the basis of its review, the staff found that the applicant had adequately addressed the

staff's concern. Therefore, the staff’s concern described in RAI 2.5-4 is resolved.

2.5.1.3 Conclusion

During its review of the information provided in the LRA, RAI responses, and the UFSAR, the

staff did not identify any omissions or discrepancies in the applicant's scoping and screening

results for electrical and I&C commodities. In addition, the staff performed a review to

determine whether any components that should be subject to an AMR had not been identified

by the applicant. No omissions were identified. On the basis of its review, the staff concluded

that the applicant had adequately identified the electrical and I&C commodities components that

are within the scope of license renewal, as required by 10 CFR 54.4(a), and the electrical and

I&C commodities components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
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2.6 Integration of Browns Ferry Nuclear, Unit 1, Restart Activities and License Renewal

Activities

BFN was designed and constructed by the applicant and licensed in 1973, 1974, and 1976

respectively. The three units are identical GE BWR/4 reactors with Mark I containments. The

units operated from original licensing until 1985 when they were voluntarily shut down by the

applicant to address management and technical issues. The applicant then implemented a

comprehensive nuclear performance plan to correct the deficiencies that led to the shutdown.

This plan included changes in management, programs, processes, and procedures, as well as

extensive equipment refurbishment, replacement, and modifications. Unit 2 was subsequently

restarted in 1991, and Unit 3 followed in 1995. In the early 1990s, the applicant decided to defer

restart of Unit 1. On May 16, 2002, the applicant announced the Unit 1 restart project. The

applicant had previously notified the staff of its intent to submit an LRA for Units 2 and 3 by

December 31, 2003. The applicant met with the staff on July 24, 2002, to discuss its proposal to

submit the LRA for all three units. Subsequent meetings were held with the staff on October 31,

2002, April 23, 2003, and September 29, 2003. Meeting summaries are documented by letters

dated November 25, 2002, June 2, 2003, and October 30, 2003, respectively, regarding the

license renewal application. In those meetings, agreement was reached with the staff on the

content and format of the application to ensure that it met all regulatory requirements and

supported staff review.

License Renewal Application Content. In the meetings referenced above, the applicant

explained that, although it was engaging in numerous plant modifications and restart activities,

the CLB for Unit 1 was well-known, defined, and documented, and the LRA would be prepared

based on the CLB. The unique element with Unit 1 is that restart activities include modifying the

Unit 1 licensing basis to make it consistent with the CLB of Units 2 and 3. During the meetings

with the staff, it was agreed the applicant would identify in the LRA the Unit 1 differences that

will be eliminated when restart activities are completed. To highlight these differences,

information not yet applicable to Unit 1 was marked with a bolded border. This annotation

methodology is consistent with previous multi-plant LRAs submitted to the staff. LRA

Appendix F describes each of these differences, its effect on the application, and the schedule

for resolution. It also provides references to application sections affected. This enabled the

applicant to submit an LRA based on the CLB for all three units, as well as to identify Unit 1

restart activities relevant to the LRA. As previously stated, the BFN units are essentially

identical, and the application is not unit-specific with regard to AMPs. The changes being

implemented as part of Unit 1 restart activities are consistent with the changes made previously

to Units 2 and 3. The AMPs are common for all three units because at restart the Unit 1

licensing basis will be the same as the licensing basis for Units 2 and 3.

2.6.1 Regulatory Framework for Review of BFN LRA and Integration Unit 1 Restart

Activities

By letter dated December 31, 2003, the applicant submitted an application pursuant to

10 CFR 54 to renew the operating licenses for the BFN Units 1, 2, and 3. The applicant is

submitting additional information concerning the status of Unit 1 restart activities and the impact

of those activities on the LRA. LRA Appendix F states that the Unit 1 restart program will result

in three operationally identical BFN units, providing assurance that the Unit 1 CLB changes

implemented prior to restart will result in the same CLB as that of Units 2 and 3 and that,
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therefore, the AMPs for each unit are the same. The Unit 1 CLB differences described in LRA

Appendix F will be resolved prior to Unit 1 restart.

BFN has a single UFSAR common to all three units. Unit 1 has been maintained in essentially

the same physical configuration as it was when it was shut down in 1985 (except for systems

required to keep Unit 1 in the shutdown condition or to support Units 2 and 3 operation). As

required by 10 CFR 50.71, the UFSAR was updated for all three units when amendments were

issued common to all the units. In 1998, the Unit 1 Technical Specifications were converted to

Improved Technical Specifications, as they were for Units 2 and 3. The license renewal UFSAR

supplement Appendix A identifies and describes the AMPs that are required for all three units.

No AMPs unique to Unit 1 are required during the period of extended operation. However, for

portions of Unit 1 systems that have not been replaced, the staff concluded that there was

insufficient operating history or data to conclude that one-time inspections are appropriate

substitutes for periodic inspections. Based on the advice from the interim review by the ACRS

in its 526th subcommittee meeting and in resolving the staff concerns in this matter, AMP

B.2.1.42, “Unit 1 Periodic Inspection Program,” was added to supplement one-time inspections.

The committee also felt that periodic inspections are the most significant compensating actions

for the lack of plant-specific operating experience of BFN Unit 1. This new AMP is only

applicable to Unit 1 and was added as a result of the staff reaching an agreement with the

applicant for managing piping and components left in place, specifically, the ones subjected to

the layup program. 

The LRA was structured to reflect the configuration and CLB of all three units. Scoping and

screening as well as AMRs were done based on the configuration and CLB of all three units.

The differences between the units that are relevant to the application, and which will be

resolved prior to Unit 1 restart, are listed in LRA Appendix F. 

As each activity identified in LRA Appendix F is completed, the corresponding highlighted 

(bold-bordered) text in the LRA will apply to Unit 1. The only change to the application will be to

remove the bolded border. No changes are required to scoping and screening results, AMR

results, or TLAAs. In some cases, boundary drawings would change to reflect the 

bold-bordered text. Accordingly, the staff reviewed all the bold-bordered items in the LRA as

they will exist when Unit 1 restarts. The staff review of Unit 1 items focused on the material,

aging effect, and AMPs as they exist in Units 2 and 3. There was no unique impact of these

evaluations on Unit 1 items, because the applicant stated that there were no unique AMPs for

Unit 1. The BFN procedures for AMPs apply site-wide and BFN procedures for new AMPs and

AMP enhancements will be issued for all three units.

LRA Appendix F provides the applicant’s plans and the schedules for Unit 1 restart activities

affecting the LRA. Whenever text shown with a bold-bordered box appears in the LRA,

indicating a licensing or design basis that only applies to Units 2 and 3, a link is provided to the

appropriate LRA Appendix F section.

LRA Appendix F summarizes the resolution of the differences between Unit 1 and Units 2 and

3. For each difference, the following information is presented:

Description – Describes the difference. 
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Difference Resolution – Explains the methodologies and activities that the applicant plans to

use to disposition each licensing or design-basis difference.

LRA Impact – Summarizes changes that would be expected to the LRA, if the condition were

resolved prior to issuance of the renewed licenses.

Schedule for Completion – Relates to milestones rather than specific dates. The schedules

reflect the current schedules in the Unit 1 restart plan and are subject to change as the plan is

implemented. The following milestones have been defined:

 • Prior to renewed license issuance – The applicant expects the resolution activities to be

complete prior to the expected issuance date of the renewed licenses.

 • Prior to restart – The applicant will complete the resolution activities prior to Unit 1

restart.

 • Permanent – The difference is acceptable as-is for license renewal. No changes related

to license renewal are necessary or planned for the condition.

 • If a submittal is required, the submittal milestone is stated.

 • Systems/structures/components impacted – The impacted systems, structures, or

components are identified with links to the appropriate sections in LRA Chapter 2

sections and the appropriate LRA Chapter 3 sections.

 • AMPs/TLAAs Impacted – The impacted AMPs and TLAAs are identified with links to the

appropriate section in LRA Chapter 4 and Appendix B.

Staff Evaluation Methodology. In reviewing the technical information provided in LRA

Appendix F, and January 31, 2005, letter, the staff review was limited to verifying (1) the

sufficiency of information provided by the applicant for the 13 items that impacted the LRA

review, (2) the applicability of the 13 items to Unit 1, (3) the systems these 13 items impacted,

and (4) the plan to resolve differences between the CLB for Unit 1 and the CLB for Units 2 and

3, so that upon restart all units will have the same CLB. It should be noted that in the LRA the

restart activities listed in LRA Appendix F are generally referred to as differences in the design

basis or licensing basis. Based on the definition of CLB in 10 CFR 54.3, these activities are

more precisely described as implementation activities of the design and licensing basis. The

applicant, by submittal dated March 2, 2006, provided details of previous safety evaluations

completed under 10 CFR 50.59, under plant changes that do not require staff approval and

agreed to make these evaluations available for an audit if necessary. Even though each of the

13 activities listed in LRA Appendix F is committed to and planned for completion prior to Unit 1

restart, any unimplemented commitments would remain valid, part of the CLB, carry over into

the renewed license period, and be controlled by the NRC regulatory and oversight process.

The staff's evaluation of the information provided in the LRA was performed in the same

manner for all mechanical, civil, electrical systems as it relates to the particular item in question.

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 had

been identified by the applicant as being within the scope of license renewal. Similarly, the staff

evaluated the applicant's screening results to verify that all long-lived, passive components are

subject to an AMR in accordance with 10 CFR 54.21(a)(1).
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Specific planned Unit 1 restart activities that impact license renewal are provided below.

2.6.1.1 Main Steam Isolation Valve Alternate Leakage Treatment

Description. In LRA Section F.1 the applicant described the proposed modification. The Unit 1

CLB for MSIV leakage does not incorporate an alternate leakage treatment pathway utilizing

main steam system piping and main condenser. The Unit 1 main steam piping from the

outermost isolation valve up to the turbine stop valve, the bypass/drain piping to the main

condenser, and the main condenser is being evaluated and will be modified as required to

ensure structural integrity is retained during and following an SSE. This will allow use of

methodology that assumes plateout and holdup in the piping and condenser (in LOCA offsite

and control room dose calculations) for radioactive leakage past the MSIVs. In the LRA, the

applicant stated that this methodology was included in the Units 2 and 3 CLB and will be

incorporated prior to Unit 1 restart.

Difference Resolution. The differences between the CLB for Unit 1 and the CLB for Units 2 and

3 will be resolved prior to Unit 1 restart by approval of a technical specification change dated

July 9, 2004, and implementation of the actions committed to in the proposed change prior to

Unit 1 restart. The applicant committed to revise plant operating procedures to provide

procedural requirements to establish the alternate leakage treatment path to the condenser and

to resolve the outliers identified in the supporting analysis. 

LRA Impact. The Unit 1 systems and structures impacted by this modification and their LRA

sections and tables:

 • high pressure coolant injection (Section 2.3.2.3)

 • auxiliary boiler (Section 2.3.3.1)

 • sampling and water quality (Section 2.3.3.14)

 • reactor core isolation cooling (Section 2.3.3.23)

 • main steam (Section 2.3.4.1 and Table 3.4.2.1)

 • condensate and demineralized water (Section 2.3.4.2 and Table 3.4.2.2)

 • heater drains and vents (Sections 2.3.4.4 and 3.4.2.1.4 and Table 3.4.2.4)

 • turbine drains and miscellaneous piping (Sections 2.3.4.5 and 3.4.2.1.5 and

Table 3.4.2.5)

 • turbine buildings (Section 2.4.7.1)

Following resolution of this item, the license renewal results shown with a bold-bordered box in

the sections identified above will be applicable to Unit 1.

Schedule for Completion. The Unit 1 modification is scheduled for completion prior to restart

and currently forecasted to be completed by August 2006. Should the applicant not receive

approval of technical specification (TS)-436, the effect on the license renewal is that the Unit 1

components credited in the MSIV alternate leakage pathway will not be within the scope of

license renewal as currently planned. The Unit 1 boundary drawings will remain accurate and

the increased scope identified by the bold-bordered boxes in the application will not be

applicable. Staff reviews of the application would not change.
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Staff Evaluation. The applicant evaluated the impacts to the scoping and screening of the

affected SSCs because of this Unit 1 restart modification. The applicant stated that after

approval of the proposed change (TS-436) and implementation of the actions committed to in

the proposed change prior to Unit 1 restart, there will be no functional differences in the

alternate leakage treatment pathways between Units 1, 2, and 3. The Unit 1 components that

comprise the alternate leakage treatment pathway will be incorporated into the appropriate

AMPs specified in the LRA, and there will be no unit-specific differences. The staff also

concurred with the applicant’s evaluation that there are no changes to the previously evaluated

intended function of respective systems and components screened and scoped previously. 

In addition, Unit 1 modifications impact LRA Section 2.1 “Scoping and Screening Methodology,”

which relates to the leakage pathway MSIV’s structural integrity. In its response dated May 31,

2005, the applicant provided information related to RAI 2.1-2A(1) and (2) concerning NSR

components that affect SR piping regarding the secondary containment integrity and also

related to RAIs 2.3.4.4-1 and 2.3.4.4-2. The staff found the applicant’s response to

RAI 2.1-2A(1) and (2) acceptable; therefore, RAIs 2.3.4.4-1 and 2.3.4.4-2 are closed.

In its submittal dated January 31, 2005, the applicant forecasted that this modification will be

completed by August 2006. This commitment will be tracked through a temporary instruction

TI-2509-01 as a part of the license application verification that this commitment be will

completed prior to Unit 1 restart. Other license conditions will not permit the applicant to enter

the period of extended operation without implementing this modification.

Conclusion. During its review of the information provided in the LRA, license renewal drawings,

RAI responses, and licensing-basis information, the staff did not identify any omissions or

discrepancies in the applicant's scoping and screening results for the structures and

components because of the MSIV alternate leakage treatment modification. The scoping and

screening reviews were done based on the CLB. The differences between the units’ CLBs that

are relevant to the application will be resolved prior to Unit 1 restart. The Unit 1 systems and

structures impacted by this modification, and their LRA sections and tables as indicated in the

list above, were evaluated in SER Section 2.1.3.1.2, and the staff requested additional

information. RAIs 2.1-2A(1) and (2) are related to seismic qualification of secondary

containment penetration seals. The MSIV alternate treatment modification potential involves

one such penetration. The staff in reviewing the structures and components impacted by these

modifications concluded that the applicant had adequately identified Unit 1 SSCs within the

scope of license renewal, as required by 10 CFR 54.4 (a), and the SSCs that are subject to an

AMR, as required by 10 CFR 54.21 (a)(1).

2.6.1.2 Containment Atmosphere Dilution System

Description. The CAD system consists of six pneumatic valves per unit, each with its own

accumulator and check valve. The CAD system was originally designated for short-term use

after DBEs. Long-term use (up to 100 days) was not considered in the original design. A

request to consider the long-term use of the CAD system was included in NUREG 0737 (TMI

action Plan), Item II.K.3.28 (Qualification of CAD Accumulators). The safety evaluation that

documents the acceptability of the applicant's plan to satisfy Item II.K.3.28 for all three units

was provided previously by letter dated July 24, 1985.
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The CAD system must have the capability to supply pressurized nitrogen to operate the main

steam relief valves when control air is not available to ensure the safe shutdown requirements

of 10 CFR Part 50, Appendix R following fires, and 10 CFR 50.63 during an SBO. That

capability has been installed on Units 2 and 3 and will be installed on Unit 1.

Difference Resolution. The differences between Unit 1 versus Units 2 and 3 will be resolved

prior to Unit 1 restart by upgrading the Unit 1 CAD accumulator system and implementing its

CLB, letter to NRC dated July 12, 1984. The capability to supply pressurized nitrogen to

operate the main steam relief valves for the long-term when control air is not available will be

provided by splitting the ring header into two sections and providing an alternate nitrogen supply

to the drywell control air system.

LRA Impact. The Unit 1 systems and structures impacted by this modification and their LRA

sections:

 • containment (2.3.2.1)

 • containment atmosphere dilution (2.3.2.7)

 • control air (2.3.3.10)

 • sampling and water quality (2.3.3.14)

 • reactor building closed cooling water (2.3.3.22)

 • radioactive waste treatment (2.3.3.25)

 • feedwater (2.3.4.3)

Following resolution of this item, the license renewal results shown with a bold-bordered box in

the sections identified above will be applicable to Unit 1. 

Schedule for Completion. The Unit 1 modification is scheduled for completion prior to restart

and currently forecasted to be completed by July 2006. Should the applicant not make the

modifications discussed above, the associated additional components planned to be installed

would not be installed and, therefore, the additional components would not be within the scope

of license renewal as currently planned. The Unit 1 boundary drawings would remain accurate

and the increased scope identified by the bold-bordered boxes in the application would not be

applicable. Staff reviews of the application would not change.

Staff Evaluation. Once the Unit 1 modifications are completed there will be no functional

differences in the containment atmosphere dilution nitrogen supply between Units 1, 2, and 3.

The Unit 1 components that comprise the containment atmosphere dilution nitrogen supply will

be incorporated into the appropriate AMPs specified in the LRA, and there will be no

unit-specific differences. As stated above, this modification is forecasted to be completed by

July 2006, and it will be duly tracked by a separate LRA Appendix A commitment and LRA

inspection prior to Unit 1 restart to confirm implementation. 

In its submittal dated January 31, 2005, the applicant forecasted that this modification will be

completed by August 2006. This commitment will be tracked through a temporary instruction

TI-2509-01 as a part of the license application verification that this commitment will be

completed prior to Unit 1 restart. Other license conditions will not permit the applicant to enter

the period of extended operation without implementing this modification.
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Conclusion. During its review of the information provided in the LRA, license renewal drawings,

and licensing-basis information, the staff did not identify any omissions or discrepancies in the

applicant's scoping and screening results for the structures and components because of the

containment atmosphere dilution system modification. The scoping and screening reviews were

done based on the CLB. The differences between the units’ CLBs that are relevant to the

application will be resolved prior to Unit 1 restart. The Unit 1 systems and structures impacted

by this modification, and their LRA sections and tables as indicated in the list above, were

evaluated elsewhere in the SER, and the staff did not identify any omissions or discrepancies.

Therefore, the staff concluded that the applicant had adequately identified the Unit 1 SSCs

within the scope of license renewal, as required by 10 CFR 54.4 (a), and the SSCs that are

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

2.6.1.3 Fire Protection

Description. The applicant is required by 10 CFR Part 50, Appendix R to have the capability to

maintain safe shutdown during and after a fire at BFN station. The staff issued an SER, dated

December 8, 1988, for the 10 CFR Part 50, Appendix R-Fire Protection Program, “Browns

Ferry Nuclear Plant, Units 1, 2, and 3 - Appendix R Safe Shutdown System Analysis,” and

supplemental safety evaluation, dated November 3, 1989, on the subject. In addition, by letter

dated March 6, 1991, the staff issued an associated license amendment. The SER for the fire

protection plan and fire hazards analysis was provided by staff letter to TVA, “Fire Protection

Program - Browns Ferry Nuclear Plant Units 1, 2, and 3," dated March 31, 1993. The

applicant’s Fire Protection Report, Volume 1 (UFSAR Chapter 10.11), states that the 10 CFR 

Part 50, Appendix R requirements for operating units have been established and implemented

for Units 2 and 3. The staff has also issued a license amendment for the 10 CFR Part 50,

Appendix R post-fire safe shutdown program, dated November 2, 1995.

Difference Resolution. The differences between the current fire protection licensing basis for

Unit 1 and the CLB for Units 2 and 3 will be resolved prior to Unit 1 restart by implementation of

the Fire Protection Program on Unit 1.

LRA Impact. The Unit 1 systems, structures, and AMPs impacted by this modification and their

LRA sections:

 • reactor recirculation (2.3.1.4)

 • containment (2.3.2.1)

 • high pressure coolant injection (2.3.2.3)

 • residual heat removal (2.3.2.4)

 • containment atmosphere dilution (2.3.2.7)

 • residual heat removal service water (2.3.3.3)

 • high pressure fire protection (2.3.3.6)

 • control air (2.3.3.10)

 • sampling and water quality (2.3.3.14)

 • emergency equipment cooling water (2.3.3.20)

 • reactor water cleanup (2.3.3.21)

 • reactor building closed cooling water (2.3.3.22)

 • reactor core isolation cooling (2.3.3.23)

 • radioactive waste treatment (2.3.3.25)
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 • fuel pool cooling and cleanup (2.3.3.26)

 • control rod drive (2.3.3.29)

 • main steam (2.3.4.1)

 • condensate and demineralized water (2.3.4.2)

 • feedwater (2.3.4.3)

 • primary containment structure (2.4.1.1)

 • reactor buildings (2.4.2.1)

 • turbine buildings (2.4.7.1)

 • electrical and instrumentation and control commodities (2.5.1)

 • Fire Protection Program (B.2.1.23)

 • Fire Water System Program (B.2.1.24)

Following resolution of this item, the license renewal results shown with a bold-bordered box in

the sections identified above will be applicable to Unit 1. 

It is reasonable to assume that the Fire Protection Program will be implemented prior to Unit 1

restart.

Schedule for Completion. The Unit 1 analyses and modifications are scheduled for completion

prior to restart and currently forecasted to be completed by August 2006.

Staff Evaluation. Once the Unit 1 Fire Protection Program modifications are completed there will

be no functional differences between Units 1, 2, and 3. The Unit 1 components that comprise

the high pressure fire protection system will be incorporated into the appropriate AMPs

specified in the LRA and there will be no unit-specific differences. The staff review of Unit 1

items focused on the material, aging effects, and AMPs as they exist in Units 2 and 3, and there

were no impacts of the evaluations on Unit 1 items, because the applicant stated that there was

no unique AMP for Unit 1. The staff found the explanation acceptable.

In its submittal dated January 31, 2005, the applicant forcasted that this modification will be

completed by August 2006. This commitment will be tracked through a temporary instruction

TI-2509-01 as a part of the license application verification that this commitment will be

completed prior to Unit 1 restart. Other license conditions will not permit the applicant to enter

the period of extended operation without implementing this modification.

Conclusion. During its review of the information provided in the LRA, license renewal drawings,

and licensing-basis information, the staff did not identify any omissions or discrepancies in the

applicant's scoping and screening results for the structures and components because of the fire

protection modification. The scoping and screening reviews were done based on the CLB. The

differences between the units’ CLBs that are relevant to the application will be resolved prior to

Unit 1 restart. The Unit 1 systems and structures impacted by this modification, and their LRA

sections and tables as indicated in the list above, were evaluated elsewhere in the SER, and

the staff did not identify any omissions or discrepancies. Therefore, the staff concluded that the

applicant had adequately identified the Unit 1 SSCs within the scope of license renewal, as

required by 10 CFR 54.4 (a), and the SSCs that are subject to an AMR, as required by

10 CFR 54.21(a)(1). 
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2.6.1.4 Environmental Qualification

Description. A site-wide EQ Program required by 10 CFR 50.49 has been developed for BFN,

and implemented on Units 2 and 3, and it is expected to be implemented on Unit 1 to ensure

compliance with 10 CFR 50.49.

As part of the recovery program for Browns Ferry, by October 24, 1988 letter, the applicant

committed to implement its EQ Program so that electrical equipment located in a harsh

environment would meet 10 CFR 50.49 requirements prior to the restart of each unit. The

safety evaluation for the program was issued by the staff on January 23, 1991. The site-wide

EQ Program required by 10 CFR 50.49 was developed for BFN, implemented on Units 2 and 3,

and is being implemented on Unit 1. This program defines responsibilities and specifies

requirements to establish and maintain auditable documentation demonstrating the

environmental qualification of equipment. This program is described in LRA Section 4.4. 

The EQ Program:

 • Identifies the applicable DBAs and determines the environmental parameters for those

accidents. The environmental parameters are necessary for procurement, design, and

qualification of equipment in accordance with 10 CFR 50.49.

 • Identifies the equipment and cables in the harsh zones within the scope of

10 CFR 50.49 and determines their required operating times. 

 • Is established or procured and documented for each piece of equipment in the

10 CFR 50.49 list. Environmental Qualification Data Packages provide documented

evidence that demonstrates the qualification of each piece of equipment for its specific

application and environment. Components subject to 10 CFR 50.49 requirements that

are not qualified for the license term must be refurbished, replaced, or have their

qualification extended prior to reaching the aging limits established in their evaluation. 

 • Actions are identified, proceduralized, and initiated to maintain the qualification of

installed equipment and cables. This includes periodic, preventive, or corrective

maintenance; procurement controls; and storage requirements. The safety evaluation

for the program was issued by the staff on January 23, 1991.

Difference Resolution. The differences between the CLB for Unit 1 and the CLB for Units 2 and

3 will be resolved prior to Unit 1 restart by implementation of the EQ Program on Unit 1, as

stated in the LRA Sections 4.4 and B.3.1.

UFSAR Impact. The Unit 1 systems, structures, commodities, AMPs, and TLAAs impacted by

this modification and its LRA sections and tables:

 • reactor recirculation (Section 2.3.1.4)

 • containment (Section 2.3.2.1)

 • high pressure coolant injection (Section 2.3.2.3)

 • residual heat removal (Section 2.3.2.4)

 • core spray (Section 2.3.2.5)

 • containment inerting (Section 2.3.2.6)
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 • containment atmosphere dilution (Section 2.3.2.7)

 • control air (Section 2.3.3.10)

 • sampling and water quality (Section 2.3.3.14)

 • emergency equipment cooling water (Section 2.3.3.20)

 • reactor water cleanup (Section 2.3.3.21)

 • reactor building closed cooling water (Section 2.3.3.22)

 • reactor core isolation cooling (Section 2.3.3.23)

 • radioactive waste treatment (Section 2.3.3.25)

 • control rod drive (Section 2.3.3.29)

 • radiation monitoring (Section 2.3.3.31)

 • main steam (Section 2.3.4.1)

 • feedwater (Section 2.3.4.3)

 • primary containment structure (Section 2.4.1.1)

 • reactor buildings (Section 2.4.2.1)

 • electrical and I&C commodities (Section 2.5.1 and Tables 3.6.1 and 3.6.2.1)

 • EQ TLAA (Section 4.4)

 • EQ Program (Section B.3.1)

Following resolution of this item, the license renewal results shown with a bold-bordered box in

the sections identified above will be applicable to Unit 1.

Schedule for Completion. The Unit 1 analyses and modification is scheduled for completion

prior to restart and currently forcasted to be completed by July 2006.

Staff Evaluation. The differences between the CLB for Unit 1 and the CLB for Units 2 and 3 will

be resolved prior to Unit 1 restart by implementation of the EQ Program. Once the Unit 1

portion of the EQ Program is completed, the BFN site-wide EQ Program will ensure that the

components subject to 10 CFR 50.49 requirements are maintained within the bounds of their

qualification bases for the period of extended operation.

In its submittal dated January 31, 2005, the applicant forcasted that this modification will be

completed by August 2006. This commitment will be tracked through a temporary instruction

TI-2509-01 as a part of the license application verification that this commitment will be

completed prior to Unit 1 restart. Other license conditions will not permit the applicant to enter

the period of extended operation without implementing this modification.

Conclusion. During its review of the information provided in the LRA, license renewal drawings,

and licensing-basis information, the staff did not identify any omissions or discrepancies in the

applicant's scoping and screening results for the structures and components because of the EQ

modification. The scoping and screening reviews were done based on the CLB. The differences

between the units’ CLBs that are relevant to the application will be resolved prior to Unit 1

restart. The Unit 1 systems and structures impacted by this modification, and their LRA sections

and tables as indicated in the list above, were evaluated elsewhere in the SER, and the staff did

not identify any omissions or discrepancies. Therefore, the staff concluded that the applicant

had adequately identified the Unit 1 SSCs within the scope of license renewal, as required by

10 CFR 54.4 (a), and the SSCs that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
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2.6.1.5 Intergranular Stress Corrosion Cracking

The applicant submitted and implemented plans for addressing intergranular stainless steel

stress corrosion cracking in accordance with generic letter (GL) 88-01 and Supplement 1 for

Units 2 and 3. In accordance with the Unit 1 restart plan, GL 88-01 will be addressed for Unit 1.

Description. The BWR Stress Corrosion Cracking Program manages IGSCC in reactor coolant

pressure boundary components made of stainless steel.

The applicant's program to address GL 88-01, the staff position on IGSCC in BWR austenitic

stainless steel piping, for Unit 3 was provided by letter dated December 28, 1992. The

applicant, by its letter dated August 1, 1988, previously committed to submit a report containing

the details of the repair or replacement work. The safety evaluation documenting the

acceptability of the program was provided and supplemental information regarding Unit 1 was

submitted by letter dated December 3, 1993. The following wrought austenitic stainless steel

piping systems and components on Unit 1 are considered susceptible to IGSCC according to

the guidelines given in GL 88-01:

 • reactor recirculation from the recirculation inlet and outlet nozzles to the connections

with RHR

 • RHR from the recirculation system to the first isolation valve outside of the drywell

penetration

 • reactor water cleanup (RWCU) from its connection to the RHR system to first isolation

valve outside of the drywell penetration

 • core spray from the core spray inlet nozzles to the drywell penetration, including the

core spray inlet safe ends

 • jet pump instrument safe ends

In its letter, dated July 21, 2004, the applicant informed the staff that the IGSCC-susceptible

piping on Unit 1 is being replaced using materials that are resistant to IGSCC. To address the

requirements for inspection schedules and expansion plans, the susceptible weldments have

been categorized according to NUREG 0313, Revision 2, Section 5, Table 1. The in-service

inspections are required by BFN Technical Requirements Manual, Section 3.4.3.

Difference Resolution. The differences between the CLB for Unit 1 and the CLB for Units 2 and

3 will be resolved Unit 1 prior to restart by the replacement of the IGSCC-susceptible piping,

and by providing IGSCC protection or mitigation.

UFSAR Impact. The Unit 1 systems and AMPs impacted by this modification and their LRA

sections and table:

 • reactor vessel (Section 2.3.1.1)

 • reactor recirculation (Section 2.3.1.4)

 • residual heat removal (Section 2.3.2.4)

 • core spray (Section 2.3.2.5 and Table 3.2.2.5)

 • reactor water cleanup (Section 2.3.3.21)
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 • Boiling Water Reactor Stress Corrosion Cracking Program (B.2.1.10)

 • BWR Reactor Water Cleanup System Program (B.2.1.22)

It is reasonable to assume that replacement of the IGSCC-susceptible piping will be performed.

The applicant has already removed the original piping and must replace it to operate the unit.

Following resolution of this item, the license renewal results shown with a bold-bordered box in

the sections identified above will be applicable to Unit 1.

Schedule for Completion. Submittal of the Unit 1 IGSCC plan and implementation report, as

well as the physical modification, are scheduled for completion prior to restart and currently

forcasted to be completed by March 2006. This commitment will be tracked through a

temporary instruction TI-2509-01 as a part of the license application verification that this

commitment will be completed prior to Unit 1 restart. Other license conditions will not allow the

applicant to enter the period of extended operation without implementing this modification.

Staff Evaluation. Once the piping replacement modifications are completed on Unit 1 there will

be no functional differences in the IGSCC mitigation or protection between Units 1, 2, and 3.

The Unit 1 components that mitigate IGSCC will be incorporated into the appropriate AMPs and

there will be no unit-specific differences.

In its submittal dated January 31, 2005, the applicant forcasted that this modification will be

completed by August 2006. Other license conditions will not permit the applicant to enter the

period of extended operation without implementing this modification.

Conclusion. During its review of the information provided in the LRA, license renewal drawings,

and licensing-basis information, the staff did not identify any omissions or discrepancies in the

applicant's scoping and screening results for the structures and components because of the

IGSCC modification. The scoping and screening reviews were done based on the CLB. The

differences between the units’ CLBs that are relevant to the application will be resolved prior to

Unit 1 restart. The Unit 1 systems and structures impacted by this modification, and their LRA

sections and tables as indicated in the list above, were evaluated elsewhere in the SER, and

the staff has not identified any omissions or discrepancies. Therefore, the staff concluded that

the applicant had adequately identified the Unit 1 SSCs within the scope of license renewal, as

required by 10 CFR 54.4 (a), and the SSCs that are subject to an AMR, as required by

10 CFR 54.21(a)(1). 

2.6.1.6 Boiling Water Reactor Vessel and Internals Project Inspection and Flaw

Evaluation Guidelines Implementation

Summary of Technical Information. During Unit 1’s extended outage, the BWRVIP was initiated

to develop inspection and flaw evaluation guidelines. The following guidelines will be

implemented on Unit 1 during its restart.

BWRVIP-03 Reactor Pressure Vessel and Internals Examination Guidelines

BWRVIP-05 BWR Reactor Pressure Vessel Shell Weld Inspection Recommendations

BWRVIP-06-A Safety Assessment of BWR Reactor Internals

BWRVIP-15 Configurations of Safety-Related BWR Reactor Internals

BWRVIP-18 BWR Core Spray Internals Inspection and Flaw Evaluation Guidelines
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BWRVIP-25 BWR Core Plate Inspection and Flaw Evaluation Guidelines

BWRVIP-26 BWR Top Guide Inspection and Flaw Evaluation Guidelines

BWRVIP-27-A BWR Standby Liquid Control System/Core Plate Inspection and Flaw Evaluation

Guidelines

BWRVIP-38 BWR Shroud Support Inspection and Flaw Evaluation Guidelines

BWRVIP-41 BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines

BWRVIP-47 BWR Lower Plenum Inspection and Flaw Evaluation Guidelines

BWRVIP-48 Vessel ID Attachment Weld Inspection and Flaw Evaluation

BWRVIP-49-A Instrument Penetration Inspection and Flaw Evaluation Guidelines

BWRVIP-74-A BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines

BWRVIP-75 Technical Basis for Revisions to Generic Letter 88-01 Inspection Schedules

BWRVIP-76 BWR Core Shroud Inspection and Flaw Evaluation Guidelines

BWRVIP-94 Program Implementation Guide

BWRVIP-104 Evaluation and Recommendations to Address Shroud Support Cracking in BWRs

Difference Resolution. The differences between the CLB for Unit 1 and the CLB for Units 2 and

3 with regard to the reactor vessel and internal inspection criteria will be resolved prior to Unit 1

restart by the implementation of the BWRVIP guidelines on Unit 1.

UFSAR Impact. The Unit 1 systems and AMPs impacted by this modification and their LRA

sections:

 • reactor vessel (3.1.2.2.16)

 • reactor vessel internals (3.1.2.2.16)

 • Boiling Water Reactor Vessel Inside Diameter Attachment Welds Program (B.2.1.7)

 • Boiling Water Reactor Penetrations Program (B.2.1.11)

 • Boiling Water Reactor Vessel Internals Program (B.2.1.12)

It is reasonable to assume that the applicant will implement the BWRVIP guidelines. Without

continued commitment to the BWRVIP, the applicant would have to independently develop and

obtain staff approval of alternate methodologies for Unit 1, which is not economically feasible.

Following resolution of this item, the license renewal results shown with a bold-bordered box in

the sections identified above will be applicable to Unit 1. 

Schedule for Completion. The Unit 1 modification is scheduled for completion prior to restart

and currently forcasted to be completed by November 2005.

Staff Evaluation. Prior to restart of Unit 1, the BWRVIP information included in the application

will be implemented on Unit 1.

In its submittal dated January 31, 2005, the applicant forcasted that this modification will be

completed by November 2006. This commitment will be tracked through a temporary instruction

TI-2509-01 as a part of the license application verification that this commitment will be

completed prior to Unit 1 restart. Other license conditions will not permit the applicant to enter

the period of extended operation without implementing this modification.

Conclusion. During its review of the information provided in the LRA, license renewal drawings,

and licensing-basis information, the staff did not identify any omissions or discrepancies in the
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applicant's scoping and screening results for the structures and components because of the

BWRVIP and flaw evaluation guidelines implementation modification. The scoping and

screening reviews were done based on the CLB. The differences between the units’ CLBs that

are relevant to the application will be resolved prior to Unit 1 restart. The Unit 1 systems and

structures impacted by this modification, and their LRA sections and tables as indicated in the

list above, were evaluated elsewhere in the SER, and the staff has not identified any omissions

or discrepancies. Therefore, the staff concluded that the applicant had adequately identified the

Unit 1 SSCs within the scope of license renewal, as required by 10 CFR 54.4 (a), and the SSCs

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

2.6.1.7 Anticipated Transients Without Scram

Description. Section 50.62 of 10 CFR requires applicants to reduce the risk from ATWS events.

The applicant adopted the BWR Owners’ Group recommendation for implementation of the

ATWS rule by letter dated March 1, 1988. The staff approval of the applicant’s approach for

satisfying 10 CFR 50.62 was provided on January 22, 1989, and the associated TS changes

were approved on January 26, 1989. TS 3.3.4.2 for the BFN units provides the requirements for

the ATWS recirculation pump trip (ATWS-RPT) instrumentation. TS 3.1.7, SLC system, for the

BFN units provides requirements for ATWS that satisfy 10 CFR 50.62. In its letter dated

November 29, 1990, the applicant confirmed its commitment to install the required ATWS

modifications prior to Unit 1 restart. Design features described in UFSAR Chapter 7.19 will be

installed on Unit 1.

Difference Resolution. The differences between the CLB for Unit 1 and the CLB for Units 2 and

3 will be resolved prior to Unit 1 restart by implementation of the ATWS modifications on Unit 1.

The CRD system will have a diverse scram (i.e. alternate rod injection) in accordance with LRA

Section 2.3.3.29. 

UFSAR Impact. The Unit 1 systems, structures, and commodities impacted by this modification

and their LRA sections:

 • reactor core isolation cooling (2.3.3.23)

 • control rod drive (2.3.3.29)

 • feedwater (2.3.4.3)

 • primary containment structure (2.4.1.1)

 • reactor buildings (2.4.2.1)

 • electrical and instrumentation and control commodities (2.5.1)

Following resolution of this item, it is expected that the license renewal results shown with a

bold-bordered box in the sections identified above will be applicable to Unit 1.

Schedule for Completion. The Unit 1 analyses and modifications are scheduled for completion

prior to restart. If for any reason, the applicant changes its planned actions to address

10 CFR 50.62, it will need to submit a revised TS change for staff approval and address the

aging management aspects of the changes as necessary.

Staff Evaluation. After the implementation of the ATWS modifications on Unit 1 there will be no

functional differences in the ATWS system between Units 1, 2, and 3. The Unit 1 components
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that perform the ATWS function will be incorporated into the appropriate AMPs specified in the

LRA and there will be no unit-specific differences.

In its submittal dated January 31, 2005, the applicant forcasted that this modification will be

completed by May 2006. This commitment will be tracked through a temporary instruction

TI-2509-01 as a part of the license application verification that this commitment will be

completed prior to Unit 1 restart. Other license conditions will not permit the applicant to enter

the period of extended operation without implementing this modification.

Conclusion. During its review of the information provided in the LRA, license renewal drawings,

and licensing-basis information, the staff did not identify any omissions or discrepancies in the

applicant's scoping and screening results for the structures and components because of the

ATWS modification. The scoping and screening reviews were done based on the CLB. The

differences between the units’ CLBs that are relevant to the application will be resolved prior to

Unit 1 restart. The Unit 1 systems and structures impacted by this modification, and their LRA

sections and tables as indicated in the list above, were evaluated elsewhere in the SER, and

the staff did not identify any omissions or discrepancies. Therefore, the staff concluded that the

applicant had adequately identified the Unit 1 SSCs within the scope of license renewal, as

required by 10 CFR 54.4 (a), and the SSCs that are subject to an AMR, as required by

10 CFR 54.21(a)(1). 

2.6.1.8 Reactor Vessel Head Spray

Description. The reactor vessel head spray piping is susceptible to IGSCC and was included in

GL 88-01. The applicant responded to GL 88-01 for all three units by letter dated August 1,

1988. In that letter, the applicant notified the staff that it had previously removed the head spray

piping from Units 2 and 3, and planned to remove the head spray piping from Unit 1 prior to

startup. The staff’s approval was provided on December 3, 1993. The applicant reconfirmed, in

its July 21, 2004, supplemental response to GL 88-01 for Unit 1, that it planned to remove the

reactor vessel head spray piping prior to Unit 1 restart.

On Units 2 and 3, the reactor vessel head spray piping within the drywell has been removed

and the reactor vessel head penetration has a flanged cap installed. The primary containment

isolation valves have been removed and the primary containment penetration has been sealed.

Head spray piping has also been removed and a permanent welded cap has been installed at

the RHR system interface with its head spray header.

Difference Resolution. The differences between the CLB for Unit 1 and the CLB for Units 2 and

3 will be resolved prior to Unit 1 restart by performing these head spray modifications on Unit 1.

Once the head spray modifications are completed on Unit 1 prior to restart, the physical and

operational differences between Unit 1 and Units 2 and 3 will be resolved

UFSAR Impact. The Unit 1 systems impacted by this modification and their LRA sections:

Reactor Vessel Internals (2.3.1.2)

Residual Heat Removal (2.3.2.4)
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Following resolution of this item, the license renewal results shown with a bold-bordered box in

the LRA sections identified above will be applicable to Unit 1.

Schedule for Completion. The Unit 1 modification is scheduled for completion prior to restart

and currently forcasted to be completed by June 2006.

Staff Evaluation. After the implementation of the reactor vessel head spray modifications on

Unit 1 there will be no functional differences in the reactor vessel head spray system between

Units 1, 2, and 3. The Unit 1 components that perform the reactor vessel head spray function

will be incorporated into the appropriate AMPs specified in the LRA, and there will be no

unit-specific differences.

In its submittal dated January 31, 2005, the applicant forcasted that this modification will be

completed by June 2006. This commitment will be tracked through a temporary instruction

TI-2509-01 as a part of the license application verification that this commitment will be

completed prior to Unit 1 restart. Other license conditions will not permit the applicant to enter

the period of extended operation without implementing this modification.

Conclusion. During its review of the information provided in the LRA, license renewal drawings,

and licensing-basis information, the staff did not identify any omissions or discrepancies in the

applicant's scoping and screening results for the structures and components because of the

reactor vessel head spray modification. The scoping and screening reviews were done based

on the CLB. The differences between the units’ CLBs that are relevant to the application will be

resolved prior to Unit 1 restart. The Unit 1 systems and structures impacted by this modification,

and their LRA sections and tables as indicated in the list above, were evaluated elsewhere in

the SER, and the staff did not identify any omissions or discrepancies. Therefore, the staff

concluded that the applicant had adequately identified the Unit 1 SSCs within the scope of

license renewal, as required by 10 CFR 54.4 (a), and the SSCs that are subject to an AMR, as

required by 10 CFR 54.21(a)(1). 

2.6.1.9 Hardened Wetwell Vent

Description. In GL 89-16, dated September 1, 1989, the staff requested applicants with Mark I

containments to voluntarily install a hardened wetwell vent. In response, the applicant

committed, by letter dated October 30, 1989, to install a hardened wetwell vent prior to restart

of each unit. The hardened wetwell vent has been installed on Units 2 and 3, but has not yet

been implemented on Unit 1. 

Difference Resolution. The differences between the CLB for Unit 1 and the CLB for Units 2 and

3 will be resolved prior to Unit 1 restart by the installation of the hardened wetwell vent on

Unit 1. Once the modifications are completed, the physical and operational differences between

Unit 1 and Units 2 and 3 will be resolved.

UFSAR Impact. The Unit 1 system and structure impacted by this modification and their LRA

sections:

 • containment (2.3.2.1)

 • reinforced concrete chimney (2.4.6.1)
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Following resolution of this item, the license renewal results shown with a bold-bordered box in

the sections identified above are applicable to Unit 1.

Schedule for Completion. The Unit 1 modification is scheduled for completion prior to restart

and this modification is currently forcasted to be completed by May 2006. If for any reason, the

applicant decided it would implement an alternate solution to GL 89-19, the applicant would be

required to notify the staff, and include any alternate modifications within the appropriate AMPs.

Staff Evaluation. After the Unit 1 hardened wetwell vent modifications are completed, there will

be no functional differences in the associated systems for Units 1, 2, and 3. The Unit 1

components that comprise the hardened wetwell vent will be incorporated into the appropriate

AMPs specified in the LRA, and there will be no unit-specific differences.

In its submittal dated January 31, 2005, the applicant forcasted that this modification will be

completed by May 2006. This commitment will be tracked through a temporary instruction

TI-2509-01 as a part of the license application verification that this commitment will be

completed prior to Unit 1 restart. Other license conditions will not permit the applicant to enter

the period of extended operation without implementing this modification.

Conclusion. During its review of the information provided in the LRA, license renewal drawings,

and licensing-basis information, the staff did not identify any omissions or discrepancies in the

applicant's scoping and screening results for the structures and components because of the

hardened wetwell vent modification. The scoping and screening reviews were done based on

the CLB. The differences between the units’ CLBs that are relevant to the application will be

resolved prior to Unit 1 restart. The Unit 1 systems and structures impacted by this modification,

and their LRA sections and tables as indicated in the list above, were evaluated elsewhere in

the SER, and the staff did not identify any omissions or discrepancies. Therefore, the staff

concluded that the applicant had adequately identified the Unit 1 SSCs within the scope of

license renewal, as required by 10 CFR 54.4 (a), and the SSCs subject to an AMR, as required

by 10 CFR 54.21(a)(1). 

2.6.1.10 Service Air and Demineralized Water Primary Containment Penetrations

Description. The staff requested, by letter dated May 5, 1992, information regarding Unit 1

compliance with NUREG-0737, Item II.E.4.2; and 10 CFR Part 50, Appendix J. The staff

compared the Unit 1 containment isolation scheme to the Unit 2 design and concluded, in the

January 6, 1995, safety evaluation, that the isolation design was acceptable. Currently, the

configuration of the Unit 1 primary containment penetrations numbers, X-20 and X-21, are

different from the corresponding configuration on Units 2 and 3. On Unit 1 the penetrations are

piped to the service air and demineralized water systems with primary containment isolation

valves. On Units 2 and 3, they are capped and not assigned to a service system. These

penetrations on Unit 1 will be capped and made identical to those of Units 2 and 3. 

Difference Resolution. The differences between the CLB for Unit 1 and the CLB for Units 2 and

3 will be resolved prior to Unit 1 restart by making the Unit 1 configuration the same as the

current Units 2 and 3 configuration. Once the service air and demineralized

water systems modifications are completed on Unit 1, the physical and operational differences

between Unit 1 versus Units 2 and 3 will be resolved.
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If for any reason, the applicant decided it would not implement the committed modifications, the

applicant would be required to notify the staff so that the following action to bring the item into

the scope of managed piping would apply. The Unit 1 associated piping and components that

are to be removed are shown on the Unit 1 boundary drawings and if the piping were not

removed, the AMPs specified in the LRA would apply. Thus, there would be no change in the

application if the committed modifications were not completed.

UFSAR Impact. The Unit 1 systems impacted by this modification and their LRA sections:

 • service air (2.3.3.11)

 • condensate and demineralized water (2.3.4.2)

Following resolution of this item, the license renewal results shown with a bold-bordered box in

the LRA sections identified above will be applicable to Unit 1.

Schedule for Completion. The Unit 1 modification is scheduled for completion prior to restart

and is currently forecasted to be completed by May 2006.

Staff Evaluation. After the modifications to the Unit 1 service air and condensate and

demineralized systems piping are completed there will be no functional differences in the

associated primary containment configurations for Units 1, 2, and 3.

In its submittal dated January 31, 2005, the applicant forcasted that this modification will be

completed by May 2006. This commitment will be tracked through a temporary instruction

TI-2509-01 as a part of the license application verification that this commitment will be

completed prior to Unit 1 restart. Other license conditions will not permit the applicant to enter

the period of extended operation without implementing this modification.

Conclusion. During its review of the information provided in the LRA, license renewal drawings,

and licensing-basis information, the staff did not identify any omissions or discrepancies in the

applicant's scoping and screening results for the structures and components because of the

service air and demineralized water primary containment penetrations modification. The

scoping and screening reviews were done based on the CLB. The differences between the

units' CLBs that are relevant to the application will be resolved prior to Unit 1 restart. The Unit 1

systems and structures impacted by this modification, and their LRA sections and tables as

indicated in the list above, were evaluated elsewhere in the SER, and the staff did not identify

any omissions or discrepancies. Therefore, the staff concluded that the applicant had

adequately identified the Unit 1 SSCs within the scope of license renewal, as required by

10 CFR 54.4 (a), and the SSCs that are subject to an AMR, as required by 10 CFR 54.21(a)(1). 

2.6.1.11 Auxiliary Decay Heat Removal System

Description. As described in UFSAR 10.22, the ADHR system only serves Units 2 and 3. The

only intended function for license renewal is to provide secondary containment integrity for the

ADHR system’s piping that transfers the fuel pool heat. 
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The ADHR system provides an NSR means to remove decay heat and residual heat from the

spent fuel pool and reactor cavity, and currently serves only Units 2 and 3. The ADHR allows

servicing of the RHR system components earlier in an outage, thus, potentially reducing the

outage duration. The only intended function for license renewal is to provide secondary

containment integrity for the ADHR system’s piping that transfers the fuel pool heat to the heat

sink outside containment. There is currently only a single piping loop serving both Units 2 and 3

that penetrates the secondary containment.

The configuration of the ADHR system will be modified to service Unit 1 as well as Units 2 and

3. When modified, there will continue to be only a single piping loop that penetrates the

secondary containment. That loop and its secondary containment penetrations will serve all

three units.

Difference Resolution. The differences between the CLB for Unit 1 and the CLB for Units 2 and

3 will be resolved prior to Unit 1 restart by modifying the ADHR system to service Unit 1 as well

as Units 2 and 3. When modified, there will continue to be only a single piping loop that

penetrates the secondary containment. That loop and its secondary containment penetrations

will serve all three units. Once the ADHR modifications are completed on Unit 1 prior to restart,

the physical and operational differences between Unit 1 and Units 2 and 3 will be resolved.

UFSAR Impact. The Unit 1 system impacted by this modification and its LRA sections and table

is the auxiliary decay heat removal system (2.3.3.24 and 3.3.2.1.24 and Table 3.3.2.24).

Following resolution of this item, the license renewal results shown with a bold-bordered box in

the LRA sections and table identified above will be applicable to Unit 1. Should the applicant not

make the modifications discussed above, the applicant would be required to notify the staff.

Since these associated additional components planned to be installed would not be installed,

the boundary drawings for Unit 1 would not change, and the additional components would not

be included within the appropriate AMPs as currently planned.

Schedule for Completion. The Unit 1 modification is scheduled for completion prior to Unit 1

restart and is currently projected to be complete by May 2005.

Staff Evaluation. After the modifications to the ADHR system are completed there will be no

functional differences in the system for Units 1, 2, and 3.

In its submittal dated January 31, 2005, the applicant forcasted that this modification will be

completed by May 2006. This commitment will be tracked through a temporary instruction

TI-2509-01 as a part of the license application verification that this commitment will be

completed prior to Unit 1 restart. Other license conditions will not permit the applicant to enter

the period of extended operation without implementing this modification.

Conclusion. During its review of the information provided in the LRA, license renewal drawings,

and licensing-basis information, the staff did not identify any omissions or discrepancies in the

applicant's scoping and screening results for the structures and components because of the

ADHR system modification. The scoping and screening reviews were done based on the CLB.

The differences between the units' CLBs that are relevant to the application will be resolved

prior to Unit 1 restart. The Unit 1 systems and structures impacted by this modification, and

their LRA sections and tables as indicated in the list above, were evaluated elsewhere in the
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SER, and the staff did not identify any omissions or discrepancies. Therefore, the staff

concluded that the applicant had adequately identified the Unit 1 SSCs within the scope of

license renewal, as required by 10 CFR 54.4 (a), and the SSCs that are subject to an AMR, as

required by 10 CFR 54.21(a)(1). 

2.6.1.12 Maintenance Rule

Description. By letter dated August 9, 1999, the staff issued a partial temporary exemption. 

This exempts the applicant from the specific scoping requirements of 10 CFR 50.65(b) and

allows it to maintain the defueled and long-term layup status of Unit 1. The exemption does not

impact Maintenance Rule scoping for equipment required to be functional to support Unit 1 in

its defueled status or equipment required to support operation of Units 2 and 3.

The scoping results for the affected SSCs will not be changed. No changes are expected for

AMR results or TLAAs.

The temporary exemption expires upon restart of Unit 1.

Difference Resolution. The differences between the CLB for Unit 1 and the CLB for Units 2 and

3 will be resolved upon the restart of Unit 1, when the temporary exemption ceases to be

effective. Specifically, with respect to the CLB differences identified in the application, the

differences in the Maintenance Rule implementation will be resolved.

UFSAR impact. There are no Unit 1 systems impacted by this modification because Unit 1

SSCs not required to be functional during the current shutdown and defueled status are not

included within the scope of the Maintenance Rule.

Schedule for Completion. The committed completion date is at Unit 1 restart because the

temporary exemption will expire upon Unit 1 restart and the full scope of the Maintenance Rule

will apply to Unit 1.

Staff Evaluation, After the Maintenance Rule modifications are completed upon Unit 1 restart,

there will be no functional differences in the system for Units 1, 2, and 3.

As stated above, this modification is forcasted to be completed upon Unit 1 restart, and it will be

duly tracked by a separate LRA Appendix A commitment and LRA inspection prior to restart to

confirm implementation. 

In its submittal dated January 31, 2005, the applicant forcasted that this modification will be

completed by Unit 1 restart. This commitment will be tracked through a temporary instruction

TI-2509-01 as a part of the license application verification that this commitment will be

completed prior to Unit 1 restart. Other license conditions will not permit the applicant to enter

the period of extended operation without implementing this modification.

Conclusion. During its review of the information provided in the LRA, license renewal drawings,

and licensing-basis information, the staff did not identify any omissions or discrepancies in the

applicant's scoping and screening results for the structures and components because of the

Maintenance Rule modification. The scoping and screening reviews were done based on the
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CLB. The differences between the units' CLBs that are relevant to the application will be

resolved prior to Unit 1 restart. The Unit 1 systems and structures impacted by this modification,

and their LRA sections and tables as indicated in the list above, were evaluated elsewhere in

the SER, and the staff did not identify any omissions or discrepancies. Therefore, the staff

concluded that the applicant had adequately identified the Unit 1 SSCs within the scope of

license renewal, as required by 10 CFR 54.4 (a), and the SSCs that are subject to an AMR, as

required by 10 CFR 54.21(a)(1). 

2.6.1.13 Reactor Water Cleanup System

Description. BFN has selected an option in the RWCU System Program that allows the

applicant not to test system piping outboard of the outboard primary containment isolation valve

provided that the following actions are completed:

 • The RWCU piping outside the outboard primary containment isolation valves will be

replaced with IGSCC-resistant piping

 • The actions requested in GL 89-10 SR Motor-Operated Valve Testing and Surveillance,

will be satisfactorily completed for the RWCU system; and, in addition, the RWCU

system will be reconfigured so that the pumps are no longer exposed to a high

temperature environment, consistent with Units 2 and 3.

The applicant committed to replace the 4-inch and larger, stainless steel, RWCU piping located

outside the drywell prior to the restart of Unit 1. The applicant also committed to develop and

implement a comprehensive Motor-operated Valve Testing and Surveillance Program for Unit 1,

satisfying the intent of GL 89-10. At the time of its restart, the Unit 1 RWCU system will have

been reconfigured so that the pumps are no longer exposed to a high-temperature

environment.

Difference Resolution. The differences between the CLB for Unit 1 and the CLB for Units 2 and

3 will be resolved prior to Unit 1 restart by performing the actions described above. Once these

actions have been implemented, there will be no operational differences between the Unit 1

RWCU system and the Units 2 and 3 systems. 

UFSAR Impact. The Unit 1 system and AMP impacted by this modification and their LRA

sections:

 • reactor water cleanup (2.3.3.21)

 • Reactor Water Cleanup System Program (B.2.1.22)

Following resolution of this item, the license renewal results shown with a bold-bordered box in

the LRA sections identified above will be applicable to Unit 1.

Schedule for Completion. The Unit 1 modification is scheduled for completion prior to restart

and is currently projected to be complete by July 2006.

The applicant will have completed the above commitments prior to Unit 1 restart since the

piping has been removed and the system is being reconfigured as described above. Other
2-245

license conditions will not allow the applicant to enter the period of extended operation without

implementing this modification

Staff Evaluation. Prior to the restart of Unit 1, the applicant will have completed replacement of

the RWCU system piping outside the outboard primary containment isolation valves, and

completed implementation of its GL 89-10 program, such that the Unit 1 differences identified in

the application in this regard are no longer applicable.

In its submittal dated January 31, 2005, the applicant forcasted that this modification will be

completed by July 2006. This commitment will be tracked through a temporary instruction

TI-2509-01 as a part of the license application verification that this commitment will be

completed prior to Unit 1 restart. Other license conditions will not permit the applicant to enter

the period of extended operation without implementing this modification.

Conclusion. During its review of the information provided in the LRA, license renewal drawings,

and licensing-basis information, the staff did not identify any omissions or discrepancies in the

applicant's scoping and screening results for the structures and components because of the

reactor water cleanup system modification. The scoping and screening reviews were done

based on the CLB. The differences between the units' CLBs that are relevant to the application

will be resolved prior to Unit 1 restart. The Unit 1 systems and structures impacted by this

modification, and their LRA sections and tables as indicated in the list above, were evaluated

elsewhere in the SER, and the staff did not identify any omissions or discrepancies. Therefore,

the staff concluded that the applicant had adequately identified the Unit 1 SSCs within the

scope of license renewal, as required by 10 CFR 54.4 (a), and the SSCs that are subject to an

AMR, as required by 10 CFR 54.21(a)(1). 

2.6.2 Staff Evaluation

The staff evaluation of LRA Appendix F items used the methodology described in SER

Section 2.6.1 to determine whether these items had been adequately scoped and screened.

The staff did not perform any safety review of any of these modifications, but performed a

limited disposition of the resolution activities for each of the LRA Appendix F items that will be

completed prior to Unit 1 restart. As stipulated and agreed upon with the staff in its

pre-application meetings, the applicant provided in its submittal dated January 31, 2005,

“Additional Information Concerning the Integration of Unit 1 Restart and License Renewal

Activities,” a status update on completion of the restart activities that impact the CLB of Unit 1.

The SER with OI presents the latest information on these modifications. Accordingly, the staff

found that the disposition and validation of the modifications were consistent with the

commitments. The staff will track modifications and implementation details of these items via

separate LRA inspections prior to Unit 1 restart to confirm implementation. 

In reviewing the technical information provided in LRA Appendix F, the staff review was limited

to verifying:

 (i) The sufficiency of information provided by the applicant for the 13 items that

impacted the LRA review. 

(ii) The applicability of the 13 items to Unit 1.
2-246

(iii) The systems these 13 items impact.

(iv) The plan to resolve differences between the CLB for Unit 1 and the CLB for

Units 2 and 3, so that upon restart all units will have the same CLB. 

It should be noted that in the LRA the restart activities listed in LRA Appendix F were generally

referred to as differences in the design basis or licensing basis. Based on the definition of CLB

in 10 CFR 54.3, these activities are more precisely described as implementation activities of the

design and licensing basis. Even though each of the 13 activities listed in LRA Appendix F is

committed to and planned for completion prior to Unit 1 restart, any unimplemented

commitments would remain valid, part of the CLB, carry over into the renewed license period,

and be controlled by the NRC regulatory and oversight process.

The staff's evaluation of the information provided in the LRA was performed in the same

manner for all mechanical, civil, and electrical systems as it relates to the particular item in

question. 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 being within the scope of license renewal.

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).

2.6.3 Conclusion

The restart plan ensures compliance with the applicant’s commitments made during the

shutdown and with regulatory requirements that changed during the extended shutdown. In

addition, a license condition will be imposed as part of LRA review that will require the Unit 1

restart activities, described in LRA Appendix F, to be completed prior to Unit 1 restart.

Therefore, while implementation of the 13 items identified in LRA Appendix F is not yet

complete, the staff found that this will not be a barrier to staff approval of license renewal for

Unit 1. This type of approval has not been made for commitments in prior LRAs approved by

the staff. Therefore, there are no staff evaluations or staff findings performed for these 13 LRA

Appendix F items, except for restating the technical information provided in the LRA and the

January 31, 2005, letter, in the format described below and a status update on the physical

implementation of these Unit 1 restart activities.

During its review of the information provided in LRA Appendix F, the staff did not identify any

omissions or discrepancies in the applicant’s integration of Unit 1 restart activities with license

renewal activities. Therefore, the staff concluded that, pending satisfactory implementation of

the activities identified in LRA Appendix F prior to Unit 1 restart, the applicant had adequately

identified the Unit 1 systems, structures, and components that will be within the scope of license

renewal, as required by 10 CFR 54.4(a), and the Unit 1 structures and components that will be

subject to an AMR, as required by 10 CFR 54.21(a)(1). Satisfactory completion of these actions

prior to Unit 1 restart will be a condition of the renewed license.
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2.7 Conclusion for Scoping and Screening

The staff reviewed the information in LRA Section 2, “Scoping and Screening Methodology for

Identifying Structures and Components Subject to Aging Management Review and

Implementation and Results.” The staff determined that the applicant's scoping and screening

methodology, including its supplement 10 CFR 54.4(a)(2) review which brought additional NSR

piping segments and associated components into the scope of license renewal, was consistent

with the requirements of 10 CFR 54.21(a)(1) and the staff's position on the treatment of SR and

NSR SSCs within the scope of license renewal and the structures and components requiring an

AMR is consistent with the requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1).

On the basis of its review, the staff concluded that the applicant had adequately identified those

systems and components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and 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 concluded that there is reasonable assurance that the

activities authorized by the renewed license can continue to be conducted in accordance with

the CLB, and any changes made to the BFN CLB, in order to comply with 10 CFR 54.29(a), are

in accord with the Act and the Commission's regulations.
THIS PAGE IS INTENTIONALLY LEFT BLANK
3-1

 SECTION 3

AGING MANAGEMENT REVIEW RESULTS

This section of the safety evaluation report (SER) contains the staff’s evaluation of the

applicant’s AMPs (AMPs) and aging management reviews (AMRs). In License Renewal

Application (LRA) Appendix B, the applicant described the 39 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 Aging Lessons Learned Report

In preparing its LRA, Tennessee Valley Authority (TVA, the applicant) credited U.S. Nuclear

Regulatory Commission Regulatory Guide (NUREG)-1801, “Generic Aging Lessons Learned

[GALL] Report,” dated July 2001. The GALL Report contains the Nuclear Regulatory

Commission’s (NRC or the staff’s) generic evaluation of the existing plant programs, and it

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 a license renewal application

to demonstrate that the programs at its facility correspond to those reviewed and approved in

the GALL 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 based on this process. The results of

the demonstration project confirmed that the GALL process will improve the efficiency and
3-2

effectiveness of the LRA review, while maintaining the staff’s focus on public health and safety.

NUREG-1800, “Standard Review Plan for the Review of License Renewal Applications,”

(SRP-LR), dated April 2001, was prepared based on both the GALL Report model and lessons

learned from the demonstration project.

The staff performed its 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,” and the guidance provided in the SRP-LR and the GALL

Report.

The staff performed onsite audits at the applicant’s offices in Chattanooga, TN, during the

weeks of June 25 and July 19, 2004, and additional technical reviews of the applicant’s AMPs

and AMRs. The objective of the audits and reviews was to verify that the effects of aging on

structures and components will be adequately managed so that their intended functions will be

maintained consistent with the plant’s current licensing basis (CLB) for the period of extended

operation, as required by 10 CFR 54, “Requirements for Renewal of Operating Licenses for

Nuclear Power Plants.” Detailed results of the staff’s onsite audits are documented in “Audit

Report for Plant AMPs and Aging Management Reviews - Browns Ferry Nuclear Plant Units 1,

2, and 3,” dated April 26, 2005.

3.0.1 Format of the License Renewal Application

TVA submitted an application that followed the standard LRA format, as agreed to between the

NRC staff and the Nuclear Energy Institute (NEI) (see letter dated April 7, 2003,

ML030990052). This revised LRA format incorporates lessons learned from the staff’s reviews

of the previous five LRAs. These previous LRAs used a format developed from information

gained during an NRC staff and NEI demonstration project that was conducted to evaluate the

use of the GALL Report in the staff’s review process.

The organization of LRA Section 3 parallels Chapter 3 of the SRP-LR. The AMR results

information in LRA Section 3 is presented in the following two table types:

 • Table 1: Table 3.x.1 – where “3” indicates the LRA section number, “x” indicates the

subsection number from the GALL Report, and “1” indicates that this is the first table

type in LRA Section 3.

 • Table 2: Table 3.x.2-y – where “3” indicates the LRA section number, “x” indicates the

subsection number from the GALL Report, “2” indicates that this is the second table type

in LRA Section 3, and “y” indicates the system table number.

The content of the previous applications and the Browns Ferry Nuclear Plant (BFN) application

is essentially the same. The intent of the revised format used for the BFN application was to

modify the tables in Chapter 3 to provide additional information that would assist the staff in its

review. In Table 1, TVA summarized the portions of the application that it considered to be

consistent with the GALL Report. In Table 2, TVA identified the linkage between the scoping

and screening results in Chapter 2 and the AMRs in Chapter 3.
3-3

3.0.1.1 Overview of Table 1

Table 3.x.1 (Table 1) provides a summary comparison of how the facility aligns with the

corresponding tables of the GALL Report, Volume 1. The table is essentially the same as

Tables 1 through 6 provided in the GALL Report, Volume 1, except that the “Type” column has

been replaced by an “Item Number” column and the “Item Number in GALL” column has been

replaced by a “Discussion” column. The “Item Number” column provides the reviewer with a

means to cross-reference from Table 2 to Table 1. The “Discussion” column is used by the

applicant to provide clarifying and 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 assumptions

 • a discussion of how the line is consistent with the corresponding line item in the GALL

Report when this may not be intuitively obvious

 • a discussion of how the item is different than the corresponding line item in the GALL

Report (e.g., when there is exception taken to an AMP that is listed in the GALL Report)

The format of Table 1 allows the staff to align a specific Table 1 row with the corresponding

GALL Report, Volume 1, table row so that the consistency can be easily checked.

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, etc.). 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 all of the component types from Section 2

of the LRA that are subject to AMR. They are listed in alphabetical order.

 2. Intended Function - The second column contains the license renewal intended functions

(using abbreviations where necessary) for the listed component types. Definitions and

abbreviations of passive component type intended functions are presented in

Table 2.0.1, Intended Function Abbreviations and Definitions.

 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, as appropriate.

Descriptions of the internal and external service environments that were used in the

AMR to determine aging effects requiring management are included in Table 3.0.1,

Internal Service Environments, and Table 3.0.2, External Service Environments.
3-4

 5. Aging Effect Requiring Management (AERM) - 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. AMPs - The AMPs used to manage the aging effects requiring management are listed in

column six of Table 2.

 7. GALL Volume 2 Item - Each combination of component type, material, environment,

AERM, and AMP that is listed in Table 2 is compared to the GALL Report, Volume 2

with consideration given to the standard notes, to identify consistencies. When they are

identified, they are documented by noting the appropriate GALL Report, Volume 2 item

number in column seven of Table 2. If there is no corresponding item number in the

GALL Report, Volume 2, this row in column seven has "None." That way, a reviewer can

readily identify where there is correspondence between the plant-specific tables and the

GALL Report, Volume 2 tables.

 8. Table 1 Item - Each combination of component, material, environment, AERM, and AMP

that has an identified NUREG-1801 Volume 2 item number must also have a Table 3.x.1

line item reference number. The corresponding line item from Table 1 is listed in column

eight of Table 2. If there is no corresponding item in the GALL Report, Volume 1, this

row in column eight has "None." That way, the information from the two tables can be

correlated.

 9. Notes - In order to realize the full benefit of the GALL Report, BFN has aligned the

information in the Tables 3.x.2.y with the information in NUREG-1801 Volume 2 using a

series of notes. Notes that utilize letter designations are industry-standard notes taken

from the Proposed Standard License Renewal Application Format Package (Letter from

Alexander Marion (NEI) to Dr. P. T. Kuo (NRC), Project Number: 690, dated August 20,

2003). Notes that use numeric designations are BFN plant-specific notes.

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 the applicant states are consistent with the GALL Report, the staff conducted

an audit.

 2. For items the applicant states are consistent with the GALL Report with exceptions, the

staff conducted an audit of the item and of the applicant’s technical justification for the

exceptions.

 3. For items that are not consistent with the GALL Report, the staff conducted a technical

review.

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 the AMPs 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
3-5

(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 Program - Scope of the program should include the specific structures and

components subject to an AMR for license renewal.

 2. Preventive Actions - Preventive actions should prevent or mitigate aging degradation.

 3. Parameters Monitored or Inspected - Parameters monitored or inspected should be

linked to the degradation of the particular structure or component intended functions(s).

 4. Detection of Aging Effects - Detection of aging effects should occur before there is a

loss of structure or component intended functions(s). This includes aspects such as

method or technique (i.e., visual, volumetric, surface inspection), frequency, sample

size, data collection, and timing of new/one-time inspections to ensure a timely detection

of aging effects.

 5. Monitoring and Trending - Monitoring and trending should provide predictability of the

extent of degradation, as well as timely corrective or mitigative actions.

 6. Acceptance Criteria - Acceptance criteria, against which the need for corrective action

will be evaluated, should ensure that the structure or component intended function(s)

are maintained under all CLB design conditions during the period of extended operation.

 7. Corrective Actions - Corrective actions, including root cause determination and

prevention of recurrence, should be timely.

 8. Confirmation Process - Confirmation process should ensure that preventive actions are

adequate and that appropriate corrective actions have been completed and are

effective.

 9. Administrative Controls - Administrative controls should provide 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 structure and component 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

the BFN audit and review report and are summarized in SER Section 3.0.3.

The staff reviewed the applicant’s Corrective Action Program and documented its evaluations in

SER Section 3.0.4. The staff’s evaluation of the Corrective Action Program included

assessment of the following program elements: (7) corrective actions, (8) confirmation process,

and (9) administrative controls.

The staff reviewed the information concerning the (10) operating experience program elements

and documented its evaluation in the BFN audit and review report. The staff also included a

summary of the program in SER Section 3.0.3.
3-6

The staff reviewed the updated final safety analysis report (UFSAR) supplement for each AMP

to determine if it provided an adequate description of the program or activity, as required by

10 CFR 54.21(d).

3.0.2.2 Review of AMR Results

Table 2 of the LRA contains information concerning whether or not the AMRs align with the

AMRs identified in the GALL Report. For a given AMR in Table 2, the NRC staff reviewed the

combination of intended function, material, environment, AERM, and AMP for a particular

component type within a system. The Table 2 AMRs that correlate with an AMR in the GALL

Report are identified by a reference item number in column seven, “GALL, Volume 2 Item.” The

eighth column, “Table 1 Item,” provides a reference number that indicates the corresponding

row in Table 1.

The staff conducted an audit to verify the appropriateness of the applicant’s AMR correlations

to the GALL Report. A blank column seven indicates that the applicant was unable to locate an

appropriate corresponding AMR in the GALL Report. The staff conducted a technical review of

those Table 2 AMRs that are not consistent with the GALL Report.

3.0.2.3 UFSAR Supplement

Consistent with the SRP-LR, for the AMRs and associated AMPs that it reviewed, the staff also

reviewed the UFSAR supplement that summarizes the applicant’s programs and activities for

managing the effects of aging for the period of extended operation, as required by

10 CFR 54.21(d).

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 BFN audit and review report, to verify that the applicant’s activities and programs will

adequately manage the effects of aging on SCs. The staff also conducted detailed discussions

and interviews with the applicant’s license renewal project personnel and others with technical

expertise relevant to aging management.

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 with which the applicant claimed its AMP was

consistent (if applicable) and the SSCs that credit the AMP for managing or monitoring aging.

The section of the SER, in which the staff’s evaluation of the program is documented, is also

provided.
3-7

Table 3.0.3-1 BFN’s Aging Management Programs

BFN's AMP

(LRA Section)

GALL

Comparison

GALL

AMP(s)

LRA Systems or Structures

That Credit the AMP

Staff's

SER Section

Existing AMPs

Electrical Cables Not

Subject to

10 CFR 50.49

Environmental

Qualification

Requirements Used in

Instrumentation

Circuits Program

(B.2.1.2)

Not consistent -

exceptions taken

XI.E2 Electrical and

instrumentation and controls

3.0.3.2.1

ASME Code Section XI

Subsections IWB,

IWC, and IWD

Inservice Inspection

Program

(B.2.1.4)

Consistent XI.M1 Reactor vessel, internals,

and reactor coolant system;

containments, structures,

and component supports;

engineered safety features

systems; auxiliary systems;

steam and power conversion

systems

3.0.3.1.3

Chemistry Control

Program

(B.2.1.5)

Not consistent -

exceptions and

enhancements

taken

XI.M2 Reactor vessel, internals,

and reactor coolant system;

engineered safety features

systems; auxiliary systems;

steam and power conversion

systems; containments,

structures, and component

supports

3.0.3.2.2

Reactor Head Closure

Studs Program

(B.2.1.6)

Consistent XI.M3 Reactor vessel, internals,

and reactor coolant system 

3.0.3.1.4

Boiling Water Reactor

Vessel Inside Diameter

Attachment Welds

Program

(B.2.1.7)

Consistent with

enhancements

XI.M4 Reactor vessel, internals,

and reactor coolant systems

3.0.3.2.3

Boiling Water Reactor

Feedwater Nozzle

Program

(B.2.1.8)

Consistent with

enhancements

XI.M5 Reactor vessel, internals,

and reactor coolant systems

3.0.3.2.4

Boiling Water Reactor

Control Rod Drive

Return Line Nozzle

Program

(B.2.1.9)

Consistent XI.M6 Reactor vessel, internals,

and reactor coolant systems

3.0.3.1.5
BFN's AMP

(LRA Section)

GALL

Comparison

GALL

AMP(s)

LRA Systems or Structures

That Credit the AMP

Staff's

SER Section

3-8

Boiling Water Reactor

Stress Corrosion

Cracking Program

(B.2.1.10)

Consistent with

enhancements

XI.M7 Reactor vessel, internals,

and reactor coolant systems;

engineered safety features;

auxiliary systems; steam and

power conversion system

3.0.3.2.5

Boiling Water Reactor

Penetrations Program

(B.2.1.11)

Consistent with

enhancements

XI.M8 Reactor vessel, internals,

and reactor coolant systems

3.0.3.2.6

Boiling Water Reactor

Vessel Internals

Program

(B.2.1.12)

Consistent with

enhancements

XI.M9 Reactor vessel, internals,

and rector coolant systems

3.0.3.2.7

Thermal Aging and

Neutron Irradiation

Embrittlement of Cast

Austenitic Stainless

Steel Program

(B.2.1.14)

N/A XI.M13 N/A 3.0.3.2.8

Flow-Accelerated

Corrosion Program

(B.2.1.15)

Consistent with

enhancements

XI.M17 Steam and power conversion

systems; engineered safety

features systems

3.0.3.2.9

Bolting Integrity

Program

(B.2.1.16)

Not consistent -

exceptions taken

XI.M18 Reactor vessel, internals,

and reactor coolant systems;

engineered safety features

systems; auxiliary systems;

steam and power conversion

systems

3.0.3.2.10

Open-Cycle Cooling

Water Program

(B.2.1.17)

Consistent with

enhancements

XI.M20 Auxiliary systems 3.0.3.2.11

Closed-Cycle Cooling

Water System Program

(B.2.1.18)

Consistent with

enhancements

XI.M21 Auxiliary systems 3.0.3.2.12

Inspection of Overhead

Heavy Load and Light

Load Handling

Systems Program

(B.2.1.20)

Not consistent -

exceptions taken

XI.M23 Auxiliary systems 3.0.3.2.13

Compressed Air

Monitoring Program

(B.2.1.21)

Consistent with

enhancements

XI.M24 Auxiliary systems; steam and

power conversion systems

3.0.3.2.14

BWR Reactor Water

Cleanup System

Program

(B.2.1.22)

Consistent with

enhancements

XI.M25 Auxiliary systems 3.0.3.2.15
BFN's AMP

(LRA Section)

GALL

Comparison

GALL

AMP(s)

LRA Systems or Structures

That Credit the AMP

Staff's

SER Section

3-9

Fire Protection

Program

(B.2.1.23)

Not consistent -

exceptions and

enhancements

taken

XI.M26 Auxiliary systems;

containments, structures,

and component supports

3.0.3.2.16

Fire Water System

Program

(B.2.1.24)

Not consistent -

exceptions and

enhancements

taken

XI.M27 Auxiliary systems 3.0.3.2.17

Aboveground Carbon

Steel Tanks Program

(B.2.1.26)

Consistent XI.M29 Steam and power conversion

systems

3.0.3.1.6

Fuel Oil Chemistry

Program

(B.2.1.27)

Not consistent -

exceptions and

enhancements

taken

XI.M30 Auxiliary systems 3.0.3.2.18

Reactor Vessel

Surveillance Program

(B.2.1.28)

Consistent with

enhancements

XI.M31 Reactor vessel, internals,

and reactor coolant system

3.0.3.2.19

Buried Piping and

Tanks Inspection

Program

(B.2.1.31)

Consistent XI.M34 Engineered safety feature

systems; auxiliary systems

3.0.3.1.9

ASME Code Section XI

Subsection IWE

Program

(B.2.1.32)

Not consistent -

exceptions and

enhancement

taken

XI.S1 Containments, structures,

and component supports

3.0.3.2.20

ASME Code Section XI

Subsection IWF

Program

(B.2.1.33)

Consistent (letter

dated January 18

and 24, 2005)

XI.S3 Containments, structures,

and component supports

3.0.3.2.21

10 CFR 50 Appendix J

Program

(B.2.1.34)

Consistent XI.S4 Containments, structures,

and component supports

3.0.3.1.10

Masonry Wall Program

(B.2.1.35)

Consistent with

enhancements

XI.S5 Containments, structures,

and component supports

3.0.3.2.22

Structures Monitoring

Program

(B.2.1.36)

Consistent with

enhancements

XI.S6 Containments, structures,

and component supports

3.0.3.2.23

Inspection of

Water-Control

Structures Program

(B.2.1.37)

Consistent with

enhancements

XI.S7 Containments, structures,

and component supports

3.0.3.2.24
BFN's AMP

(LRA Section)

GALL

Comparison

GALL

AMP(s)

LRA Systems or Structures

That Credit the AMP

Staff's

SER Section

3-10

Systems Monitoring

Program

(B.2.1.39)

Plant-specific N/A Reactor coolant systems;

engineered safety features

systems; auxiliary systems;

steam and power conversion

systems

3.0.3.3.1

Diesel Starting Air

Program

(B.2.1.41)

Plant-specific N/A Auxiliary systems 3.0.3.3.3

Environmental

Qualification Program

(B.3.1)

Consistent with

enhancements

X.E1 Electrical and

instrumentation and controls

3.0.3.2.25

Fatigue Monitoring

Program

(B.3.2)

Consistent with

enhancements

X.M1 Reactor vessel, internals,

and reactor coolant systems;

containment, structures, and

component supports

3.0.3.2.26

New AMPs

Accessible

Non-Environmental

Qualification Cables

and Connections

Inspection Program

(B.2.1.1)

Consistent XI.E1 Electrical and

instrumentation and controls

3.0.3.1.1

Inaccessible Medium

Voltage Cables Not

Subject to

10 CFR 50.49

Environmental

Qualification

Requirements Program

(B.2.1.3)

Consistent XI.E3 Electrical and

instrumentation and controls

3.0.3.1.2

Thermal Aging

Embrittlement of Cast

Austenitic Stainless

Steel Program

(B.2.1.13)

N/A Main steam line

flow-restricting venturis

3.0.3.3.4

One-Time Inspection

Program

(B.2.1.29)

Consistent XI.M32 Reactor vessel, internals,

and reactor coolant systems;

engineered safety feature

systems; auxiliary systems;

steam and power conversion

systems; containment,

structures and component

supports

3.0.3.1.7

Selective Leaching of

Materials Program

(B.2.1.30)

Consistent XI.M33 Engineered safety feature

systems; auxiliary systems;

steam and power conversion

systems

3.0.3.1.8
BFN's AMP

(LRA Section)

GALL

Comparison

GALL

AMP(s)

LRA Systems or Structures

That Credit the AMP

Staff's

SER Section

3-11

Bus Inspection

Program

(B.2.1.40)

Plant-specific N/A 3.0.3.3.2

Unit 1 Periodic

Inspection Program

(B.2.1.42)

Plant-specific N/A Un-replaced, un-refurbished

piping and components for

Unit 1 only 

3.0.3.3.5

3.0.3.1 AMPs That Are Consistent with the GALL Report, for Which Further Evaluation is

Not Recommended

In LRA Appendix B, the applicant identified that the following AMPs were consistent with the

GALL Report:

 • Accessible Non-Environmental Qualification Cables and Connections Inspection

Program (B.2.1.1)

 • Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental

Qualification Requirements Program (B.2.1.3)

 • ASME Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program

(B.2.1.4)

 • Reactor Head Closure Studs Program (B.2.1.6)

 • Boiling Water Reactor Control Rod Drive Return Line Nozzle Program (B.2.1.9)

 • Aboveground Carbon Steel Tanks Program (B.2.1.26)

 • One-Time Inspection Program (B.2.1.29)

 • Selective Leaching of Materials Program (B.2.1.30)

 • Buried Piping and Tanks Inspection Program (B.2.1.31)

 • 10 CFR 50 Appendix J Program (B.2.1.34)

During its audit and review, conducted June 21 to 25, 2004, the staff confirmed the applicant's

claim of consistency with the GALL Report. As a result of this review, the staff identified issues

for several of the AMPs that were resolved with a docketed response from the applicant. Those

issues and resolutions are discussed in Sections 3.0.3.1.1 to 3.0.3.1.10, below.

3.0.3.1.1 Accessible Non-Environmental Qualification Cables and Connections Inspection

Program

Summary of Technical Information in the Application. The applicant’s Accessible

Non-Environmental Qualification (Non-EQ) Cables and Connections Inspection Program is

described in LRA Section B.2.1.1, “Accessible Non-Environmental Qualification Cables and

Connections Inspection Program.” In the LRA, the applicant stated that this is a new program

that will be initiated prior to the period of extended operation. This commitment is identified on
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the applicant’s license renewal commitment list as Item No. 1. This program is consistent with

GALL AMP XI.E1, “Electrical Cables and Connections Not Subject to 10 CFR 50.49

Environmental Qualification Requirements.”

Staff Evaluation. During its audit and review, the staff confirmed the applicant’s claim of

consistency with the GALL Report. Details of the staff’s evaluation of this AMP are documented

in the BFN audit and review report. The staff determined that this AMP is consistent with the

AMP described in the GALL Report, including the associated operating experience attribute.

As a result of this review, the staff identified two issues discussed below that were resolved with

a docketed response from the applicant. 

 1. GALL AMP XI.E1 recommends that the program be written specifically to address

cables and connections at plants whose configuration is such that most (if not all) cables

and connections installed in adverse localized environments are accessible. However,

the applicant’s description of the Accessible Non-EQ Cables and Connections

Inspection Program does not address the percentage of cables in adverse localized

environments at BFN that are accessible.

The applicant stated, as documented in the staff’s audit and review report that, based

upon a search of as designed data in the current cable routing database, greater than

50 percent of cables are located in accessible cable trays. 

The staff found the applicant’s response acceptable since more than 50 percent of the

cables will be accessible for inspection, which is consistent with the recommendations

for GALL AMP XI.E1.

 2. The description of GALL AMP XI.E1 states that the technical basis for the sample of

cables and connections selected for inspection is to be provided. However, the staff

noted that the description of the Accessible Non-EQ Cables and Connections Inspection

Program in the LRA does not address the rationale for selecting the sample of cables

and connections to be inspected.

In its response to the request for additional information (RAI) 3.6-6, dated December 9,

2004, the applicant stated that the scope of the program will include a representative

sample of accessible, insulated cables and connections within the scope of license

renewal will be visually inspected in adverse localized environments as identified by a

review of operating experience. The sample will include cables in raceways located in

the drywell that are qualified to the IEEE 383-1974 flame test and not coated with

Flamemastic. Selected cables and connections from accessible areas (the inspection

sample) will represent, with reasonable assurance, all cables and connections in

adverse localized environments.

Operating Experience: The applicant stated in the LRA that the Accessible Non-EQ Cables and

Connections Inspection Program is a new program for which there is no operating experience.

The operating experience data associated with implementing this program will be addressed in

the applicant's Corrective Action Program. In evaluating the element, the applicant stated that

the implementation of the Accessible Non-EQ Cables and Connections Inspection Program will

provide reasonable assurance that the applicable aging effects will be effectively managed so

that the structures and components within the scope of this program will continue to perform

their intended functions consistent with the CLB for the period of extended operation.
3-13

UFSAR Supplement. In LRA Section A.1.1, the applicant provided the UFSAR supplement for

the Accessible Non-EQ Cables and Connections Inspection Program. The staff reviewed this

section and determined that the information in the UFSAR supplement provides an adequate

summary description of the program. The staff found this section of the UFSAR supplement

sufficient, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant's program, the staff determined

that those program elements for which the applicant claimed consistency with the GALL Report

are consistent with the GALL Report. The staff concluded that the applicant had demonstrated

that the effects of aging will be adequately managed so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and

concluded that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.0.3.1.2 Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental

Qualification Requirements Program

Summary of Technical Information in the Application. The applicant’s Inaccessible Medium

Voltage Cables Not Subject to 10 CFR 50.49 EQ Requirements Program is described in LRA

Section B.2.1.3, “Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49

Environmental Qualification Requirements Program.” In the LRA, the applicant stated that this

is a new program that will be initiated prior to the period of extended operation. This program is

consistent with GALL AMP XI.E3, “Inaccessible Medium Voltage Cables Not Subject to

10 CFR 50.49 Environmental Qualification Requirements.”

The applicant stated that the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49

EQ Requirements Program will manage the aging effects of inaccessible medium-voltage

cables that are not subject to the EQ requirements of 10 CFR 50.49 and are exposed to

adverse localized environments caused by moisture while energized. The applicant also stated

that the specific type of test performed will be determined prior to the initial test and will be a

proven test for detecting deterioration of the insulation system due to wetting. The test will be

as described in Electric Power Research Institute (EPRI) TR-103834-P1-2 or will be a test that

is state-of-the-art at the time of program implementation.

The Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental

Qualification Requirements Program is a condition monitoring program in which medium

voltage cables that are installed in underground conduit duct banks and that perform an

intended function within the scope of license renewal (such as the medium voltage cables to the

residual heat removal service water (RHRSW) pumps) will be tested to provide an indication of

the condition of the conductor insulation. The specific type of test performed will be determined

prior to the initial test and will be a proven test for detecting deterioration of the

insulation system due to wetting.

Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information

included in LRA Section B.2.1.3, regarding the applicant’s demonstration of the Inaccessible

Medium Voltage Cables Not Subject to 10 CFR 50.49 EQ Requirements Program to ensure

that the effects of aging, as discussed above, will be adequately managed so that the intended
3-14

functions will be maintained consistent with the CLB throughout the period of extended

operation. 

The staff’s review of LRA Section B.2.1.3 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. 

In RAI 3.6-3, dated November 4, 2004, the staff stated it reviewed the Inaccessible Medium

Voltage Cables Not Subject to 10 CFR 50.49 EQ Requirements Program credited for managing

the effects for non-EQ inaccessible medium voltage cables. Therefore, staff requested the

applicant to provide (1) a list of cables that are covered under this program, (2) any plant and/or

industry operating experience regarding the water-treeing phenomenon or any anticipated

decrease in the dielectric strength of the conductor insulation, and (3) a description of the 10

elements of the proposed AMP.

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 Program - In its response to the staff RAI 3.6-3 as above and by letter dated

December 9, 2004, the applicant stated that medium voltage cables that are installed in

underground conduit duct banks and that perform an in-scope intended function (such

as the medium voltage cables to RHRSW pumps) will also be included in this program.

The staff finds the above response to be acceptable since the Non-EQ Inaccessible

Medium voltage Cable Program will require testing of all in-scope cables included in the

program.

 2. Preventive Actions - Periodic actions, such as inspecting for water collection in cable

manholes and conduit, and draining water, as needed, will be taken to prevent cables

from being exposed to significant moisture. These actions will be performed as part of

the testing described in Parameters Monitored or Inspected. The staff finds that the

inspection of water collection in cable manholes and conduit at a ten year frequency is

not adequate. The staff indicated that the frequency of inspection for water collection in

cable manholes and conduit should be yearly. The staff asked the applicant to explain

why every ten years inspection is sufficient. On January 18, 2005, the applicant stated

that inspection for water collection for in-scope cable manholes and conduits will be

adjusted to be performed annually. Based on the above, the staff's concern is resolved.

 3. Parameters Monitored or Inspected - This program will test those inaccessible medium

voltage cables identified as in scope to determine the condition of the conductor

insulation by testing the cables. The specific type of test performed will be determined

prior to the initial test, and is to be a proven test for detecting deterioration of the

insulation system, such as power factor, partial discharge, or polarization index, as

described in EPRI TR-103834-P1-2, or other testing that is state-of-art at the time. The

staff finds this to be acceptable since this is consistent with the GALL XI.E3 program.

 4. Detection of Aging Effects - Affected cables will be tested before the current 40-year

licensing term has concluded for each unit and at least once every 10 years thereafter.

The staff finds this to be acceptable since this is consistent with the GALL XI.E3

program.
3-15

 5. Monitoring and Trending - Trending actions are not included as part of this program

because the ability to trend test results is dependent on the specific type of test chosen.

Test results that are trendable may be trended to provide additional information on the

rate of degradation. The staff finds this to be acceptable since this is consistent with

GALL XI.E3 program.

 6. Acceptance Criteria - During testing, cables shall meet the acceptance criteria of the

test being performed. The staff finds this to be acceptable since this is consistent with

the GALL XI.E3 program.

 7. Operating Experience - Industry operating experience was incorporated into the license

renewal process through a review of industry documents to identify aging effects and

mechanisms that could challenge the intended function of components within the scope

of this program. Review of plant-specific operating experience was also performed to

identify aging effects experienced. This review involved electronic database searches of

plant information including problem evaluation reports (PERs), staff communications,

RAIs, and work orders (WOs). As a result of the search, the following documents were

reviewed with no new aging effects identified: Information Notice (IN) 86-49, RIS

2000-25, and RAIs 1554 through 1558 (Peach Bottom Units 1 and 2). 

On the basis of its review of the above operating experience, the staff concluded that the

applicant's program for Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 EQ

Requirements Program adequately manages the aging effects that have been observed at the

applicant's plant. Therefore, the staff’s concern described in RAI 3.6-3 is resolved.

UFSAR Supplement. In LRA Section A.1.3, and subsequent LRA supplements, the applicant

provided the UFSAR supplement for the applicant's program for Inaccessible Medium Voltage

Cables Not Subject to 10 CFR 50.49 EQ Requirements Program. The staff reviewed this

section and determined that the information in the UFSAR supplement provides an adequate

summary description of the program. The staff found that this section of the UFSAR

supplement met the requirements of 10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant's program and RAI response,

the staff determined that those program elements for which the applicant claimed consistency

with the GALL Report are consistent with the GALL Report. The staff concluded that the

applicant had demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement

for this AMP and concluded that it provides an adequate summary description of the program,

as required by 10 CFR 54.21(d).

3.0.3.1.3 ASME Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program

Summary of Technical Information in the Application. The applicant’s American Society of

Mechanical Engineers (ASME) Code Section XI Subsections IWB, IWC, and IWD Inservice

Inspection Program is described in LRA Section B.2.1.4, “ASME Section XI Subsections IWB,

IWC, and IWD Inservice Inspection Program.” In the LRA, the applicant stated that this is an
3-16

existing program. This program is consistent with GALL AMP XI.M1, “ASME Section XI

Inservice Inspection, Subsections IWB, IWC, and IWD.”

In the LRA, the applicant stated that the ASME Code Section XI Subsections IWB, IWC, and

IWD Inservice Inspection Program includes periodic visual, surface, and/or volumetric

examination of Class 1, 2, and 3 pressure-retaining components and their integral attachments.

Requirements for ASME Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection

Program are mandated by the BFN Technical Requirements Manual 3.4.3, “Structural Integrity.”

Section 50.55a of 10 CFR imposes the inservice inspection requirements of the ASME Code

Section XI for Class 1, 2, and 3 pressure-retaining components and their integral attachments

in light-water-cooled power plants. 

Staff Evaluation. During its audit and review, the staff confirmed the applicant’s claim of

consistency with the GALL Report. Details of the staff’s evaluation of this AMP are documented

in the BFN audit and review report. The staff determined that this AMP is consistent with the

AMP described in the GALL Report, including the associated operating experience attribute.

Based on its review, the staff concluded that the applicant's ASME Code Section XI

Subsections IWB, IWC, and IWD Inservice Inspection Program provides reasonable assurance

of aging management. As a result of this review, the staff identified two issues discussed below

that were resolved with a docketed response from the applicant.

 1. The staff noted that ASME Code Section XI Subsections IWB, IWC, and IWD Inservice

Inspection Program did not indicate what the IWB, IWC, and IWD commitment will be

for Unit 1 restart baseline inspections, after restart, and during the extended period of

operation.

The applicant stated, as documented in the staff’s audit and review report, that the

re-baseline inspection scope includes all inspections required during a typical 10-year

inspection interval for Class 1, 2, and 3 components that have not been repaired or

replaced. The code of record for Unit 1 recovery is the 1995 Edition with Addenda

through 1996 of ASME Code Section XI. Following restart, the current (suspended)

inservice inspection (ISI) interval will be completed. The next inspection interval will

meet the requirements of 10 CFR 50.55(a) at that time. For the period of extended

operation, the Code edition will be consistent with 10 CFR 50.55(a) requirements for all

three units.

The staff found the applicant’s response acceptable on the basis that all three units will

be consistent with the GALL Report during the extended period of operation and the

Unit 1 re-baseline program will provide reasonable assurance that the condition of Unit 1

piping and components is comparable to that of Units 2 and 3.

 2. In LRA Section B.2.1.4, the applicant stated that currently approved relief requests and

approved code cases are used. The staff noted that these are not applicable to the

period of extended operation and asked the applicant to confirm that the commitment to

implement the requirements of 10 CFR 50.55(a) for license renewal is not modified by

the current relief requests or implementation of currently approved code cases.

The applicant stated, as documented in the staff’s audit and review report, that the

commitment to implement the requirements of 10 CFR 50.55(a) for license renewal is

not modified by the current relief requests or implementation of currently approved Code
3-17

cases; that there are currently no relief requests that extend past the 40-year period;

and, that relief requests that extend into the period of license renewal will be in

accordance with 10 CFR 50.55(a).

The staff found the applicant’s response acceptable on the basis that current approved

relief requests and code cases will not in any way modify the applicant’s commitment to

implement 10 CFR 50.55a during the period of extended operation.

Operating Experience. The ASME Code Section XI Subsections IWB, IWC, and IWD Inservice

Inspection Program in accordance with Subsections IWB, IWC, or IWD has been shown to be

generally effective in managing aging effects in Class 1, 2, or 3 components and their integral

attachments. 

The applicant successfully identified indications of age-related degradation prior to the loss of

the functions of the components, and has taken appropriate corrective actions through

evaluation, repair, or replacement of the components in accordance with ASME Section XI and

station implementing procedures.

UFSAR Supplement. In LRA Section A.1.4, the applicant provided the UFSAR supplement for

the ASME Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program.

The staff reviewed this section and determined that the information in the UFSAR supplement

provides an adequate summary description of the program. The staff found that this section of

the UFSAR supplement met the requirements of 10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant's program, the staff determined

that those program elements for which the applicant claimed consistency with the GALL Report

are consistent with the GALL Report. The staff concluded that the applicant had demonstrated

that the effects of aging will be adequately managed so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and

concluded that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.0.3.1.4 Reactor Head Closure Studs Program

Summary of Technical Information in the Application. The applicant’s Reactor Head Closure

Studs Program is described in LRA Section B.2.1.6, “Reactor Head Closure Studs Program.” In

the LRA, the applicant stated that this is an existing program. This program is consistent with

GALL AMP XI.M3, “Reactor Head Closure Studs Program.”

In the LRA, the applicant stated that the Reactor Head Closure Studs Program includes (1)

inservice inspection in conformance with the requirements of the ASME Code Section XI

Subsection IWB, Table IWB 2500-1 (B.2.1.4), and (2) preventive measures to mitigate

cracking. The applicant stated that (1) the preventive measures of regulatory guide (RG) 1.65,

"Materials and Inspections for Reactor Vessel Closure Studs," have been implemented, and (2)

approved lubricants minimize the potential for cracking of the non-metal-plated reactor head

closure studs.
3-18

Staff Evaluation. During its audit and review, the staff confirmed the applicant’s claim of

consistency with the GALL Report. Details of the staff’s evaluation of this AMP are documented

in the BFN audit and review report. The staff determined that this AMP is consistent with the

AMP described in the GALL Report, including the associated operating experience attribute.

Operating Experience. In LRA Section B.2.1.6, the applicant evaluated the program element

operating experience and stated that stress corrosion cracking (SCC) has occurred in boiling

water reactor (BWR) reactor head closure studs, particularly metal-plated studs. The approved

lubricants used have proven to be effective in preventing seized studs or nuts. The reactor head

closure studs are not metal plated. With the lack of metal plating and preventive use of

approved lubricants, the Reactor Head Closure Studs Program has been effective in reducing

the probability of SCC of the reactor head closure studs.

UFSAR Supplement. In LRA Section A.1.6, the applicant provided the UFSAR supplement for

the Reactor Head Closure Studs Program. The staff reviewed this section and determined that

the information in the UFSAR supplement provides an adequate summary description of the

program. The staff found that this section of the UFSAR supplement met the requirements of

10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant's program, the staff determined

that those program elements for which the applicant claimed consistency with the GALL Report

are consistent with the GALL Report. The staff concluded that the applicant had demonstrated

that the effects of aging will be adequately managed so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and

concluded that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.0.3.1.5 Boiling Water Reactor Control Rod Drive Return Line Nozzle Program

Summary of Technical Information in the Application. The applicant’s BWR Control Rod Drive

Return Line Nozzle Program is described in LRA Section B.2.1.9, “Boiling Water Reactor

Control Rod Drive Return Line Nozzle Program.” In the LRA, the applicant stated that this is an

existing program. This program is consistent with GALL AMP XI.M6, “BWR Control Rod Drive

Return Line Nozzle.”

In the LRA, the applicant stated that the BWR Control Rod Drive Return Line Nozzle Program

includes (1) an inservice inspection in accordance with the ASME Code Section XI

Subsection IWB. This inspection requirement is implemented by the ASME Code Section XI

Subsections IWB, IWC, and IWD Inservice Inspection Program, and (2) system modifications to

mitigate cracking. The CRD return lines have been modified to meet the recommendations of

NUREG-0619, ”BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking.”

The applicant stated that the CRD return lines now return to the reactor water cleanup system

piping, the CRD return line reactor vessel nozzle piping has been removed, and the reactor

vessel nozzles have been capped.

Staff Evaluation. During its audit and review, the staff confirmed the applicant’s claim of

consistency with the GALL Report. Details of the staff’s evaluation of this AMP are documented

in the BFN audit and review report. The staff determined that this AMP is consistent with the
3-19

AMP described in the GALL Report, except for the staff issue described below that was

resolved with a docketed response from the applicant.

The staff questioned why Units 2 and 3 perform an enhanced visual test (EVT)-1 of the inner

radius instead of the Code-specified volumetric exam. The applicant stated, as documented in

the staff’s audit and review report, that the nozzle-to-vessel weld and inner radius are inspected

in accordance with ASME Code Section XI, ISI Program, Subsection IWB, Category B-D

requirements. Units 2 and 3 perform an EVT-1 of the inner radius instead of the Code-specified

volumetric exam, as approved by Requests for Relief 2-ISI-16 and 3-ISI-14. The applicant

indicated that an ultrasonic (UT) exam of both the nozzle-to-vessel weld and the inner radius is

currently performed for Unit 1. Relief requests will not extend into the period of extended

operation. The staff found the applicant’s response regarding the current inspections performed

for all three BFN units acceptable. 

In the LRA, the applicant stated that system modifications to mitigate cracking are in progress.

The CRD return lines have been modified to meet the recommendations of NUREG-0619,

“BWR Feedwater Nozzle and Control Rod Drive (CRD) Return Line Nozzle Cracking.” The CRD

return lines now return to the reactor water cleanup system piping. The CRD return line reactor

vessel nozzle piping has been removed, and the reactor vessel nozzles have been capped. The

staff noted that the capped CRD return line nozzles are not subject to cyclic loads from thermal

stratification and striping. Therefore, they are not susceptible to cracking due to cyclic loading

and do not impact AMR review. The staff found the evaluation acceptable.

Based on its review, the staff concluded that the applicant's Boiling Water Reactor Control Rod

Drive Return Line Nozzle Program provides reasonable assurance of management of inservice

inspection and implementation of preventive measures to mitigate cracking. The staff found this

AMP acceptable. It conforms to the recommended program description, program elements, and

acceptance criteria for the Boraflex monitoring program, as discussed in GALL AMP XI.M6,

"BWR Control Rod Drive Return Line Nozzle Program."

Operating Experience. After implementation of the recommendations of NUREG-0619, BFN

has operated for over twenty years with no significant CRD return line reactor vessel nozzle

issues. The plant-specific operating experience and staff evaluation are shown in SER

Section 3.1.2.3.10.

UFSAR Supplement. In LRA Section A.1.9, the applicant provided the UFSAR supplement for

the BWR Control Rod Drive Return Line Nozzle Program. The staff reviewed this section and

determined that the information in the UFSAR supplement provides an adequate summary

description of the program. The staff found that this section of the UFSAR supplement met the

requirements of 10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant's program, the staff determined

that those program elements for which the applicant claimed consistency with the GALL Report

are consistent with the GALL Report. The staff concluded that the applicant had demonstrated

that the effects of aging will be adequately managed so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and

concluded that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).
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3.0.3.1.6 Aboveground Carbon Steel Tanks Program

Summary of Technical Information in the Application. The applicant’s Aboveground Carbon

Steel Tanks Program is described in LRA Section B.2.1.26, “Aboveground Carbon Steel Tanks

Program.” In the LRA, the applicant stated that this is an existing program. This program is

consistent with GALL AMP XI.M29, “Aboveground Carbon Steel Tanks Program.”

In the LRA, the applicant stated that the program includes preventive measures to mitigate

corrosion by protecting the external surface of carbon steel tanks with paint or coatings in

accordance with standard industry practice. The flat-bottomed condensate storage tanks sit on

beds of compacted sulfur-free oiled sand. The applicant also stated that it condition monitors for

degradation by performing periodic inspections in accordance with the 10 CFR 50.65

Maintenance Rule Program. The applicant stated that activities to ensure that significant

degradation in inaccessible tank bottoms is not occurring by performing a one-time inspection.

A one-time inspection, in accordance with the One-Time Inspection Program (B.2.1.29), will be

performed prior to entering the period of extended operation and will consist of thickness

measurements of flat-bottomed tanks’ bottom surface.

Staff Evaluation. During its audit and review, the staff confirmed the applicant’s claim of

consistency with the GALL Report. Details of the staff’s evaluation of this AMP are documented

in the BFN audit and review report. The staff determined that this AMP is consistent with the

AMP described in the GALL Report, except for the staff issue described below in subsection

“UFSAR Supplement” that was resolved with a docketed response from the applicant. 

Operating Experience. Some external corrosion problems have been reported on carbon steel

tanks. Corrective actions have been implemented prior to loss of intended function.

UFSAR Supplement. In LRA Section A.1.23, the applicant provided the UFSAR supplement for

the Aboveground Carbon Steel Tanks Program. The staff reviewed this section and determined

that the information in the UFSAR supplement does not identify a one-time inspection in

accordance with the One-Time Inspection Program to take thickness measurements of

flat-bottomed tanks’ bottom surface prior to entering the period of extended operation. This is

identified as an element of the program in LRA Section B.2.1.26. Therefore, the staff could not

confirm that the UFSAR supplement provides an adequate summary description of the

program, as identified in the SRP-LR UFSAR supplement table, and as required by

10 CFR 54.21(d). The staff requested that the applicant provide additional information to

resolve this issue. The staff followed this request for additional information in a follow up call

with the applicant on April 7, 2005.

In its response, by letter May 25, 2005, the applicant confirmed the following, which resolves

the staff issue:

The One-Time Inspection Program (B.2.1.29) has been revised to specifically identify

ultrasonic thickness measurements of the fuel oil storage tank bottom surfaces to

ensure that significant degradation is not occurring. To implement this change, the

“Program Description” section of LRA Appendix B.2.1.29, One-Time Inspection

Program, has been revised to include the following item: “thickness measurements of

tank bottoms to ensure that significant degradation is not occurring for those tanks
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specified in the Fuel Oil Chemistry Program (B.2.1.27) and the Aboveground Carbon

Steel Tanks Program (B.2.1.26).” The staff considers the issue resolved.

Conclusion. On the basis of its review and audit of the applicant's program, and the RAI

response that those program elements for which the applicant claimed consistency with the

GALL Report are consistent with the GALL Report, the staff concluded that the applicant

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP

and concluded that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.0.3.1.7 One-Time Inspection Program

Summary of Technical Information in the Application. The applicant’s One-Time Inspection

Program is described in LRA Section B.2.1.29, “One-Time Inspection Program.” In the LRA, the

applicant stated that this is a new program. This program is consistent with GALL AMP XI.M32,

“One-Time Inspection.”

In the LRA, the applicant stated that the One-Time Inspection Program will include measures to

verify that unacceptable degradation of any reactor system component 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.

LRA Section B.2.1.29 states that the elements of the One-Time Inspection Program will include:

 • Determination of the sample size based on an assessment of materials of fabrication,

environment, plausible aging effects, and operating experience.

 • Identification of the inspection locations in the SSCs based on the aging effect.

 • Determination of the examination technique, including acceptance criteria that would be

effective in managing the aging effect for which the component is examined.

Nondestructive techniques will generally be used; however, in some circumstances

(e.g.,small bore RCPB), destructive testing will be utilized if samples become available.

 • Evaluation of the need for follow-up examinations to monitor the progression of any

aging degradation. When one-time inspections fail to meet the established acceptance

criteria, the Corrective Action Program will be used to schedule, track, and trend

appropriate corrective actions and follow-up inspections.

LRA Section B.2.1.29 states that the One-Time Inspection Program will include the one-time

inspections of SSCs that are identified generally in LRA Chapter 3.0 and in an AMR, such as:

 • reactor coolant pressure boundary piping, valves, tubing, restricting orifices, and fittings

less than 4-inch nominal pipe size (NPS 4) exposed to reactor coolant for loss of

material and cracking

 • ventilation duct work for loss of material and elastomer degradation/deterioration
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 • flexible connections for loss of material, cracking, and elastomer

degradation/deterioration

 • heat exchangers for loss of material, cracking, and biofouling 

 • various fittings, piping, valves, pumps, strainers, tanks, traps, tubing, expansion joints,

fan housings, fire dampers, and heaters for loss of material cracking, and biofouling.

The One-Time Inspection Program will be completed before the end of the current operating

license term. The schedule of the inspection will be completed in a way that minimizes its

impact on plant operations; however, the inspection will not be scheduled so early in the current

operating license term that will preclude questions on potential aging effects that may surface at

the end of the current licensing period.

The applicant, in evaluating the AMP, stated that implementation of the One-Time Inspection

Program will provide reasonable assurance that the aging effects will be managed so that the

systems and components within the scope of this program will continue to perform their

intended functions consistent with the CLB for the period of extended operation.

Staff Evaluation. During its audit and review, the staff confirmed the applicant’s claim of

consistency with the GALL Report. Details of the staff’s evaluation of this AMP are documented

in the BFN audit and review report. The staff determined that this AMP is consistent with the

AMP described in the GALL Report, including the associated operating experience attribute.

Operating Experience. The One-Time Inspection Program is new. Therefore, no programmatic

operating experience is available.

UFSAR Supplement. In LRA Section A.1.26, the applicant provided the UFSAR supplement for

the One-Time Inspection Program. The staff reviewed this section and determined that the

information in the UFSAR supplement provides an adequate summary description of the

program. The staff found that this section of the UFSAR supplement met the requirements of

10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant's program, the staff determined

that those program elements for which the applicant claimed consistency with the GALL Report

are consistent with the GALL Report. The staff concluded that the applicant had demonstrated

that the effects of aging will be adequately managed so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and

concluded that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.0.3.1.8 Selective Leaching of Materials Program

Summary of Technical Information in the Application. The applicant’s Selective Leaching of

Materials Program is described in LRA Section B.2.1.30, “Selective Leaching of Materials

Program.” In the LRA, the applicant stated that this is a new program. This program is

consistent with GALL AMP XI.M33, “Selective Leaching of Materials.”
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The Selective Leaching of Materials Program consists of visual inspections and hardness

measurements on selected components susceptible to selective leaching. The materials of

construction for these components may include cast iron, brass, bronze, or aluminum bronze.

These components may be exposed to a raw water, treated water, or ground water

environment. The Selective Leaching of Materials Program will perform one-time visual

inspections and hardness measurements of representative components from those

components identified in this LRA’s AMR results. The Selective Leaching of Materials Program

will be completed prior to entering the period of extended operation. The selection, inspection,

and measurement techniques will be consistent with industry practice at the time of

implementation.

Staff Evaluation. During its audit and review, the staff confirmed the applicant’s claim of

consistency with the GALL Report. Details of the staff’s evaluation of this AMP are documented

in the BFN audit and review report. The staff determined that this AMP is consistent with the

AMP described in the GALL Report, including the associated operating experience attribute.

Operating Experience. In the LRA Section B.2.1.30 the applicant evaluated the program

element operating experience and stated that the Selective Leaching of Materials Program is a

new program. No operating experience is available.

UFSAR Supplement. In LRA Section A.1.27, the applicant provided the UFSAR supplement for

the Selective Leaching of Materials Program. The staff reviewed this section and determined

that the information in the UFSAR supplement provides an adequate summary description of

the program. The staff found this section of the UFSAR supplement met the requirements of

10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant's program, the staff determined

that those program elements for which the applicant claimed consistency with the GALL Report

are consistent with the GALL Report. The staff concluded that the applicant had demonstrated

that the effects of aging will be adequately managed so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and

concluded that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.0.3.1.9 Buried Piping and Tanks Inspection Program

Summary of Technical Information in the Application. The applicant’s Buried Piping and Tanks

Inspection Program is described in LRA Section B.2.1.31, “Buried Piping and Tanks Inspection

Program.” In the LRA, the applicant stated that this is an existing program. This program is

consistent with GALL AMP XI.M34, “Buried Pipes and Tanks Inspection.”

There are no buried tanks identified within the scope of license renewal. The Buried Piping and

Tanks Inspection Program includes (1) preventive measures to mitigate corrosion by applying

external coatings and wrappings in accordance with standard industry practices, and (2)

condition monitoring to manage the effects of corrosion. The applicant stated that buried piping

is inspected when excavated for any reason, typically for maintenance. The inspections are

performed as part of the 10 CFR 50.65 Maintenance Rule Program. The inspections provide for
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determination of degradation due to the loss of, or damage to, the protective coatings and

wraps used for corrosion control on buried pipe external surfaces. The inspections also include

connections and joints for signs of separation, signs of environmental degradation, signs of

leakage, and appreciable settlement between piping segments.

Staff Evaluation. During its audit and review, the staff confirmed the applicant’s claim of

consistency with the GALL Report. Details of the staff’s evaluation of this AMP are documented

in the BFN audit and review report. The staff determined that this AMP is consistent with the

AMP described in the GALL Report, except for the staff issue, described below, that concerned

inspection of buried piping and that was resolved with a docketed response from the applicant. 

The staff noted that the applicant relied solely on opportunistic inspections to check buried

piping. If there were not any opportunistic inspections, the buried pipe would not be inspected.

Therefore, the staff requested that the applicant agree to inspect the buried piping within 10

years after entering the period of extended operation, unless conclusive opportunistic

inspections that provide a representative sample have occurred within this 10-year period.

Before the tenth year, BFN should perform an engineering evaluation to determine if sufficient

inspections have been conducted to draw a conclusion regarding the ability of the underground

coatings to protect the underground piping systems from degradation. If it is found that

sufficient inspections have not occurred to draw a conclusion regarding the underground

coatings, BFN should conduct a focused inspection to allow that conclusion to be reached. The

staff followed this request for additional information in a follow up call with the applicant on

April 7, 2005.

In its response dated May 25, 2005, the applicant clarified the staff issue as follows:

Buried piping within the scope of the Buried Piping and Tanks Program will be inspected

when they are excavated for maintenance or when those components are exposed for

any reason. BFN will perform an inspection of buried piping within ten years after

entering the period of extended operation, unless an opportunistic inspection has

occurred within this ten-year period. Before the tenth year, BFN will perform an

engineering evaluation to determine if sufficient inspections have been conducted to

draw a conclusion regarding the ability of the underground coatings to protect the

underground piping from degradation. If not, BFN will conduct a focused inspection to

allow that conclusion to be reached. Sections A.1.28 and B.2.1.31 are modified as

described below to implement this change: Paragraph (b) of LRA Appendix A.1.28,

Buried Piping and Tanks Inspection Program, and paragraph (b) of the “Program

Description” section of Appendix B.2.1.31, Buried Piping and Tanks Inspection Program

have been revised to include the following statement: “Before the tenth year of extended

operation, BFN will perform an engineering evaluation to determine if sufficient

inspections have been conducted to draw a conclusion regarding the ability of the

underground coatings to protect the underground piping from degradation. If not, BFN

will conduct a focused inspection to allow that conclusion to be reached.

Operating Experience. Review of the operating experience identified no concerns relating to the

corrosion of external surfaces of buried piping or components. Several instances of buried

piping replacement were identified resulting from internal corrosion or microbiological fouling or

degradation. There are no buried tanks that are within the scope of license renewal.
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UFSAR Supplement. In LRA Section A.1.28, the applicant provided the UFSAR supplement for

the Buried Piping and Tanks Inspection Program. The staff reviewed this section and

determined that the information in the UFSAR supplement provides an adequate summary

description of the program. The staff found this section of the UFSAR supplement net the

requirements of 10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant's program, the staff determined

that those program elements for which the applicant claimed consistency with the GALL Report

are consistent with the GALL Report. The staff concluded that the applicant had demonstrated

that the effects of aging will be adequately managed so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and

concluded that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d). 

3.0.3.1.10 10 CFR 50 Appendix J Program

Summary of Technical Information in the Application. The applicant’s 10 CFR 50 Appendix J

Program is described in LRA Section B.2.1.34, “10 CFR 50 Appendix J Program.” In the LRA,

the applicant stated that this is an existing program. This program is consistent with GALL AMP

XI.S4, “10 CFR Part 50, Appendix J.”

The 10 CFR 50 Appendix J Program monitors leakage rates through the containment pressure

boundary (including the drywell and torus, penetrations, fittings, and other access openings) in

order to detect degradation of the primary containment pressure boundary. Seals, gaskets, and

bolted connections are also monitored. Type A and Type B containment leak-rate tests are

performed in accordance with the regulations in 10 CFR 50 Appendix J Option B; and the

guidance provided in RG 1.163, “Performance-Based Containment Leak-Testing Program”;

NEI 94-01, “Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50

Appendix J.” The 10 CFR 50 Appendix J Program requirements are mandated by Technical

Specification (TS) 5.5.12, Primary Containment Leakage Rate Testing Program. Additional

requirements for testing the containment are mandated by the following TS surveillance

requirements: SR 3.6.1.1.1, SR 3.6.1.2.1, SR 3.6.1.3.10, and SR 3.6.1.3.11.

Staff Evaluation. During its audit and review, the staff confirmed the applicant’s claim of

consistency with the GALL Report. Details of the staff’s evaluation of this AMP are documented

in the BFN audit and review report. The staff determined that this AMP is consistent with the

AMP described in the GALL Report, including the associated operating experience attribute.

Operating Experience. In LRA Section B.2.1.34, the applicant evaluated the program element

operating experience and stated that testing in accordance with 10 CFR 50 Appendix J has

been effective in monitoring the pressure integrity of the primary containment boundaries

industry-wide and at BFN. The staff concurred with the applicant’s evaluation. 

UFSAR Supplement. In LRA Section A.1.31, the applicant provided the UFSAR supplement for

the 10 CFR 50 Appendix J Program. The staff reviewed this section and determined that the

information in the UFSAR supplement provides an adequate summary description of the

program. The staff found this section of the UFSAR supplement met the requirements of

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 determined

that those program elements for which the applicant claimed consistency with the GALL Report

are consistent with the GALL Report. The staff concluded that the applicant had demonstrated

that the effects of aging will be adequately managed so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and

concluded that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.0.3.2 AMPs That Are Consistent with the GALL Report with Exceptions or

Enhancements

In LRA Appendix B, the applicant identified that the following AMPs were, or will be, consistent

with the GALL Report, with exceptions or enhancements:

 • Electrical Cables Not Subject to 10 CFR 50.49 Environmental Qualification

Requirements Used in Instrumentation Circuits Program (B.2.1.2)

 • Chemistry Control Program (B.2.1.5)

 • Boiling Water Reactor Vessel Inside Diameter Attachment Welds Program (B.2.1.7)

 • Boiling Water Reactor Feedwater Nozzle Program (B.2.1.8)

 • Boiling Water Reactor Stress Corrosion Cracking Program (B.2.1.10)

 • Boiling Water Reactor Penetrations Program (B.2.1.11)

 • Boiling Water Reactor Vessel Internals Program (B.2.1.12)

 • Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel

Program (B.2.1.14)

 • Flow-accelerated Corrosion Program (B.2.1.15)

 • Bolting Integrity Program (B.2.1.16)

 • Open-cycle Cooling Water System Program (B.2.1.17)

 • Closed-cycle Cooling Water System Program (B.2.1.18)

 • Inspection of Overhead Heavy Load and Light Load Handling Systems Program

(B.2.1.20)

 • Compressed Air Monitoring Program (B.2.1.21)

 • BWR Reactor Water Cleanup System Program (B.2.1.22)

 • Fire Protection Program (B.2.1.23)

 • Fire Water System Program (B.2.1.24)

 • Fuel Oil Chemistry Program (B.2.1.27)

 • Reactor Vessel Surveillance Program (B.2.1.28)

 • ASME Section XI Subsection IWE Program (B.2.1.32)
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 • ASME Section XI Subsection IWF Program (B.2.1.33)

 • Masonry Wall Program (B.2.1.35)

 • Structures Monitoring Program (B.2.1.36)

 • Inspection of Water-control Structures Program (B.2.1.37)

 • Environmental Qualification Program (B.3.1)

 • Fatigue Monitoring Program (B.3.2)

For AMPs that the applicant claimed are consistent with the GALL Report, with exceptions or

enhancements, the staff performed an audit to confirm that those programs were indeed

consistent. The staff also reviewed the exceptions and enhancements to the GALL Report to

determine whether they were acceptable and adequate. The results of the staff’s audit and

reviews are documented in the following sections.

3.0.3.2.1 Electrical Cables Not Subject to 10 CFR 50.49 Environmental Qualification

Requirements Used in Instrumentation Circuits Program

Summary of Technical Information in the Application. The applicant’s Electrical Cables Not

Subject to 10 CFR 50.49 EQ Requirements Used in Instrumentation Circuits Program is

described in LRA Section B.2.1.2, “Electrical Cables Not Subject to 10 CFR 50.49

Environmental Qualification Requirements Used in Instrumentation Circuits Program.” In the

LRA, the applicant stated that this is an existing program. This program is consistent, with

exception, with GALL AMP XI.E2, “Electrical Cables Not Subject to 10 CFR 50.49

Environmental Qualification Requirements Used in Instrumentation Circuits.”

In the LRA, the applicant stated that the Electrical Cables Not Subject to 10 CFR 50.49 EQ

Requirements Used in Instrumentation Circuits Program will provide reasonable assurance that

the intended functions of the neutron monitoring local power range monitor (LPRM) circuits

exposed to adverse, localized environments caused by heat, radiation, and moisture can be

maintained consistent with the CLB through the period of extended operation.

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

BFN audit and review report. Furthermore, the staff reviewed the exceptions and their

justifications to determine whether the AMP, with exceptions, remains adequate to manage the

aging effects for which it is credited.

The staff reviewed the program elements (see SER Section 3.0.2.1) contained in the AMP

bases documents against GALL AMP XI.E2 for consistency. 

The staff noted that the LRA credits the EQ Program for managing aging effects for radiation

monitoring system cables within the scope of license renewal. The EQ Program covers certain

electrical components that are important to safety and could be exposed to harsh environment

accident conditions. Since portions of the radiation monitoring cables are not exposed to a

harsh environment, the staff inquired in RAI 2.5-2, below, whether all radiation monitoring

cables within the scope of license renewal, located both inside and outside the containment, are

covered by the EQ Program. The applicant stated, as documented in the staff’s audit and
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review report, that all high-range radiation monitoring cables are included in the EQ Program,

regardless of their location, in mild or harsh areas of the plant. The staff found the applicant’s

response acceptable on the basis that all of the high-range radiation monitoring cables are

included in the EQ Program.

The staff’s review of LRA Section B.2.1.2 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.

During the audit, the staff also noted that the applicant’s AMP is limited to managing the

neutron monitoring local power range monitoring circuits. Not included in the scope of Electrical

Cables Not Subject to 10 CFR 50.49 EQ Requirements Used in Instrumentation Circuits

Program are nuclear instrumentation cables used in circuits for the SRM, intermediate range

monitor (IRM), average power range monitor (APRM), rod block monitor (RBM), and traversing

in-core probe (TIP). The staff considers the IRM system to be safety-related (SR) at all BWRs

and the IRM is part of the plant’s TSs. The staff pursued this issue with the applicant and

requested additional clarifications in RAI 2.5-2, see SER Section 2.5.1.2

Based on its response and additional discussions with the staff, the applicant concurred that the

IRM instrumentation circuit cables should be within the scope of license renewal because they

are part of the TS. Because of this inclusion, the applicant confirmed that their aging effects

should be managed by the Electrical Cables Not Subject to 10 CFR 50.49 EQ Requirements

Used in Instrumentation Circuits Program. The applicant also agreed that other accessible

neutron monitoring subsystem cables and connections will be managed by the Accessible

Non-EQ Cables and Connections Inspection Program. This inclusion impacts the scope of the

two AMP elements "Program Description" and "NUREG-1801 Consistency.” These changes

have been added to the SER Appendix A commitment table, and the applicant will modify the

UFSAR supplement to reflect these changes. The details of the staff evaluation on RAI 2.5-2

are shown in SER Section 2.5.1.2.

In LRA Section B.2.1.2, the applicant stated an exception to GALL AMP XI.E2. The staff

evaluation of the affected GALL elements (Parameters Monitored/Inspected and Detection of

Aging Effects) for the acceptability of the exception is as follows:

Exception - In LRA Section B.2.1.2, the applicant takes an exception to GALL AMP XI.E2 and

states that it performs a calibration procedure that implements TS requirements. The procedure

is not a normal loop calibration. The procedure utilizes actual detector signals during normal

operation for calibration inputs. This exception impacts the following program elements, which

are evaluated as follows.

Parameters Monitored/Inspected (Element 3) - The parameters monitored are determined from

the plant TSs and are specific to the instrumentation loop being calibrated, as documented in

the surveillance test procedure. The applicant in evaluating the element stated that this program

will monitor parameters that are required by TSs and are specific to the LPRM cable system

being calibrated. 

This program will monitor parameters that are required by TSs and are specific to the LPRM

cable system being calibrated. In evaluating the exception regarding Parameters

Monitored/Inspected, the applicant stated, as documented in the staff’s audit and review report,
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that the applicant performs a specific calibration procedure as determined from plant TSs on

LPRM circuits. The applicant stated that cables are part of the calibration procedure since the

detector is in service when the calibration is performed. In this program, review of routine

calibration results by appropriate personnel provide sufficient indication of the need for

corrective actions by monitoring key parameters related to LPRM cable system performance.

The normal calibration frequency specified in BFN TSs provides reasonable assurance that

severe aging degradation will be detected prior to loss of the cable intended function.

The staff found that this exception acceptable in that it will not adversely impact the ability of the

AMP to manage the affects of aging since the only difference between the applicant’s program

and GALL AMP XI.E2 is that the applicant utilizes actual detector signals during operation to

calibrate the LPRM. The parameters monitored in the applicant’s program are determined from

the plant TSs and, therefore, the staff found this exception to be acceptable for the program

element.

Detection of Aging Effects (Element 4) - 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. The normal calibration

frequency specified in the plant TSs provides reasonable assurance that severe aging

degradation will be detected prior to loss of the cable intended function. The first tests for

license renewal are to be completed before the period of extended operation.

In evaluating the exception regarding Detection of Aging Effects, the applicant stated that

routine calibration results will provide adequate and timely indication of the need for corrective

actions by monitoring key parameters related to LPRM cable system performance. The normal

calibration frequency specified in TSs provides reasonable assurance that severe aging

degradation will be detected prior to loss of the cable intended function. Calibrations will

continue through the period of extended operation at the required frequency as specified in the

TSs.

As discussed above, in response to the staff’s inquiry regarding the difference between the

applicant’s calibration procedure and that specified in GALL AMP XI.E2, the applicant stated

that it performs a specific calibration procedure as determined from plant TSs on LPRM circuits.

The normal calibration frequency specified in BFN TSs provides reasonable assurance that

severe aging degradation will be detected prior to loss of the cable intended function.

The staff found that this exception will not adversely impact the ability of this AMP to manage

the effects of aging since the only difference between the applicant’s program and GALL

AMP XI.E2 is that the applicant utilizes actual detector signals during operation to calibrate the

LPRM and does not perform a loop calibration. The normal calibration frequency specified in

the plant TSs provides reasonable assurance that severe aging degradation will be detected

prior to loss of the cable intended function, and the first tests for license renewal will be

completed before the period of extended operation. Therefore, the staff found this exception to

be acceptable.

Operating Experience. In LRA Section B.2.1.2, the applicant stated that industry operating

experience was incorporated into the license renewal process through a review of industry

documents to identify aging effects and mechanisms that could challenge the intended function

of components, systems and structures within the scope of this program. Review of

plant-specific operating experience was also performed to identify aging effects experienced.
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This review involved electronic database searches of plant information including problem

evaluation reports, staff communications, RAIs, and WOs. As a result, no new aging effects

were identified.

During the concurred audit, the staff noted that the applicant incorporates internal and external

plant operating experience issues into the plant Corrective Action Program on a continuing

basis. The staff concluded there is reasonable assurance that operating experience will

continue to be reviewed in the future to ensure that the effects of aging will be adequately

managed.

UFSAR Supplement. In LRA Section A.1.2, the applicant provided the UFSAR supplement for

the Electrical Cables Not Subject to 10 CFR 50.49 EQ Requirements Used in Instrumentation

Circuits Program. The staff reviewed this section and determined that the information in the

UFSAR supplement provides an adequate summary description of the program. The staff found

this section of the UFSAR supplement met the requirements of 10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant’s program, the staff determined

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 exception and the

associated justifications and determined that the AMP, with the exception, is adequate to

manage the aging effects for which it is credited. The staff concluded that the applicant had

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP

and concluded that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.0.3.2.2 Chemistry Control Program

Summary of Technical Information in the Application. The applicant’s Chemistry Control

Program is described in LRA Section B.2.1.5, “Chemistry Control Program.” In the LRA, the

applicant stated that this is an existing program. This program is consistent, with exceptions

and an enhancement, with GALL AMP XI.M2, “Water Chemistry.”

The purpose of the Chemistry Control Program is to minimize loss of material due to general,

crevice, and pitting corrosion and crack initiation and growth caused by SCC. This objective is

achieved by periodic monitoring, control and mitigation of known detrimental contaminants in

order to ensure that their concentrations remain below the levels known to result in corrosion

and stress corrosion crack initiation and growth. The monitoring is consistent with the EPRI

guidelines for BWR reactor water chemistry, condensate and feedwater, cooling water for

CRDs, and other systems such as spent fuel pool water. In addition, the applicant has

established an AMP consistent with GALL AMP XI.M2 “Water Chemistry.”

Staff Evaluation. During its audit and review, the staff confirmed the applicant’s claim of

consistency with the GALL Report. The staff reviewed the two exceptions and one

enhancement and the applicant’s justifications to determine whether the AMP, with the

exceptions and enhancement, remains adequate to manage the aging effects for which it is

credited as follows.
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Exception 1. In LRA Appendix B, the applicant stated that the GALL Report recommends that

water chemistry be controlled in accordance with Boiling Water Reactor Vessel Internals Project

(BWRVIP)-29. BWRVIP-29 references the 1993 revision of EPRI Report TR-103515, "BWR

Water Chemistry Guidelines.” The Chemistry Control Program is based on BWRVIP-79 EPRI

Report TR-103515-R2, which is the 2000 Revision of "BWR Water Chemistry Guidelines.”

This exception affects the program element, “Scope of Program,” (Element 1) which is

described as follows:

The program includes periodic monitoring and control of known detrimental

contaminants such as chlorides, fluorides (Pressurized Water Reactors (PWRs) only),

dissolved oxygen, and sulfate concentrations below the levels known to result in loss of

material or crack initiation and growth. Water chemistry control is in accordance with the

guidelines in BWRVIP-29 (EPRI TR-103515) for water chemistry in BWRs; EPRI

TR-105714, Rev. 3, for primary water chemistry in pressurized water reactors (PWRs);

EPRI TR-102134, Rev. 3, for secondary water chemistry in PWRs; or later revisions or

updates of these reports as approved by the staff. 

The applicant evaluated the exception applicable to the program element. The applicant stated

that EPRI periodically updates the water chemistry guidelines, as new information becomes

available. EPRI TR-103515-R2 incorporates new information to develop proactive plant-specific

water chemistry programs to minimize intergranular stress corrosion cracking (IGSCC). In the

“License Renewal Safety Evaluation Report for the Peach Bottom Atomic Power Station,

Units 2 and 3” (ML030370189), the staff found EPRI TR-103515-R2 acceptable because the

program is based on updated industry experience and plant-specific and industry-wide

operating experience confirms the effectiveness of the reactor coolant system (RCS) chemistry

program. The BFN units are similar to the Peach Bottom units. Therefore the staff conclusion

reached for Peach Bottom is applicable to BFN.

In evaluating the exception, the staff stated that the difference between the two revisions is due

to the 2000 revision representing a more up-to-date program. It incorporates new information,

which forms the basis of the proactive, plant-specific water chemistry procedures, which will

minimize IGSCC and will provide information on water chemistry that was not available when

the 1993 revision was developed. In the description of the scope of the program, the GALL

Report states that revisions or updates of the currently existing reports are acceptable as

approved by the staff. This applies to the 2000 revision, which was approved previously by the

staff for one of the license renewal plants; therefore, the staff finds that using the 2000 revision

of the EPRI BWR Water Chemistry Guidelines instead of the earlier 1993 revision will not

negatively impact the 10 elements of the applicant’s Chemistry Control Program described in

the LRA. 

Exception 2. In LRA Appendix B, the applicant stated that the GALL Report indicates that

hydrogen peroxide is monitored to mitigate degradation of structural materials. The applicant

takes an exception that the Chemistry Control Program does not monitor for hydrogen peroxide

because the rapid decomposition of hydrogen peroxide makes reliable data exceptionally

difficult to obtain and EPRI TR-103515-R2 Section 4.3.3, "Water Chemistry Guidelines for

Power Operation," does not address monitoring for hydrogen peroxide.
3-32

This exception affects the program elements, “Parameters Monitored or Inspected” (Element 3)

and “Confirmation Process,” (Element 8), which are described as follows:

Parameters Monitored - The concentration of corrosive impurities listed in the EPRI

guidelines discussed above, which include chlorides, fluorides (PWRs only), sulfates,

dissolved oxygen, and hydrogen peroxide, are monitored to mitigate degradation of

structural materials. Water quality (pH and conductivity) is also maintained in

accordance with the guidance. Chemical species and water quality are monitored by in

process methods or through sampling. The chemistry integrity of the samples is

maintained and verified to ensure that the method of sampling and storage will not

cause a change in the concentration of the chemical species in the samples. The

guidelines in BWRVIP-29 (EPRI TR-103515) for BWR reactor water recommend that

the concentration of chlorides, sulfates, and dissolved oxygen are monitored and kept

below the recommended levels to mitigate corrosion. The two impurities, chlorides and

sulfates, determine the coolant conductivity; dissolved oxygen, hydrogen peroxide, and

hydrogen determine electrochemical potential (ECP). The EPRI guidelines recommend

that the coolant conductivity and ECP are also monitored and kept below the

recommended levels to mitigate SCC and corrosion in BWR plants. The EPRI

guidelines in BWRVIP-29 (TR-103515) for BWR feedwater, condensate, and control rod

drive water recommends that conductivity, dissolved oxygen level, and concentrations of

iron and copper (feedwater only) are monitored and kept below the recommended levels

to mitigate SCC. The EPRI guidelines in BWRVIP-29 (TR-103515) also include

recommendations for controlling water chemistry in auxiliary systems: torus/pressure

suppression chamber, condensate storage tank, and spent fuel pool.

Confirmation Process - Following corrective actions, additional samples are taken and

analyzed to verify that the corrective actions were effective in returning the

concentrations of contaminants such as chlorides, fluorides, sulfates, dissolved oxygen,

and hydrogen peroxide to within the acceptable ranges. As discussed in the appendix to

this report, the staff finds it acceptable to use the requirements of 10 CFR Part 50,

Appendix B, in addressing the confirmation process.

The staff in evaluating the exceptions stated that monitoring of hydrogen peroxide is not

required by any version of the EPRI BWR chemistry guidelines. Although there is a chemical

method for measuring hydrogen peroxide, chemical reactions occurring in sample lines result in

peroxide destruction before it reaches the sampling point. Obtaining meaningful results is,

therefore, very difficult and not a very practical proposition. The procedure becomes even less

accurate with noble metals application, which is being currently practiced at the plant, due to

their catalytic effect on the hydrogen-oxygen reaction. However, the applicant stated that, if

necessary, the concentration of hydrogen peroxide can be estimated at various locations by

predictive radiolysis modeling. This method is acceptable to the staff, because it could provide

needed information.

The description of the confirmation process in the GALL Report includes a requirement for

monitoring hydrogen peroxide as one of the parameters for confirming corrective actions. For

the same reasons as in scope of the program element, the staff finds it justifiable not to monitor

hydrogen peroxide for confirmation purposes. The staff found the exceptions acceptable.
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Enhancement 1. The Chemistry Control Program procedure is written to address all three units;

however, Unit 1 must implement the latest revision to EPRI TR-103515-R2 guidelines prior to

the period of extended operation. This affects the program element, ”Scope of Program,”

(Element 1), as described below.

The program includes periodic monitoring and control of known detrimental

contaminants such as chlorides, fluorides (PWRs only), dissolved oxygen, and sulfate

concentrations below the levels known to result in loss of material or crack initiation and

growth. Water chemistry control is in accordance with the guidelines in BWRVIP-29

(EPRI TR-103515) for water chemistry in BWRs; EPRI TR-105714, Rev. 3, for primary

water chemistry in PWRs; EPRI TR-102134, Rev. 3, for secondary water chemistry in

PWRs; or later revisions or updates of these reports as approved by the staff. 

In evaluating the element, the applicant stated that, with the implementation of this

enhancement and with the exceptions noted above, the Chemistry Control Program will be

consistent with the affected program element for all three units.

In evaluating the element, the enhancement stated that in order to make the Chemistry Control

Program applicable to all three units in the Browns Ferry plant, the Revision 2000 of the EPRI

BWR Chemistry Guidelines has to be implemented in Unit 1. This will make the Chemistry

Control program identical for all three units. The staff finds this enhancement acceptable.

Operating Experience. In evaluating the BFN operating experience, the applicant stated that for

this program element the EPRI guideline documents have been developed based on plant

experience and have been shown to be effective over time with their widespread use in the

industry. The specific examples of BWR industry operating experience are as follows:

 • IGSCC has occurred in small and large-diameter BWR piping made of austenitic

stainless steels and nickel-based alloys.

 • Significant cracking has occurred in recirculation, core spray, residual heat removal, and

reactor water cleanup systems’ piping welds.

 • IGSCC has also occurred in a number of vessel internal components, including the core

shroud, access hole cover, top guide, and core spray spargers.

 • No occurrence of SCC in piping and other components in standby liquid control systems

exposed to sodium pentaborate solution has ever been reported.

As chemistry control guidelines were evolving in the industry, BFN experience with RCS

chemistry was similar to that of the industry. Cracking due to IGSCC was found in reactor

recirculation, reactor water cleanup, and jet pump instrumentation system piping.

The Chemistry Control Program is based on EPRI TR-103515-R2 (BWRVIP-79), which is the

2000 Revision of "BWR Water Chemistry Guidelines.” EPRI periodically updates the water

chemistry guidelines, as new information becomes available. The Chemistry Control Program

has incorporated new EPRI information to develop a proactive water chemistry program to

minimize IGSCC.
3-34

The applicant indicated that its operating experience with reactor chemistry was similar to that

of the industry. The aging effect of the components was mainly due to cracking caused by

IGSCC in reactor recirculation, reactor water cleanup, and jet pump instrumentation system

piping. The applicant has indicated that as new information becomes available the Chemistry

Control Program will be updated by developing proactive water chemistry procedures aiming at

minimizing IGSCC.

The staff asked the applicant to provide plant-specific operating experience in staff 

RAI B.2.5.1-2 dated December 7, 2004, since the applicant stated in Appendix B that its

experience was similar to the industry experience described above; however, the applicant did

not provide plant-specific details to substantiate the similarity.

In its response, by letter January 6, 2005, the applicant stated that a review of BFN chemistry

records revealed that the EPRI Action 3 criteria were not exceeded at any time during the five

years considered. BFN short-term transients had no significant impact on reactor vessel and

RCS components. In addition, these transients had no impact on the acceptability of the

Chemistry Control Program as an effective aging management tool for the renewal term. Minor

water chemistry excursions were noted. For example, minor excursions above Action Level 1

occurred during unit startups. In addition, several instances of condensate demineralizer resin

leakage have occurred between 1999 and 2004 on Units 2 and 3 due to bleed-through of old

septa and deficiencies in design/installation of new septa. Once the intrusions were identified,

the source of resin was isolated and sulfates were returned to normal levels. Some instances of

RCS sulfate concentration in Units 2 and 3 RCS exceeding Action Level 1 were observed in

2003 and 2004. There were no instances where Action Level 2 limits were exceeded. The

majority of the elevated concentrations have been due to resin intrusions. The staff found the

operating experience was not abnormal and was within the bounds of the industry experience

and, therefore, acceptable.

UFSAR Supplement. In LRA Section A.1.5, the applicant provided the UFSAR supplement for

the Chemistry Control Program. The staff reviewed this section and determined that the

information in the UFSAR supplement provides an adequate summary description of the

program. The staff found this section of the UFSAR supplement met the requirements of

10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant’s program, the staff determined

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. Also, the staff reviewed the enhancement and

confirmed that the implementation of the enhancement prior to the period of extended operation

would result in the existing AMP being consistent with the GALL Report AMP to which it was

compared. The staff concluded that the applicant had demonstrated that the effects of aging

will be adequately managed so that the intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the UFSAR supplement for this AMP and concluded 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 Boiling Water Reactor Vessel Inside Diameter Attachment Welds Program

Summary of Technical Information in the Application. The applicant’s BWR Vessel Inside

Diameter (ID) Attachment Welds Program is described in LRA Section B.2.1.7 “Boiling Water

Reactor Vessel Inside Diameter Welds Program.” In the LRA, the applicant stated that this is an

existing program. This program is consistent, with the enhancement, with GALL AMP XI.M4,

“BWR Vessel ID Attachment Welds.”

In the LRA, the applicant stated that the BWR Vessel ID Attachment Welds Program

implements the inspection and evaluation recommendations of staff-approved BWRVIP-48,

“Vessel ID Attachment Weld Inspection and Evaluation Guidelines,” (EPRI Report TR-108724,

February 1998), and the primary water chemistry recommendations in accordance with

BWRVIP-79, “BWR Water Chemistry Guidelines - 2000 Revision,” (EPRI Report

TR-103515-R2, February 2000) to ensure the long-term structural integrity of inside diameter

attachment welds of the vessel.

The purpose of the BWR Vessel ID Attachment Welds Program is to manage the effects of

crack initiation and growth due to SCC, including IGSCC, in the reactor vessel ID attachment

welds. The program identifies welds and their inspection frequency, flaw evaluation, and repair

or replacement requirements. The applicant stated that Section 7.11 of BFN Technical

Instruction 0-TI-365, “Reactor Pressure Vessel Internals Inspection (RPVII) Units 1, 2, and 3,”

identifies vessel interior wall welds that are within the scope of this AMP. They include jet pump

riser brace welds, core spray piping welds, and steam dryer support and feedwater (FW)

bracket attachment welds that use furnace-sensitized stainless steel (E308/309 or 308L/309L)

or alloy 182. The baseline and EVT-1, as well as re-inspection schedule, scope, and frequency

for these welds are consistent with BWRVIP-48 recommendations. Other non-safety related

(NSR) attachment welds that are inspected in accordance with the ASME Code Section XI,

Examination Category B-N-2, are steam dryer support/holddown, guide rod, FW sparger, and

surveillance sample holders. The applicant also stated that these examinations are coordinated

with the ASME Code Section XI requirements in examination category B-N-2, which require

visual examination of reactor pressure vessel (RPV) internal integral attachments.

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

BFN audit and review report. Furthermore, the staff reviewed the enhancement and its

justifications to determine whether the AMP, with the enhancement, remains adequate to

manage the aging effects for which it is credited.

In the LRA, the applicant stated that the BWR Vessel ID Attachment Welds Program will be

consistent with GALL AMP XI.M4 prior to the extended period of operation. The staff reviewed

the program elements (see SER Section 3.0.2.1) contained in the LRA and associated bases

documents, and compared them to the recommendations for GALL AMP XI.M4 for consistency.

The staff identified differences in the program elements, “Scope of Program” (Element 1),

“Preventive Action” (Element (2), and “Acceptance Criteria” (Element 6), as discussed below.

Scope of Program - In the description of AMP XI.M4, the GALL Report recommends

that BWR water chemistry control be performed in accordance with BWRVIP-29, which

references the 1993 revision of EPRI TR-103515, “BWR Water Chemistry Guidelines.”

However, the BFN water chemistry program is based on BWRVIP-79, the 2000 revision
3-36

of EPRI TR-103515-R2, which uses hydrogen water chemistry (HWC) with noble metal

chemical application (NMCA) to control both detrimental impurities and crack initiation

and growth. The staff found this difference acceptable, since BWRVIP-79 is the current

revision to industry practice.

Detection of Aging Effects - The staff identified a difference in the program element for

detection of aging effects. BWRVIP-48 guidelines recommend EVT-1 of all SR

attachments and those NSR attachments identified as being susceptible to IGSCC. The

recommendations in GALL AMP XI.M4 state that the EVT-1 should achieve at least 1

mil wire resolution. The applicant stated that BFN’s EVT-1 technique is capable of

achieving 1⁄2 mil wire resolution. Since the applicant’s technique is more sensitive than

the recommendation in the GALL Report, the staff found this difference acceptable.

Acceptance Criteria. The staff also noted that the applicant had not identified the use of

BWRVIP-14, BWRVIP-59, and BWRVIP-60 in the program element for acceptance

criteria to evaluate crack growth in stainless steel, nickel alloy, and low-alloy steel,

respectively. The applicant responded that nuclear document Nuclear Engineering

Design Procedure (NEDP)-23, Rev. 0, “BWR Reactor Pressure Vessel Internals

Inspections (RPVII),” references BWRVIP-14, BWRVIP-59, and BWRVIP-60 for the

evaluation of crack growth in stainless steels, nickel alloys, and low-alloy steels,

respectively, as supporting documents. The staff found this acceptable.

Enhancement. In LRA Section B.2.1.7, the applicant identified one enhancement to make this

AMP consistent with GALL AMP XI.M4. The enhancement is that BWRVIP guidelines will be

implemented for Unit 1 prior to the period of extended operation. The staff found this

enhancement acceptable since it will make the applicant’s program consistent for all three units.

Operating Experience. In LRA Section B.2.1.7, the applicant stated in its evaluation of the

program element, “Operating Experience,” that the BWR Pressure Vessel ID Weld inspection

program incorporates all susceptible welds. The inspections are based on operating

experience, industry operating experience and various BWRVIP/EPRI Guidelines. The program

schedules inspections, evaluates any flaws detected, and provides for repair or replacement as

appropriate. The program, as implemented, has adequately managed the reactor vessel ID

attachment welds.

The staff asked the applicant to describe the plant-specific operating experience relevant to the

vessel ID attachment welds. The applicant provided, by its formal response dated October 8,

2004 and as documented in the staff’s audit and review report, the following plant-specific

operating experience: 

 • The jet pump riser brace to vessel pad welds are inspected by Technical Instruction

0-TI-365 ("Reactor Pressure Vessel Internals Inspection (RPVII) - Units 1, 2, and 3") in

accordance with BWRVIP-41. The welds were baseline inspected during the 2001

refueling outage for Unit 2 and the 2002 and 2004 refueling outages for Unit 3. The

applicant did not find any reportable indications and these welds will be inspected on

Unit 1 prior to restart. 

 • The core spray piping bracket welds are inspected by 0-TI-365 in accordance with

BWRVIP-18. The welds were baseline inspected during the 1999 refueling outage for
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Unit 2 and the 2000 refueling outage for Unit 3. No reportable indications were found.

These welds will be inspected on Unit 1 prior to restart.

 • The inspection and flaw evaluation were performed in accordance with the guidelines of

BWRVIP-48. Since the implementation of these guidelines, for approximately 4 years,

no reportable indications were found in Units 2 and 3. The applicant stated that these

guidelines will be implemented on Unit 1 prior to its restart.

In evaluating the element, staff concurred with the applicant that the continued implementation

of the BWR Vessel ID Attachment Welds Program provides reasonable assurance that crack

initiation and growth will be adequately managed and the intended functions of the vessel ID

attachment welds will be maintained consistent with the CLB for the period of extended

operation. The staff found that the applicant had adequately considered operating experience,

consistent with the guidance in the GALL Report. (See SER Section 3.1.2.3.7)

UFSAR Supplement. In LRA Section A.1.7, the applicant provided the UFSAR supplement for

the Boiling Water Reactor Vessel ID Attachment Welds Program. The staff reviewed this

section and determined that the information in the UFSAR supplement provides an adequate

summary description of the program. The staff found this section of the UFSAR met the

requirements of 10 CFR 54.21(d). 

Conclusion. On the basis of its review and audit of the applicant’s program, the staff determined

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 enhancement and

confirmed that the implementation of the enhancement prior to the period of extended operation

would result in the existing AMP being consistent with the GALL Report AMP to which it was

compared. The staff concluded that the applicant had demonstrated that the effects of aging

will be adequately managed so that the intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.4 Boiling Water Reactor Feedwater Nozzle Program

Summary of Technical Information in the Application.The applicant’s BWR Feedwater Nozzle

Program is described in LRA Section B.2.1.8 “Boiling Water Reactor Feedwater Nozzle

Program.” In the LRA, the applicant stated that this is an existing program. This program is

consistent, with the enhancement, with GALL AMP XI.M5, “BWR Feedwater Nozzle.”

In the LRA, the applicant stated that the BWR Feedwater Nozzle Program enhances the ISIs

specified in ASME Code Section XI with the recommendations of General Electric Corporation

(GE) report, NE-523-A71-0594, Rev.1,“Alternate BWR Feedwater Nozzle Inspection

Requirements,” August 1999. 

The BWR Feedwater Nozzle Program manages cracking in reactor feedwater nozzles due to

thermal fatigue. The program addresses BWR feedwater nozzle cracking by implementing the

recommendations of NUREG-0619, “BWR Feedwater Nozzle and Control Rod Drive Return

Line Nozzle Cracking,” November 1980. LRA Section B.2.1.8 describes the details of hardware

modifications completed to mitigate cracking. The applicant also stated that changes to plant
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operating procedures for Units 2 and 3 have been implemented and include improved

feedwater control. For details of the modification implemented, refer to LRA Section B.2.1.8.

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

BFN audit and review report. Furthermore, the staff reviewed the enhancement and its

justifications to determine whether the AMP, with the enhancement, remains adequate to

manage the aging effects for which it is credited.

In the LRA, the applicant stated that the BWR Feedwater Nozzle Program will be consistent

with GALL AMP XI.M5 with the enhancement described below. The staff reviewed the program

elements contained in the AMP and associated bases documents, and compared them to the

recommendations in GALL AMP XI.M5 for consistency.

The applicant credited GE report GE-NE-523-A71-0594, Revision 1, which has been approved

by the staff, and is consistent with the GALL Report for managing crack initiation and growth in

the feedwater nozzle.

Enhancement. In LRA Section B.2.1.8, the applicant identified one enhancement to make this

AMP consistent with GALL AMP XI.M5. The enhancement involves Unit 1 operating procedures

upgraded to decrease the magnitude and frequency of FW temperature fluctuations. This

enhancement affects the program element “Preventive Action.” In evaluating the element, the

applicant concluded that mitigation occurs by systems modifications, such as removal of

stainless steel cladding and installation of improved spargers. The applicant stated that it is also

accomplished by changes to plant operating procedures, such as improved feedwater control

and rerouting of the reactor water cleanup system, to decrease the magnitude and frequency of

temperature fluctuations. 

The staff concurred with the applicant’s evaluation and finds this enhancement acceptable. It

will make the applicant’s program consistent for all three units.

Operating Experience. Regarding plant-specific operating experience with cracking of

feedwater nozzles, the applicant stated that cracking was discovered in the RPV feedwater

nozzle cladding in 1977. Cladding removal and feedwater sparger replacement were performed

for all three units (Unit 1 - 1977, Unit 2 - 1978, Unit 3 - 1979). Since this modification was made,

no cracking problems have been found.

The staff concluded that implementation of the applicant’s program provides reasonable

assurance that cracking of feedwater nozzles is being adequately managed, such that there is

no loss of intended function. During the concurred audit, the staff noted that the applicant

incorporates internal and external plant operating experience issues into the plant Corrective

Action Program on a continuing basis. The staff concluded there is reasonable assurance that

operating experience will continue to be reviewed in the future to ensure that the effects of

aging will be adequately managed.

In the LRA, the applicant concluded that the BWR Feedwater Nozzle Program provides

reasonable assurance that cracking aging effects in the feedwater nozzles are adequately

managed so that their intended functions, consistent with the CLB, are maintained during the
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period of extended operation. The staff found that the applicant had adequately considered the

operating experience consistent with the guidance in the GALL Report.

UFSAR. In LRA Section A.1.8, the applicant provided the UFSAR supplement for the BWR

Feedwater Nozzle Program. The staff reviewed this section and determined that the information

in the UFSAR supplement provides an adequate summary description of the program. The staff

found this section of the UFSAR met the requirements of 10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant’s program, the staff determined

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 enhancement and

confirmed that implementation of the enhancement prior to the period of extended operation

would result in the existing AMP being consistent with the GALL Report AMP to which it was

compared. The staff concluded that the applicant had demonstrated that the effects of aging

will be adequately managed so that the intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.5 Boiling Water Reactor Stress Corrosion Cracking Program

Summary of Technical Information in the Application. The applicant’s BWR SCC Program is

described in LRA Section B.2.1.10, “Boiling Water Reactor Stress Corrosion Cracking

Program.” In the LRA, the applicant stated that this is an existing program. This program is

consistent, with an enhancement, with GALL AMP XI.M7, “BWR Stress Corrosion Cracking.”

In the LRA, the applicant stated that the BWR SCC Program enhances the inservice

inspections specified in ASME Code Section XI with the recommendations of NUREG-0313,

Rev. 2, “Technical Report on Material Selection and Processing Guidelines for BWR Coolant

Pressure Boundary Piping,” 1988; NRC GL 88-01, “NRC Position on Intergranular Stress

Corrosion Cracking in BWR Austenitic Stainless Steel Piping,” and its Supplement 1,

February 1992; and BWRVIP-75, “Technical Basis for Revisions to Generic Letter 88-01

Inspection Schedules,” September 2000.

The purpose of BWR SCC Program is to manage IGSCC in reactor coolant pressure boundary

components made of stainless steel. The comprehensive programs outlined in GL 88-01 and

NUREG-0313, and in the staff-approved BWRVIP-75, have been implemented and address the

mitigating measures for SCC and IGSCC in these components. Preventive methodologies

include piping replacement with IGSCC-resistant stainless steel. Preventive measures have

also included heat sink welding, induction heating, and mechanical stress improvement.

The ASME Code Section XI inspection and flaw evaluation methodology, enhanced by the

recommendations of BWRVIP-75, is credited to detect and evaluate IGSCC. BWRVIP-75

allows for modification of the inspection scope identified in the GL 88-01 program. The ASME

Code Section XI, Subsections IWB, IWC, and IWD Inservice Inspection Program detects

degradation, including IGSCC.
3-40

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

BFN audit and review report. Furthermore, the staff reviewed the enhancement and its

justifications to determine whether the AMP, with the enhancement, remains adequate to

manage the aging effects for which it is credited.

In the LRA, the applicant stated that the BWR SCC Program is consistent with GALL

AMP XI.M7. The staff reviewed the program elements (see SER Section 3.0.2.1) contained in

the AMP and associated bases documents, and compared them to the recommendations in

GALL AMP XI.M7 for consistency. The staff identified a difference in the program description,

as well as in the program element for preventive action, as discussed below.

GALL AMP XI.M7 recommends that BWR water chemistry control be performed in accordance

with BWRVIP-29, which references the 1993 revision of EPRI TR-103515, “BWR Water

Chemistry Guidelines.” The water chemistry programs are based on BWRVIP-79, which

references the 2000 revision of EPRI TR-103515-R2 and uses HWC with NMCA to control both

detrimental impurities and crack initiation and growth. The applicant stated in the LRA that BFN

has not applied for any relief for vessel internals component weld inspections in accordance

with BWRVIP-62, which allows relief for welds exposed to HWC. The staff found this difference

acceptable, since BWRVIP-79 is the current revision to industry practice.

Regarding the program element for preventive action, the applicant stated, as documented in

the staff’s audit and review report, that induction heating stress improvement and mechanical

stress improvement program have been used on various welds on both Units 2 and 3 as a

remedy to IGSCC in austenitic stainless steel piping. However, the induction heating stress

improvement technique was performed many years prior to the issuance of BWRVIP-61, which

provides guidelines for induction heating stress improvement effectiveness. As part of the

applicant’s response to IE Bulletin 88-01, mechanical stress improvement program will be

performed on applicable welds on Unit 1 prior to restart. The BWR SCC Program will continue

during the period of extended operation and will implement the replacement and preventive

measures as augmented by NUREG-0313, GL 88-01 and BWRVIP-75 guidelines, to mitigate

IGSCC.

Additionally, the applicant stated that the materials in the sections of pipe exposed to fluid

temperatures greater than 200 °F are being replaced with 316 Stainless Steel NG grade

material, which is not susceptible to IGSCC. The criteria for the design, installation, and testing

associated with the replacement or removal of selected piping to limit the susceptibility to

IGSCC for all three BFN units is provided in general design criteria (GDC) BFN-50-779,

“Replacement of Selected Piping to Limit Susceptibility to IGSCC,” and has been implemented

for Units 2 and 3 by various design changes. Unit 1 is in the process of implementing similar

design changes prior to its restart. 

The applicant stated that detection of leaks due to IGSCC has been performed through

inspection (Section XI and other augmented examinations, such as BWRVIP, NUREG-0619),

monitoring of drywell leakage, and the feedwater leakage detection system.

The staff noted that the applicant has not identified the use of BWRVIP-14, BWRVIP-59, and

BWRVIP-60 in the program element for acceptance criteria, to evaluate crack growth in

stainless steel, nickel alloy and low-alloy steel, respectively. The applicant responded that
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NEDP-23, Revision 0, “BWR Reactor Pressure Vessel Internals Inspections (RPVII),”

references BWRVIP-14, BWRVIP-59, and BWRVIP-60, for evaluation of crack growth in

stainless steels, nickel alloys, and low-alloy steels, respectively, as supporting documents. 

Since the applicant continues to use these measures in accordance with the staff-approved

methodology, the staff found this acceptable.

Enhancement. In the LRA Section B.2.1.10, the applicant identified one enhancement to make

this AMP consistent with GALL AMP XI.M7. The BWR Stress Corrosion Cracking Program will

be implemented on Unit 1 prior to the period of extended operation. The staff found this

enhancement acceptable since it will make the applicant’s program consistent for all three units.

Operating Experience. In the LRA, the applicant stated that, since the implementation of this

program, structural integrity has been maintained by ensuring that aging effects were

discovered and components repaired/replaced before the loss of their intended function. For

Units 2 and 3, mitigation measures to prevent cracking or dispositions of examinations that

have detected cracking include: targeted replacement of existing piping with piping fabricated

with IGSCC-resistant material; utilizing a stress improvement process; increasing

nondestructive examination frequency; implementing a hydrogen water chemistry program;

and, application of weld overlay reinforcement. For Unit 1, BFN is replacing the majority of

Class 1 SS piping, including any weld overlay reinforcement. Pre-service examinations of the

replaced piping will be performed as required by ASME Code Section XI. After restart,

applicable mitigation measures and nondestructive examinations will be performed in

accordance with NUREG 0313, Revision 2, and GL 88-01 or the referenced BWRVIP-75

guideline.

The applicant stated that the BWR SSC Program provides reasonable assurance that SCC in

stainless steel piping is adequately managed so that its intended functions, consistent with the

CLB, is maintained during the period of extended operation. During the onsite audit, the staff

noted that the applicant incorporates internal and external plant operating experience issues

into the plant Corrective Action Program on a continuing basis. The staff concluded there is

reasonable assurance that the applicant will continue to review operating experience in the

future to ensure that the effects of aging are adequately managed, consistent with the guidance

in the GALL Report.

The staff reviewed and determined that the applicant should address the plant-specific

experience related to SCC in the reactor vessel (RV) and reactor vessel internals (RVIs) at the

BFN units. A detailed discussion of the staff's evaluation of Boiling Water Reactor Stress

Corrosion Cracking Program is shown SER Section 3.1.2.3.8.

In RAI B.2.1.10-1(A), the staff requested that the applicant describe plant-specific experience

related to IGSCC cracking of the stainless steel and nickel alloy components in RV and RVIs.

In its response to RAI B.2.1.10-1(A), by letter dated January 31, 2005, the applicant stated that

no IGSCC had been identified in RV and its components at BFN, Units 2 and 3, with the

exception of guide tube/dry tube (replaced with IGSCC-resistant material as discussed in

Section 3.1.3.1.6.1 of the staff's SER on the AMR section). For BFN, Unit 1, the applicant

proposed to implement improved RCS water chemistry to mitigate IGSCC. The staff reviewed

the response and finds it acceptable, because implementation of the improved water chemistry
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(AMP B.2.1.5), and ISI programs (AMP B.2.1.4) would enable the applicant to manage the

aging effect due to IGSCC effectively during the extended period of operation.

In RAI B.2.1.10-1(B) the staff requested that the applicant submit information on the mitigation

actions taken at BFN with respect to selection of materials that are resistant to sensitization,

use of special processes that reduce residual tensile stress, and monitoring of water chemistry

such as discussed in GALL AMP XI.M7, "BWR Stress Corrosion Cracking."

In its response to RAI B.2.1.10-1(B), by letter dated January 31, 2005, the applicant stated that

mitigation efforts include selection of IGSCC-resistant materials and monitoring/control of water

chemistry parameters. The criteria for the design, installation, and testing associated with the

replacement or removal of selected RCS piping to limit the susceptibility to IGSCC is provided

in GDC BFN-50-779, "Replacement of Selected Piping to Limit Susceptibility to IGSCC."

Monitoring and control of chemistry parameters is controlled by AMP B.2.1.5. The staff finds

AMP B.2.1.5 acceptable because the program is based on updated industry experience and

plant-specific and industry-wide operating experience confirms the effectiveness of the RCS

chemistry program. The staff found that the applicant's proposed mitigation strategy would

ensure that the aging effect due to IGSCC in the RV and its components can be managed

effectively during the extended period of operation. 

In RAI B.2.1.10-1(C), the staff requested that the applicant provide information concerning

whether any NMCA and HWC is applied at BFN. The staff requested that the applicant confirm

the method of controlling HWC and any NMCA in the RV. The staff requested the applicant to

provide details on the methods for determining the effectiveness of HWC and NMCA by using

the following parameters:

 (1) Electro Chemical Potential (ECP)

 (2) Feedwater hydrogen flow

 (3) Main steam oxygen content

 (4) Hydrogen/oxygen molar ratio.

In its response to RAI B.2.1.10-1(C), by letter dated January 31, 2005, the applicant stated that

BFN currently utilizes zinc addition, NMCA and HWC as part of the reactor water chemistry

control program. BFN does not utilize ECP probes and, therefore, alternate means are used to

monitor NMCA/HWC control. The acceptable alternate means are described in Section 5.4 of

EPRI-103515-R2. These guidelines are implemented in BFN procedure CI-13.1, Chemistry

Program, which specifies that the reactor water H2/O2 molar ratio must be greater than 4 during

power operation to effectively mitigate IGSCC. 

The staff agreed that implementation of HWC/NMCA should effectively mitigate IGSCC

because these additions reduce the oxygen potential in RCS water. With reduced oxygen levels

in the RCS water the occurrence of IGSCC is minimized. The effectiveness of HWC/NMCA can

be maintained by using H2/O2 molar ratio of greater than 4, which is acceptable to the staff

because this molar ratio provides adequate margin in maintaining hydrogen availability for the

RV and RVIs. AMP recommended by the GALL Report for managing IGSCC for the RVIs is

XI.M.7, "BWR Stress Corrosion Cracking."
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UFSAR Supplement. In LRA Section A.1.10, the applicant provided the UFSAR supplement for

the Boiling Water Reactor Stress Corrosion Cracking Program. The staff reviewed this section

and determined that the information in the UFSAR supplement provides an adequate summary

description of the program. The staff found this section of the UFSAR supplement met the

requirements of 10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant’s program, the staff determined

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 enhancement and

confirmed that the implementation of the enhancement prior to the period of extended operation

would result in the existing AMP being consistent with the GALL Report AMP to which it was

compared. The staff concluded that the applicant had demonstrated that the effects of aging

will be adequately managed so that the intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.6 Boiling Water Reactor Penetrations Program

Summary of Technical Information in the Application. The applicant’s BWR Penetrations

Program is described in LRA Section B.2.1.11, “Boiling Water Reactor Penetrations Program.”

In the LRA, the applicant stated that this is an existing program. This program is consistent,

with an enhancement, with GALL AMP XI.M8, “BWR Penetrations.”

In the LRA, the applicant stated that the BWR Penetrations Program enhances the inservice

inspections specified in ASME Code Section XI with the recommendations of BWRVIP-27,

“BWR Standby Liquid Control System/Core Plate P/SLC Inspection and Flaw Evaluation

Guidelines, (EPRI TR-107286, April 1997)” and BWRVIP-49, “Instrument Penetration

Inspection and Flaw Evaluation Guidelines, (EPRI TR-108695, March 1998).” Repair or

replacement recommendations of BWRVIP-53, “Standby Liquid Control Line Repair Design

Criteria, (EPRI TR-108716, March 24, 2000)” and BWRVIP-57, “Instrument Penetration Repair

Design Criteria, (EPRI TR-108721, March 24, 2000)” are also implemented and are performed

in accordance with ASME Code Section XI repair and replacement requirements. The program

also incorporates the water chemistry recommendations of BWRVIP-79, “BWR Water

Chemistry Guidelines, (EPRI TR-103515-R2, 2000).”

The purpose of the BWR Penetrations Program is to manage the effects of crack initiation and

growth due to SCC or IGSCC in instrument and standby liquid control nozzle penetrations of

the reactor vessel. The program contains preventive measures to mitigate SCC or IGSCC. The

ASME Code Section XI inservice inspections implement guidelines of BWRVIP-49 and

BWRVIP-27 to monitor the effects of cracking on the intended function of these penetrations.

BWRVIP-57 for instrumentation penetrations and BWRVIP-53 for the standby liquid control line

provide guidelines for repair and/or replacement as needed to maintain the ability to perform the

intended function.
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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

BFN audit and review report. Furthermore, the staff reviewed the enhancement and its

justifications to determine whether the AMP, with the enhancement, remains adequate to

manage the aging effects for which it is credited.

In the LRA, the applicant stated that the BWR Penetrations Program is consistent with GALL

AMP XI.M8. The staff reviewed the program elements (SER Section 3.0.2.1) contained in the

AMP and associated bases documents, and compared them to those listed for GALL

AMP XI.M8 for consistency.

The staff identified a difference in the program description, as well as in the program element

for preventive action, as discussed below. 

GALL AMP XI.M7 recommends that the BWR water chemistry control be performed in

accordance with BWRVIP-29, which references the 1993 revision of EPRI TR-103515, “BWR

Water Chemistry Guidelines.” However, the water chemistry programs are based on

BWRVIP-79, which references the 2000 revision of EPRI TR-103515-R2 and uses HWC with

NMCA to control both detrimental impurities and crack initiation and growth. In the LRA, the

applicant stated that BFN has not applied for any relief for vessel internals component weld

inspections in accordance with BWRVIP-62, which allows relief for welds exposed to hydrogen

water chemistry. The staff found this difference acceptable. BWRVIP-79 is the current revision

to industry practice.

The staff also noted that the applicant has not identified the use of BWRVIP-14, BWRVIP-59,

and BWRVIP-60 in the program element for acceptance criteria to evaluate crack growth in

stainless steel, nickel alloy and low-alloy steel, respectively. The applicant responded that

NEDP-23, Rev. 0, “BWR Reactor Pressure Vessel Internals Inspections (RPVII),” references

BWRVIP-14, BWRVIP-59, and BWRVIP-60, for evaluation of crack growth in stainless steels,

nickel alloys, and low-alloy steels, respectively, as supporting documents. The staff found this

acceptable.

Enhancement. In LRA Section B.2.1.11, the applicant identified one enhancement to make this

AMP consistent with GALL AMP XI.M8. The BWRVIP guidelines will be implemented on Unit 1

prior to the period of extended operation. The staff found this enhancement acceptable since it

will make the applicant’s program consistent for all three units.

Operating Experience. In the LRA, the applicant stated that the BWR penetration program

monitors the effects of SCC/IGSCC on the intended function of the component by detection and

sizing of cracks by the ISI program. The ISI program incorporates the inspection and evaluation

guidelines of BWRVIP-27 and BWRVIP-49. The BWRVIP-49 provides guidelines for instrument

penetrations, and BWRVIP-27 addresses the standby liquid control (SLC) system nozzle or

housing. Inspections are performed with BFN procedures that are part of the ISI program and

incorporate the requirements of ASME Code Section XI, Table IWB-2500-1.

The applicant stated, as documented in the staff’s audit and review report, that Units 2 and 3

have experienced no unacceptable conditions during the four years since implementation of the

BWRVIP-27 and BWRVIP-49 guidelines. These inspections will be implemented on Unit 1 prior
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to its restart. The staff concluded that the recent operating experience provides reasonable

assurance of the program’s effectiveness.

During the onsite audit, the staff noted that the applicant incorporates internal and external

plant operating experience issues into the plant Corrective Action Program on a continuing

basis. The staff concluded there is reasonable assurance that the applicant will continue to

review operating experience in the future to ensure that the effects of aging are adequately

managed, consistent with the guidance in the GALL Report. (See SER Section 3.1.2.3.11)

UFSAR Supplement. In LRA Section A.1.11, the applicant provided the UFSAR supplement for

the BWR Penetrations Program. The staff reviewed this section and determined that the

information in the UFSAR supplement provides an adequate summary description of the

program. The staff found this section of the UFSAR supplement met the requirements of

10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant’s program, the staff determined

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 enhancement and

confirmed that the implementation of the enhancement prior to the period of extended operation

would result in the existing AMP being consistent with the GALL Report AMP to which it was

compared. The staff concluded that the applicant had demonstrated that the effects of aging

will be adequately managed so that the intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.7 Boiling Water Reactor Vessel Internals Program

Summary of Technical Information in the Application. The applicant’s BWR Vessel Internals

Program is described in LRA Section B.2.1.12, “Boiling Water Reactor Vessel Internals

Program.” In the LRA, the applicant stated that this is an existing program. This program is

consistent, with the enhancement, with GALL AMP XI.M9, “BWR Vessel Internals.”

In the LRA, the applicant stated that the purpose of BWR Vessel Internals Program is to

manage the effects of crack initiation and growth due to SCC, IGSCC, or irradiation-assisted

stress corrosion cracking (IASCC) in vessel internals components. The program contains

preventive measures to mitigate SCC or IGSCC. The ASME boiler and pressure vessel (B&PV),

Section XI, inservice inspection programs implement the BWRVIP guidelines associated with

BWR vessel internal components, to monitor the effects of cracking on their intended functions.

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

audit and review report. Furthermore, the staff reviewed the enhancements and their

justifications to determine whether the AMP, with enhancements, remains adequate to manage

the aging effects for which it is credited.

In the LRA, the applicant stated that BWR Vessel Internals Program is consistent with GALL

AMP XI.M9. The staff reviewed the program elements (see SER Section 3.0.2.1) contained in
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the AMP and associated bases documents, and compared them to those listed for GALL

AMP XI.M9 for consistency.

In accordance with NEDP-23, Revision 0, “BWR Reactor Pressure Vessel Internals Inspections

(RPVII),” the applicant stated that the staff-approved BWRVIP documents identified in the

GALL Report for this AMP are applicable to all units.

The staff identified a difference in the program description, as well as in the program element

for preventive action, as discussed below.

The GALL AMP XI.M8 recommends that BWR water chemistry control be performed in

accordance with BWRVIP-29, which references the 1993 revision of EPRI TR-103515, “BWR

Water Chemistry Guidelines.” However, the BFN water chemistry programs are based on

BWRVIP-79, which references the 2000 revision of EPRI TR-103515-R2 and uses HWC with

NMCA to control both the detrimental impurities and crack initiation and growth. In the LRA, the

applicant stated that BFN has not applied for any relief for vessel internals component weld

inspections in accordance with BWRVIP-62, which allows relief for welds exposed to hydrogen

water chemistry. The staff found this difference acceptable, since BWRVIP-79 is the current

revision to industry practice.

The staff noted that the applicant will utilize BWRVIP-76 (which supersedes BWRVIP-07 and

BWRVIP-63) for core shroud inspection and flaw evaluation guidelines during the extended

period of operation.

The applicant stated, as documented in the staff’s audit and review report, that BFN committed

to the use of BWRVIP documents (transmittal of revised BWRVIP commitment letter to the

staff, dated June 2, 1997, RIMS R12 970612 789) and that the commitment to use BWRVIP

documents includes evaluating the SER (for BWRVIP documents), and completing the

applicable SER action items. The staff found this acceptable since the applicant will use the

results of the staff review in implementing BWRVIP-76.

The staff requested a clarification pertaining to the utilization of BWRVIP-44 and BWRVIP-45

as part of the vessel internals AMP.

The applicant also stated that, as documented in the staff’s audit and review report, even

though BWRVIP-44 and BWRVIP-45 are not specifically mentioned in BWRVIP-94 or NEDP-23

(which implements BWRVIP-94), the applicant previously committed to the use of BWRVIP

documents (in revised BWRVIP Commitment Letter to the staff, dated June 2, 1997, RIMS R12

970612 789). Should weld repair of nickel-based alloys be needed, the applicant would follow

the guidelines of BWRVIP-44 and BWRVIP-45 as stated in NEDP-23. The staff found this

acceptable since the applicant is committed to utilization of BWRVIP-44 and BWRVIP-45, if the

need arises. The staff found this acceptable, and the commitment is incorporated into SER

Appendix A. 

The staff noted that the applicant is taking a deviation to BWRVIP-18 on two specific items: i)

pertaining to Unit 3 core spray repair design and, ii) BWRVIP- 41 on Unit 3 jet pump #5 repair

design. The applicant addressed this issue in its responses dated January 31, 2005, and

May 25, 2005, to the staff RAI B.2.1.12, and the details and staff disposition of the issue is

shown in SER Section 3.1.2.2.7. The staff, in a follow-up call on March 29, 2005, inquired
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whether the applicant planned to take any exceptions to the implementation of BWRVIP

inspection guidelines as a part of the AMP for the reactor vessel internals. If so, the applicant

must submit the exceptions (including the exceptions that were taken on BWRVIP-18 and

BWRVIP-41) to the staff for review and approval no later than two years prior to the

commencement of the extended period of operation. The applicant in its response dated

May 25, 2005, confirmed that it currently has not identified any exception to the BWRVIP

guidelines. Hence the staff considered this RAI resolved.

Enhancement. In LRA Section B.2.1.12, the applicant identified one enhancement to make this

AMP consistent with GALL AMP XI.M9. The BWRVIP guidelines will be implemented on Unit 1

prior to the period of extended operation. The staff found this enhancement acceptable since it

will make the applicant’s program consistent for all three units.

Operating Experience. In the LRA, the applicant stated that extensive cracking has been

observed in core shrouds at both horizontal and vertical welds (GL 94-03, NRC IN 97-17). It has

affected shrouds fabricated from Type 304 and Type 304L SS, which is generally considered to

be more resistant to SCC. Weld regions are most susceptible, although it is not clear whether

this is due to sensitization and/or impurities associated with the welds, or the high residual

stresses in the weld regions. This experience is reviewed in GL 94-03 and NUREG-1544. Some

experiences with visual inspections are discussed in IN 94-42. Most of the BWR reactors,

including BFN, have experienced cracking of RPV internal components.

The staff concluded that implementation of the applicable BWRVIP guidelines provides

reasonable assurance that cracking of BWR RPV internal components is being adequately

managed, such that there is no loss of intended function.

During the concurred audit, the staff noted that the applicant incorporates internal and external

plant operating experience issues into the plant Corrective Action Program on a continuing

basis. The staff concluded there is reasonable assurance that operating experience will

continue to be reviewed in the future to ensure that the effects of aging will be adequately

managed.

UFSAR Supplement. In LRA Section A.1.12, the applicant provided the UFSAR supplement for

the BWR Vessel Internals Program. The staff reviewed this section and determined that the

information in the UFSAR supplement provides an adequate summary description of the

program. The staff found this section of the UFSAR supplement met the requirements of

10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant’s program, the staff determined

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 enhancement and

confirmed that the implementation of the enhancement prior to the period of extended operation

would result in the existing AMP being consistent with the GALL Report AMP to which it was

compared. The staff concluded that the applicant had demonstrated that the effects of aging

will be adequately managed so that the intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the UFSAR supplement for this AMP and concluded 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 Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless

Steel Program

Summary of Technical Information in the Application. The applicant’s Thermal Aging and

Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS) Program is

described in LRA Section B.2.1.14, “Thermal Aging and Neutron Irradiation Embrittlement of

Cast Austenitic Stainless Steel Program.” In the LRA, the applicant stated that this is an existing

program. This program is consistent, with enhancement, with GALL AMP XI.M13, “Thermal

Aging and Neutron Irradiation Embrittlement of CASS.”

The applicant stated that the Thermal Aging and Neutron Irradiation Embrittlement of CASS

Program monitors the effects of loss of fracture toughness on the intended function of the

component by performing supplemental examinations of CASS reactor vessel internals

components. The reactor vessel internals receive a visual inspection in accordance with the

ASME Code Section XI Subsection IWB, Category B-N-3 requirements.

Additional enhanced visual inspections that incorporate the requirements of the BWR Vessel

Internals Program are performed to detect the effects of loss of fracture toughness due to

thermal aging and neutron irradiation embrittlement of CASS reactor vessel internals.

The enhanced visual inspections include the ability to achieve a 0.0005-inch resolution, with the

conditions (e.g., lighting and surface cleanliness) of the inservice examination bounded by

those used to demonstrate the resolution of the inspection technique.

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

BFN audit and review report. Furthermore, the staff reviewed the enhancement and its

justifications to determine whether the AMP, with enhancement, remains adequate to manage

the aging effects for which it is credited.

In the LRA, the applicant stated that the Thermal Aging and Neutron Irradiation Embrittlement

of CASS Program is consistent with the GALL AMP XI.M13, “Thermal Aging and Neutron

Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS).” The staff reviewed the

program elements (see SER Section 3.0.2.1) contained in the AMP basis document and

compared them against GALL AMP XI.M13 for consistency. The staff noted a difference in the

program element for the scope of the program, as discussed below.

The GALL AMP XI.M13 recommendations state that the scope of the program should specify

the guidelines for identification of susceptible components determined to be limiting from the

standpoint of thermal aging susceptibility (i.e., ferrite and molybdenum contents, casting

process, and operating temperature) and/or neutron irradiation embrittlement (neutron fluence).

Either a supplemental examination of the affected component based on the neutron fluence or

a component-specific evaluation to determine its susceptibility to loss of fracture toughness is to

be performed. The staff noted that the Thermal Aging and Neutron Irradiation Embrittlement of

CASS Program does not address this screening process. In response to a question from the

staff, the applicant stated that the scope of the Thermal Aging and Neutron Irradiation

Embrittlement of CASS Program includes supplemental examination of all CASS reactor vessel

internal components. Since screening is not used, there is no need to define a screening

process. The staff found this acceptable.
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The staff determined that all other program elements are consistent with GALL, with one

enhancement related to the program element “Scope of Program.” The applicant stated in the

LRA Appendix B that the enhancement to the Thermal Aging and Neutron Irradiation

Embrittlement of CASS AMP will be implemented on Unit 1. The enhancement is scheduled for

implementation prior to the period of extended operation. 

Staff Evaluation. In LRA Section B.2.1.14, the applicant identified one enhancement to make

this AMP consistent with GALL AMP XI.M13. This AMP will be implemented on Unit 1 prior to

the period of extended operation. The staff found that with the implementation of this

enhancement, BFN will be consistent with the affected program element for all three units.

Operating Experience. In the LRA, the applicant stated that cracking had been detected in the

reactor vessel internals at several domestic and overseas boiling water reactors. In June 1994,

the BWRVIP was formed to address integrity issues arising from inservice degradation of

reactor vessel internals. Since that time, the BWRVIP has published several reports that

present guidelines for inspecting, evaluating, and repairing reactor vessel internals.

The staff concluded that implementation of the BWRVIP guidelines for inspecting, evaluating,

and repairing reactor vessel internals provides reasonable assurance that loss of fracture

toughness of CASS reactor pressure vessel internal components is being adequately managed,

such that there is no loss of intended function.

In GALL AMP XI.M13, void swelling is also identified as an aging mechanism leading to loss of

fracture toughness in CASS reactor vessel internals. The applicant evaluated this program

element “operating experience” in section LRA B.2.1.14 on page B-48 and concluded as

follows:

The continued implementation of the Thermal Aging and Neutron Irradiation

Embrittlement of CASS aging management program provides reasonable assurance

that the aging effects will be managed so that the systems and components within the

scope of this program will continue to perform their intended functions consistent with

the current licensing basis for the period of extended operation.

The BFN Reactor Vessel Internals Program is based on research data obtained from both

laboratory-aged and service-aged materials. EPRI TR-107521 addresses data gathered from

liquid-metal-cooled fast breeder reactors, and how it may possibly be related to a PWR

component (baffle-former bolt) that is in almost direct contact with the fuel in a PWR. Since a

BWR does not have components in a similar location and thus can reasonably be expected to

experience less fluence, the staff concludes that is not a concern with BFN. Past studies of void

swelling by ANL, ORNL, HEDL, and GE have shown that the threshold fluence for void swelling

is approximately 1022 n/cm2, which is well in excess of the fluence experienced by typical boiling

water reactor CASS components. Secondly, the EPRI report notes that field experience does

not suggest that void swelling is a significant issue. The lowest temperature for which this

phenomenon is conjectured to occur is 300 °C (572 °F), which is higher than the temperature

experienced by BWR reactor vessel internals. Hence the staff concluded that void swelling is

not an aging effect applicable to BFN. 

During the onsite audit, the staff noted that the applicant incorporates internal and external

plant operating experience issues into the plant Corrective Action Program on a continuing
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basis. The staff concluded there is reasonable assurance that operating experience will

continue to be reviewed in the future to ensure that the effects of aging will be adequately

managed.

UFSAR Supplement. In LRA Section A.1.14, the applicant provided the UFSAR supplement for

the Thermal Aging and Neutron Irradiation Embrittlement of CASS Program. The staff reviewed

this section and determined that the information in the UFSAR supplement provides an

adequate summary description of the program. The staff found this section of the UFSAR

supplement met the requirements of 10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant’s program, the staff determined

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 enhancement and

confirmed that the implementation of the enhancement prior to the period of extended operation

would result in the existing AMP being consistent with the GALL Report AMP to which it was

compared. The staff concluded that the applicant had demonstrated that the effects of aging

will be adequately managed so that the intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.9 Flow-Accelerated Corrosion Program

Summary of Technical Information in the Application. The applicant’s Flow-Accelerated

Corrosion (FAC) Program is described in LRA Section B.2.1.15, “Flow-Accelerated Corrosion

Program.” In the LRA, the applicant stated that this is an existing program. This program is

consistent, with the enhancement, with GALL AMP XI.M17, “Flow-Accelerated Corrosion

Program.”

In the LRA, the applicant stated that the FAC Program was developed in response to GL 89-08,

"Erosion/Corrosion-Induced Pipe Wall Thinning.” The program is based on the guidelines of

EPRI NSAC-202L, "Recommendations for an Effective Flow Accelerated Corrosion Program,"

Revision 2. The FAC Program includes the use of an industry-accepted computer code to

predict FAC in carbon steel lines containing high-energy fluids (two-phase as well as

single-phase systems subject to FAC). The program includes analysis to determine critical

locations, baseline inspections to determine the extent of thinning at these locations, and

follow-up inspections to confirm the predictions. Repair, replacements, or re-evaluations are

performed 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

BFN audit and review report. Furthermore, the staff reviewed the enhancement and its

justifications to determine whether the AMP, with enhancement, remains adequate to manage

the aging effects for which it is credited.

In the LRA, the applicant stated that the FAC Program will be consistent with GALL

AMP XI.M17, “Flow-accelerated Corrosion.” The staff reviewed the program elements (see SER

Section 3.0.2.1) contained in the AMP basis document and compared them to those listed for

GALL AMP XI.M17 for consistency. The staff also conducted a review of implementing
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procedure 0-TI-140 “BFN Technical Instruction, Monitoring Program for Flow-Accelerated

Corrosion,” Revision 0, 03/15/02. 

Enhancement. In LRA Section B.2.1.15, the applicant identified one enhancement to make this

AMP consistent with GALL AMP XI.M17. The NSAC-202L-R2 recommendations will be

implemented on Unit 1 prior to the period of extended operation. The staff found this

enhancement acceptable since it will make the applicant’s program consistent for all three units.

Operating Experience. In the LRA, the applicant stated that wall-thinning problems in

single-phase systems had occurred in feedwater and condensate systems (NRC IE Bulletin No.

87-01 and INs 81-28, 92-35, and 95-11), in two-phase piping in extraction steam lines (NRC INs

89-53 and 97-84), and in moisture separator and feedwater heater drains (INs 89-53, 91-18,

93-21, and 97-84) throughout the industry.

The applicant’s experience with its FAC Program activities has shown that the program can

determine susceptible locations for FAC, predict component degradation, and detect 

wall-thinning in components due to FAC, thus providing for timely evaluation, repair, or

replacement prior to loss of intended function. When FAC problems have been identified,

corrective actions have been taken to prevent recurrence. For example, extraction steam,

heater drain, and heater vent line piping have experienced wall-thinning due to FAC. This piping

is being replaced, primarily with FAC-resistant materials.

The staff reviewed several PERs that are included in the basis document, and concluded that

implementation of the applicant’s program provides reasonable assurance that loss of material

due to FAC is being adequately managed, such that there is no loss of intended function.

During the onsite audit, the staff noted that the applicant incorporates internal and external

plant operating experience issues into the plant Corrective Action Program on a continuing

basis. The staff concluded there is reasonable assurance that operating experience will

continue to be reviewed in the future to ensure that the effects of aging will be adequately

managed, consistent with the GALL Report.

UFSAR Supplement. In LRA Section A.1.14, the applicant provided the UFSAR supplement for

the FAC Program. The staff reviewed this section and determined that the information in the

UFSAR supplement provides an adequate summary description of the program. The staff found

this section of the UFSAR met the requirements of 10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant’s program, the staff determined

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 enhancement and

confirmed that the implementation of the enhancement prior to the period of extended operation

would result in the existing AMP being consistent with the GALL Report AMP to which it was

compared. The staff concluded that the applicant had demonstrated that the effects of aging

will be adequately managed so that the intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).
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3.0.3.2.10 Bolting Integrity Program

Summary of Technical Information in the Application. The applicant’s Bolting Integrity Program

is described in LRA Section B.2.1.16, “Bolting Integrity Program.” In the LRA, the applicant

stated that this is an existing program. This program is consistent, with exceptions, with GALL

AMP XI.M18, “Bolting Integrity.”

The applicant stated that the Bolting Integrity Program provides for condition monitoring of

selected pressure-retaining bolted joints and external surfaces of piping and components within

the scope of license renewal. The applicant claimed that the Bolting Integrity Program is

consistent with the guidelines of EPRI NP-5769, “Degradation and Failure of Bolting in Nuclear

Power Plants,” and the additional recommendations of NUREG-1339, “Resolution of Generic

Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants,” to prevent or mitigate

degradation and failure of SR bolting. According to the applicant, the Bolting Integrity Program

includes the following AMPs:

 • ASME Code Section XI, Subsections IWB, IWC, and IWD Inservice Inspection Program

for Class 1, 2, and 3 components. (B.2.1.4)

 • Systems Monitoring Program for bolts not included in ASME Code Section XI, Inservice

Inspection Program. (B.2.1.39)

The applicant stated that the Bolting Integrity Program is consistent with GALL XI.M18 with the

following exceptions:

Exception 1. The GALL Report indicates that the program covers all bolting within the

scope of license renewal including structural bolting. The applicant stated that the

Structures Monitoring Program covers aging management of structural bolting.

Exception 2. The GALL Report indicates that the program covers all bolting within the

scope of license renewal including bolting for Class 1 nuclear steam supply system

(NSSS) component supports. The applicant stated that the ASME Code Section XI,

Subsection IWF Program, covers aging management of Class 1 NSSS component

support bolts at the BFN Units.

These two exceptions affect the program elements “Scope of Program “ and “Detection of

Aging Effects.” The applicant evaluated the exceptions in LRA Appendix B and stated that

structural bolting is addressed by the Structures Monitoring Program and the ASME Section XI,

Subsection IWF Program. These two AMPs are considered appropriate for managing the aging

of these types of bolting.

The applicant also stated that requirements that are specified in EPRI NP-5769, with the

exceptions noted in NUREG-1339, will be applicable for all SR bolting at the BFN units. The

applicant indicated in the LRA that EPRI TR-104213, “Bolted Joint Maintenance and

Applications Guide,” is used as a basis for evaluation of the structural integrity of NSR bolting.

The inspection requirements that are specified in ASME Code Section XI, Subsections IWB,

IWC, IWD, and EPRI NP-5769 will be used in detecting the aging effects of all SR ASME

Class 1, 2, and 3 bolting, and NSSS component-support bolting. The applicant indicated that

these requirements are consistent with the GALL Report.
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In evaluating AMP B.2.1.16, the applicant stated that continued implementation of the Bolting

Integrity Program provides reasonable assurance that the aging effects will be managed so that

the systems and components within the scope of this program will continue to perform their

intended functions consistent with the CLB for the period of extended operation.

This AMP is credited for managing degradation of bolting in the RCS, engineered safety feature

(ESF), auxiliary, and steam and power conversion systems.

Staff Evaluation. During review, the staff confirmed the applicant’s claim of consistency with the

GALL Report. Furthermore, the staff reviewed the exceptions and their justifications to

determine whether the AMP, with exceptions, remains adequate to manage the aging effects

for which it is credited.

For SR bolting, the GALL Report relies on staff recommendations and guidelines for a

comprehensive Bolting Integrity Program delineated in NUREG-1339 "Resolution of Generic

Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants," and industry's

technical basis for the program and guidelines in regard to material selection and testing,

bolting preload control, ISI, plant operation and maintenance, and evaluation of structural

integrity of bolted joints outlined in EPRI NP-5769, with the exceptions noted in NUREG-1339.

These requirements are consistent with NUREG 1801 Section XI.M18, and staff found them

acceptable. Since there are no high-strength low-alloy steel bolts (yield strength greater than

150 ksi) at the BFN units, aging effects due to SCC is not credible and can be excluded from

the AMP. 

With regard to NSR bolting, the applicant stated that it will comply with the aging management

attributes delineated in EPRI TR-104213 including material procurement, use of approved

lubricants and sealants, proper torquing, and leakage evaluations. The staff found the

applicant's Bolting Integrity Program for NSR bolting consistent with the recommendations in

the GALL and the standards delineated in EPRI TR-104213.

The LRA states that the Bolting Integrity Program does not include bolting for Class 1 NSSS

component-support bolts. The applicant stated that there are no high-strength bolts (yield

strength greater than 150 ksi) in NSSS component supports. The staff evaluated this attribute

and found it acceptable.

The staff previously accepted the use of periodic ISI of closure bolting as an acceptable AMP

for loss of mechanical closure integrity, since failure of the mechanical joint, as evidenced by

leakage, can be attributed to loss of material, cracking of bolting materials, or loss of preload.

The staff determined that periodic ASME Code Section XI ISI and plant preventive maintenance

programs as described in NUREG-1339 and EPRI NP-5769 can be effectively relied upon to

identify loss of closure integrity for bolted assemblies. Therefore, the applicant’s management

of loss of mechanical closure integrity is adequate for managing the aging effects of loss of

material, cracking, and loss of preload. The staff determined that the applicant demonstrated its

compliance with all the attributes of GALL AMP XI.M18 for bolting in the RCS with exceptions.

The staff reviewed these exceptions, and concluded that they do not have any technical impact

on the effectiveness of managing the aforementioned aging effects of the bolts in the RCS.

Therefore, the staff concluded that by implementing the Bolting Integrity Program, which is

consistent with GALL, the aging effects of the bolting in the RCS will be effectively managed in

a timely manner for the period of extended operation. 
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The staff’s review of the applicant’s program for managing the effects of aging on structural

bolting and bolting in Class 1 NSSS component supports is provided in the discussion in the

SER regarding ASME Code Section XI Subsection IWF Program and Structures Monitoring

Program respectively.

Operating Experience. In evaluating the program element, the applicant stated in LRA

Appendix B that the BWR fleet of plants, including BFN, has experienced bolting degradation

issues. The industry and BFN has implemented a Bolting Integrity Program, which adequately

detected bolting integrity issues (degradation of bolting material). The Bolting Integrity Program

has been effective at detecting degradation of bolting and corrective actions have been taken

prior to the loss of its intended function. BFN uses no high strength bolts (actual yield strength

>150 ksi).

UFSAR Supplement. In LRA Section A.1.15, the applicant provided the UFSAR supplement for

the Bolting Integrity Program. The staff reviewed this section and determined that the

information in the UFSAR supplement provides an adequate summary description of the

program. The staff found this section of the UFSAR supplement met the requirements of

10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant’s program, the staff determined

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 concluded that the applicant had

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP

and concluded that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.0.3.2.11 Open-Cycle Cooling Water System Program

Summary of Technical Information in the Application. The applicant’s Open-Cycle Cooling

Water (OCCW) System Program is described in LRA Section B.2.1.17, “Open-Cycle Cooling

Water System Program.” In the LRA, the applicant stated that this is an existing program. This

program is consistent, with enhancement, with GALL AMP XI.M20, “Open-Cycle Cooling Water

System.”

The OCCW System Program relies on implementation of the recommendations of GL 89-13 to

ensure that the effects of aging on the OCCW system will be managed for the extended period

of operation. The program includes surveillance and control techniques to manage aging

effects caused by biofouling, corrosion, erosion, protective coating failures, and silting in the

OCCW system or structures and components serviced by the OCCW system.

Implementation of GL 89-13 activities provides for management of aging effects due to loss of

material, fouling due to micro- or macro-organisms, and heat transfer aging effects in raw water

cooling water systems. The applicant does not utilize protective coatings in any raw water

systems, as addressed in IN 85-24. Therefore, protective coating failures do not apply to BFN.
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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

BFN audit and review report. Furthermore, the staff reviewed the enhancement and its

justifications to determine whether the AMP, with the enhancement, remains adequate to

manage the aging effects for which it is credited.

The staff reviewed the program elements (see SER Section 3.0.2.1) contained in the OCCW

System Program and associated bases documents, and compared them to those listed for

GALL AMP XI.M20 report for consistency. The staff also reviewed selected implementing

procedures, including Standard Program and Process (SPP)-9.7, “Corrosion Control Program,”

Rev. 6, which establishes the engineering requirements, details, and strategies to control

corrosion of plant systems, components, equipment and structures, and the responsibilities and

methodologies utilized to identify, monitor, trend, and control corrosion.

Based on its review, the staff found that the program elements of the OCCW System Program

are consistent with GALL AMP XI.M20.

Enhancement. In LRA Section B.2.1.17, the applicant identified one enhancement to make this

AMP consistent with GALL AMP XI.M20. GL 89-13 will be implemented on Unit 1 prior to the

period of extended operation. The staff found this enhancement acceptable since it will make

the applicant’s program consistent for all three units.

Operating Experience. In LRA Section B.2.1.17, the applicant stated that it has been

implementing the guidance of GL 89-13 for approximately 10 years, and found the guidance to

be effective in managing aging effects due to biofouling, corrosion, erosion, pitting, and silting in

structures and components serviced by OCCW systems.

The raw water fouling and corrosion control program inspection and testing activities have

detected and evaluated the presence of biofouling, corrosion, microbiologically influenced

corrosion (MIC), and silting. The system and component corrective actions were implemented

prior to loss of system function. The raw water fouling and corrosion control program activities

adequately manage the aging effects of loss of material, cracking, pitting, flow blockage, and

reduction of heat transfer in components exposed to raw cooling water.

The staff concluded that implementation of the applicant’s program provides reasonable

assurance that aging effects due to biofouling, corrosion, erosion, pitting, and silting in

structures and components serviced by OCCW systems are being adequately managed, such

that there is no loss of intended function.

During the onsite audit, the staff noted that the applicant incorporates internal and external

plant operating experience issues into the plant Corrective Action Program on a continuing

basis. The staff concluded there is reasonable assurance that operating experience will

continue to be reviewed in the future to ensure that the effects of aging will be adequately

managed, consistent with the guidance in the GALL Report.
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UFSAR Supplement. In LRA Section A.1.16, the applicant provided the UFSAR supplement for

the OCCW System Program. The staff reviewed this section and determined that the

information in the UFSAR supplement provides an adequate summary description of the

program. The staff found this section of the UFSAR supplement met the requirements of

10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant’s program, the staff determined

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 enhancement and

confirmed that the implementation of the enhancement prior to the period of extended operation

would result in the existing AMP being consistent with the GALL Report AMP to which it was

compared. The staff concluded that the applicant had demonstrated that the effects of aging

will be adequately managed so that the intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

 3.0.3.2.12 Closed-Cycle Cooling Water System Program

Summary of Technical Information in the Application. The applicant’s Closed-Cycle Cooling

Water (CCCW) System Program is described in LRA Section B.2.1.18, “Closed-Cycle Cooling

Water System Program.” In the LRA, the applicant stated that this is an existing program. This

program is consistent, with an enhancement, with GALL AMP XI.M21, “Closed-Cycle Cooling

Water System.”

The CCCW System Program includes preventive measures to minimize corrosion and

surveillance testing and inspection to monitor the effects of corrosion on the intended function

of the component. The program relies on maintenance of system corrosion inhibitor

concentrations within specified limits of EPRI TR-107396, “Closed Cooling Water Chemistry

Guideline,” to minimize corrosion. Surveillance testing and inspection in accordance with

standards in EPRI TR-107396 for CCCW systems is performed to evaluate system and

component performance. These measures will ensure that the CCCW system and components

serviced by the CCCW system are performing their functions acceptably.

CCCW System Program will be enhanced to implement EPRI TR-107396 for Unit 1 prior to the

period of extended operation.

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

BFN audit and review report. Furthermore, the staff reviewed the enhancement and its

justifications to determine whether the AMP, with the enhancement, remains adequate to

manage the aging effects for which it is credited.

The staff reviewed the program elements (see SER Section 3.0.2.1) contained in the CCCW

System Program and associated bases documents, and compared them to those listed for

GALL AMP XI.M21 for consistency.

The staff also reviewed the applicant’s implementing procedures, including Browns Ferry

Chemical Instruction CI-13.1, and “Browns Ferry Nuclear Plant Chemistry Program,”
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Revision 17, which incorporates EPRI TR-107396, “Closed Cooling Water Chemistry

Guidelines.” Appendix A of that procedure provides water quality control specifications for the

reactor building closed-cooling water system, drywell outage chiller (when inservice), off-gas

chiller systems, closed-building heating, generator stator cooling water, diesel generator cooling

water, and control bay chiller systems. The parameter monitored, monitoring frequency,

administrative goal, and action levels for corrective actions are identified for each system.

The staff’s review determined that the applicant’s CCCW systems program monitors the effects

of corrosion by system chemistry sampling, chemical treatment and water chemistry trending in

accordance with the Water Chemistry Program. The chemistry parameters are monitored and

maintained in accordance with the BFN chemistry specifications and recommendations of EPRI

TR-107396. The parameters monitored include nitrate, pH, conductivity, tolyltriazole, bacteria

(aerobic and SRBs ), sulfates, metals (iron, copper), ammonia, chloride, calcium, molybate, and

glycol (weight percent). If parameter limits are exceeded, the chemistry control procedures

require corrective action to be taken to restore parameters to within the acceptable range.

Maintenance of water chemistry and corrosion inhibitor levels within the chemistry parameters

mitigate loss of material, cracking, and reduction of heat transfer. In addition, regular scheduled

system flow balances, pump suction and discharge pressure, heat exchanger flows, and

temperatures and maintenance inspections are performed on system/components to detect,

monitor, control, and minimize corrosion aging effects. The system heat exchangers are also

cleaned and inspected to detect, monitor, control, and minimize corrosion aging effects that

could cause a reduction of heat transfer. 

Based on its review, the staff found that the program elements of the CCCW System Program

are consistent with GALL AMP XI.M21.

Enhancement. In LRA Section B.2.1.18, the applicant identified one enhancement to make this

AMP consistent with GALL AMP XI.M21. EPRI TR-107396 will be implemented on Unit 1 prior

to the period of extended operation. The staff found this enhancement acceptable since it will

make the applicant’s program consistent for all three units.

Operating Experience. In the LRA, the applicant stated that industry operating experience

demonstrates that the use of corrosion inhibitors in closed-cooling water systems that are

monitored and maintained by chemistry activities is effective in mitigating loss of material,

cracking, and reduction of heat transfer. The BFN CCCW systems have not experienced a loss

of intended function of components due to corrosion product buildup or through-wall cracking of

components. The CCCW systems inspection and testing have detected loss of material and

corrosion product buildup. These aging effects were identified and corrected prior to loss of

system functions.

The staff concluded that implementation of the applicant’s program provides reasonable

assurance that loss of material, cracking, and reduction of heat transfer in CCCW systems are

being adequately managed such that there is no loss of intended function.

During the onsite audit, the staff noted that the applicant incorporates internal and external

plant operating experience issues into the plant Corrective Action Program on a continuing

basis. The staff concluded there is reasonable assurance that operating experience will

continue to be reviewed in the future to ensure that the effects of aging will be adequately

managed, consistent with the guidance in the GALL Report.
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UFSAR Supplement. In LRA Section A.1.17, the applicant provided the UFSAR supplement for

the CCCW System Program. The staff reviewed this section and determined that the

information in the UFSAR supplement provides an adequate summary description of the

program. The staff found this section of the UFSAR supplement met the requirements of

10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant’s program, the staff determined

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 enhancement and

confirmed that the implementation of the enhancement prior to the period of extended operation

would result in the existing AMP being consistent with the GALL Report AMP to which it was

compared. The staff concluded that the applicant had demonstrated that the effects of aging

will be adequately managed so that the intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.13 Inspection of Overhead Heavy Load and Light Load Handling Systems Program

Summary of Technical Information in the Application. The applicant’s Inspection of the

Overhead Heavy Load and Light Load Handling Systems Program is described in LRA

Section B.2.1.20, “Inspection of Overhead Heavy Load and Light Load Handling Systems

Program.” In the LRA, the applicant stated that this is an existing program. This program is

consistent, with an exception, with GALL AMP XI.M23, “Inspection of Overhead Heavy Load

(Related to Refueling) and Light Load Handling Systems.”

In LRA Section B.2.1.20, the applicant stated that Inspection of the Overhead Heavy Load and

Light Load Handling Systems Program includes crane inspection activities to verify the

structural integrity of the crane components required to maintain the crane intended function.

Visual inspections assess conditions such as loss of material due to corrosion of structural

members, misalignment, flaking, side wear of rails, loose tie-down bolts, and excessive wear or

deformation of monorails. Crane functional tests are periodically performed to assure the

cranes capability. The effectiveness of the program is monitored in accordance with the

guidance of RG 1.160, “Monitoring the Effectiveness of Maintenance at Nuclear Power Plants.”

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

BFN audit and review report. Furthermore, the staff reviewed the exception and its justifications

to determine whether the AMP, with the exception, remains adequate to manage the aging

effects for which it is credited.

The staff reviewed the program elements (see SER Section 3.0.2.1) contained in the Inspection

of the Overhead Heavy Load and Light Load Handling Systems Program and associated bases

documents, and compared them to those listed for GALL AMP XI.M23 for consistency.

In LRA Section B.2.1.20, the applicant identified an exception to GALL AMP XI.M23 that affects

GALL Report element Parameters Monitored/Inspected. Reactor building crane fatigue was

evaluated as a TLAA in LRA Section 4.7.1. The disposition of the TLAA is that the analyses are

valid through the period of extended operation because the 60-year 7,500-cycle estimate
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remains a small fraction of the 100,000 cycle design. Therefore, the applicant stated that aging

management of crane fatigue is not required. 

Exception. The staff evaluation of the affected GALL Report program element, “Parameters

Monitored/Inspected” (Element 3), for the acceptability of the exception is as follows:

Parameters Monitored/Inspected. 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 staff found this exception acceptable on the basis that the crane is designed for 100,000 

lift-cycles, compared to the applicant’s 60-year estimate of 7,500 cycles (1.5 times 40-year

estimate of 5,000 cycles), as documented in LRA Section 4.7.1. The staff found that, with

evaluation of the exception discussed below, the program elements reviewed for the Inspection

of the Overhead Heavy Load and Light Load Handling Systems Program are consistent with

GALL AMP XI.M23.

Operating Experience. In the Inspection of the Overhead Heavy Load and Light Load Handling

Systems Program basis document, the applicant stated that no incidents of failure of passive

crane and hoist components due to aging have occurred at Browns Ferry. The requirements for

monitoring the effectiveness of maintenance at nuclear power plants provided in 10 CFR 50.65

have been incorporated into the Maintenance Rule Program procedures.

The staff concluded that the crane inspection program activities, implemented as part of the

Maintenance Rule Program, provide reasonable assurance that the intended functions of crane

and hoist passive components will be maintained during the period of extended operation.

During the onsite audit, the staff noted that the applicant incorporates internal and external

plant operating experience issues into the plant Corrective Action Program on a continuing

basis. The staff concluded there is reasonable assurance that operating experience will

continue to be reviewed in the future to ensure that the effects of aging will be adequately

managed, consistent with the guidance in the GALL Report.

UFSAR Supplement. In LRA Section A.1.18, the applicant provided the UFSAR supplement for

the Inspection of Overhead Heavy Load and Light Load Handling Systems Program. The staff

reviewed this section and determined that the information in the UFSAR supplement provides

an adequate summary description of the program. The staff found this section of the UFSAR

supplement met the requirements of 10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant’s program, the staff determined

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 exception and the

associated justifications and determined that the AMP, with the exception, is adequate to

manage the aging effects for which it is credited. The staff concluded that the applicant had

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP
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and concluded that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.0.3.2.14 Compressed Air Monitoring Program

Summary of Technical Information in the Application. The applicant’s Compressed Air

Monitoring Program is described in LRA Section B.2.1.21, “Compressed Air Monitoring

Program.” In the LRA, the applicant stated that this is an existing program. This program is

consistent, with enhancements, with GALL AMP XI.M24, “Compressed Air Monitoring.”

The Compressed Air Monitoring Program will be enhanced prior to the period of extended

operation to include program and procedure upgrades that will be credited for license renewal,

to ensure that the applicable aging effects are discovered and evaluated. Also, the Unit 1

control air system procedures will be updated to fully implement the compressed air monitoring

program on Unit 1, prior to Unit 1 re-start from its current extended outage.

The Compressed Air Monitoring Program consists of condition monitoring (inspection and

testing of the system) and preventive actions (air quality at various locations in the system is

monitored to ensure that oil, water, rust, dirt, and other contaminants are kept within specified

limits). The program includes inspection, monitoring, and testing of the entire system, including

frequent leak testing of valves, piping, and other system components, especially those made of

carbon steel, and preventive monitoring that checks air quality at various locations in the

system to ensure that oil, water, rust, dirt, and other contaminants are kept within the specified

limits.

The Compressed Air Monitoring Program is based on GL 88-14, “Instrument Air Supply System

Problems Affecting Safety-Related Equipment,” and the Institute of Nuclear Power Operations

(INPO) Significant Operating Experience Report (SOER) 88-01, “Instrument Air System

Failures.” The AMP also incorporates provisions conforming to the guidance of the EPRI 

NP-7079, issued in 1990 to assist utilities in identifying and correcting system problems in the

instrument air system and to enable them to maintain required industry safety standards.

Additionally, the Compressed Air Monitoring Program will be upgraded to implement these

guidelines of EPRI TR-108147, which addresses maintenance of the latest compressors and

other instrument air system equipment in use, and the ASME Code operations and

maintenance standards and guides (ASME Code OM-S/G-1998, Part 17), which provide

additional guidance for the maintenance of the instrument air system, including recommended

test methods, test intervals, parameters to be measured and evaluated, acceptance criteria,

corrective actions, and records requirements.

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

BFN audit and review report. Furthermore, the staff reviewed the enhancements and their

justifications to determine whether the AMP, with the enhancements, remains adequate to

manage the aging effects for which it is credited.

In LRA Section B.2.1.21, the applicant indicated that the Compressed Air Monitoring Program

requires implementation of two enhancements to achieve consistency with GALL AMP XI.M24

for all three units.
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Enhancement 1. The staff evaluation of the affected GALL Report program elements,

“Preventive Actions” (Element 2) and “Detection of Aging Effects” (Element 3), for the

acceptability of the enhancement is as follows:

Preventive Actions - The system air quality is monitored and maintained in accordance

with the plant owner’s testing and inspection plans, which are designed to ensure that

the system and equipment meet specified operability requirements. These requirements

are prepared from consideration of manufacturer’s recommendations for individual

components and guidelines based on ASME Code OM-S/G-1998, Part 17;

ISA-S7.0.01-1996; EPRI NP-7079; and EPRI TR-108147. The preventive maintenance

program addresses various aspects of the inoperability of air-operated components due

to corrosion and the presence of oil, water, rust, and other contaminants.

Detection of Aging Effects - Guidelines in EPRI NP-7079, EPRI TR-108147, and ASME

Code OM-S/G-1998, Part 17, ensure timely detection of degradation of the compressed

air system function. Degradation of the piping and any equipment would become evident

by observation of excessive corrosion, by the discovery of unacceptable leakage rates,

and by failure of the system or any item of equipment to meet specified performance

limits.

Enhancement 2. Unit 1 control air system procedures will be updated to fully implement the

Compressed Air Monitoring Program on Unit 1. This enhancement is scheduled for completion

prior to Unit 1 re-start from its current extended outage.

For all units, the Compressed Air Monitoring Program will be upgraded to implement the

following guidelines: ASME Code OM-S/G-2000, Part 17, “Performance Testing of Instrument

Air Systems in Light-Water Reactor Power Plants”; ANSI/ISA-S7.0.01-1996, “Quality Standard

for Instrument Air”; and EPRI TR-108147, “Compressor and Instrument Air System

Maintenance Guide.” This enhancement is scheduled for completion prior to the start of the

period of extended operation.

The staff concurred that with the implementation of these enhancements the Compressed Air

Monitoring Program will be consistent with GALL AMP XI.M24 for all three units.

Operating Experience. In LRA Section B.2.1.21, the applicant stated that, through air quality

testing and sampling of the compressed air systems, various contaminants such as moisture,

oil, and particulates, have been identified above acceptable levels, as documented in the staff’s

BFN audit and review report. Appropriate corrective actions have been taken. 

Potentially significant SR problems pertaining to air systems have been documented in IN

81-38, IN 87-28, IN 87-28 S1 and licensee event report (LER) 50-237/94-005-3. As a result of

GL 88-14 and consideration of INPO SOER 88-01, EPRI NP-7079, and EPRI TR-108147,

performance of air systems has improved significantly.

The applicant stated that GL 88-14, IN 81-38, IN 87-28, IN 87-28 S1, INPO SOER 88-01 and

EPRI NP-7079 had been adequately addressed and that the control air system performance

has improved significantly as a result of GL 88-14, and consideration of INPO SOER 88-01 and

EPRI NP-7079. In addition, the control air leak detection program has been effective in

detecting leaks and implementing repairs prior to loss of system function. The air quality
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sampling program effectively monitors the system for moisture, oil, and particulates. This

ensures timely repairs prior to degradation to the point of loss of intended function.

The applicant also identified that the drywell control air system has a trend of moisture

problems, which has required considerable attention. To address the current operating

deficiencies identified in the drywell control air system, the applicant plans to convert the drywell

control air to nitrogen supply on all three units. This conversion has already been initiated for

Unit 1. The staff noted that this plant modification addresses a current operating problem, and

is not related to any license renewal commitment.

The staff concluded that implementation of the applicant’s program provides reasonable

assurance that age-related degradation of compressed air systems is being adequately

managed, such that there is no loss of intended function.

During the onsite audit, the staff noted that the applicant incorporates internal and external

plant operating experience issues into the plant Corrective Action Program on a continuing

basis. The staff concluded there is reasonable assurance that operating experience will

continue to be reviewed in the future to ensure that the effects of aging will be adequately

managed, consistent with the guidance in the GALL Report.

UFSAR Supplement. In LRA Section A.1.19, the applicant provided the UFSAR supplement for

the Compressed Air Monitoring Program. The staff reviewed this section and determined that

the information in the UFSAR supplement provides an adequate summary description of the

program. The staff found this section of the UFSAR supplement met the requirements of

10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant’s program, the staff determined

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 enhancement and

confirmed that the implementation of the enhancement prior to the period of extended operation

would result in the existing AMP being consistent with the GALL Report AMP to which it was

compared. The staff concluded that the applicant had demonstrated that the effects of aging

will be adequately managed so that the intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.15 BWR Reactor Water Cleanup System Program

Summary of Technical Information in the Application. The applicant’s BWR Reactor Water

Cleanup System Program is described in LRA Section B.2.1.22, “BWR Reactor Water Cleanup

System Program.” In the LRA, the applicant stated that this is an existing program. This

program is consistent, with an enhancement, with GALL AMP XI.M25, “BWR Reactor Water

Cleanup System Program.” This program will be enhanced to implement the BWRVIP

guidelines, GL 88-01, and GL 89-10 for Unit 1 prior to the period of extended operation.

The BWR Reactor Water Cleanup System Program includes inservice inspection and

monitoring for reactor water cleanup (RWCU) system piping welds outboard of the second

isolation valve and monitors and controls reactor water chemistry based on industry-recognized
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guidelines of EPRI Report TR-103515, “BWR Water Chemistry Guidelines (BWRVIP-79),"

prevents, minimizes, mitigates, and reduces the susceptibility of RWCU system piping to SCC

and IGSCC. 

On Units 2 and 3, RWCU system piping has been replaced with piping that is resistant to

IGSCC in response to GL 88-01, “NRC Position on Intergranular Stress Corrosion Cracking

(IGSCC) in BWR Austenitic Stainless Steel Piping," concerns. In addition, all actions requested

in GL 89-10, “Safety-Related Motor-Operated Valve Testing and Surveillance,” have been

completed.

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

BFN audit and review report. Furthermore, the staff reviewed the enhancement and its

justifications to determine whether the AMP, with the enhancement, remains adequate to

manage the aging effects for which it is credited.

The staff reviewed the program elements (see SER Section 3.0.2.1) contained in the BWR

Reactor Water Cleanup System Program and associated bases documents, and compared

them to those listed for GALL AMP XI.M25 for consistency.

The staff also reviewed selected implementing procedures, including CI-13.1, “Chemistry

Program.” This instruction details specific requirements for the chemistry program. This

chemical instruction establishes how the chemistry program is implemented and provides

specifications to maximize long-term plant availability, minimize environmental impact, and

minimize worker radiation exposure. Controlling water quality through control of ingress and

cleanup system optimization limits corrosion, minimizes radioactive inventory, and minimizes

radioactive releases to the environment. The requirements of this instruction apply to all

aspects of the chemistry program associated with BFN and supporting facilities. This instruction

defines the minimum requirements for the site and corporate chemistry programs as they apply

to BFN. This includes incorporation of EPRI TR-103515, Revision 2 guidelines. In addition,

HWC must be installed for mitigation of IGSCC, which will include the RWCU system for Unit 1.

The staff found that the program elements reviewed for BWR Reactor Water Cleanup System

Program are consistent with GALL AMP XI.M25.

Enhancement. In LRA Section B.2.1.22, the applicant identified one enhancement to

make this AMP consistent with GALL AMP XI.M25. On Unit 1 the recommendations of

GL 88-01 and NUREG-0313 will be implemented and the actions requested in GL 89-10

will be satisfactorily completed. These enhancements are scheduled for completion prior

to the period of extended operation.

The staff found that with the implementation of this enhancement the BWR Reactor Water

Cleanup System Program will be consistent with GALL AMP XI.M25 for all three BFN units.

Operating Experience. In LRA Section B.2.1.22, the applicant stated that IGSCC has occurred

in boiling water reactor piping made of austenitic stainless steel. The comprehensive program

outlined in GL 88-01 and NUREG-0313 addresses improvements in managing the elements

(susceptible material, significant tensile stress, and an aggressive environment) that cause
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SCC or IGSCC, and has been effective in managing IGSCC in austenitic stainless steel piping

in the RWCU system.

The applicant identified that the applicant experienced IGSCC in the past with piping made of

austenitic stainless steel. The following measures that have been implemented have proven

effective at managing IGSCC in austenitic stainless steel piping in the RWCU system: (1)

replacement of IGSCC-susceptible material with IGSCC-resistant material, (2) establishment of

a HWC program, and (3) water chemistry controls in accordance with EPRI guidelines.

The staff concluded that implementation of the recommendations of GL 88-01 and

NUREG-0313 and the actions requested in GL 89-10 provides reasonable assurance that

cracking of austenitic stainless steel piping in the RWCU system is being adequately managed,

such that there is no loss of intended function.

During the onsite audit, the staff noted that the applicant incorporates internal and external

plant operating experience issues into the plant Corrective Action Program on a continuing

basis. The staff concluded there is reasonable assurance that operating experience will

continue to be reviewed in the future to ensure that the effects of aging will be adequately

managed, consistent with the guidance in the GALL Report.

UFSAR Supplement. In LRA Section A.1.20, the applicant provided the UFSAR supplement for

the BWR Reactor Water Cleanup System Program. The staff reviewed this section and

determined that the information in the UFSAR supplement provides an adequate summary

description of the program. The staff found this section of the UFSAR supplement met the

requirements of 10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant’s program, the staff determined

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 enhancement and

confirmed that the implementation of the enhancement prior to the period of extended operation

would result in the existing AMP being consistent with the GALL Report AMP to which it was

compared. The staff concluded that the applicant had demonstrated that the effects of aging

will be adequately managed so that the intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.16 Fire Protection Program

Summary of Technical Information in the Application. The applicant’s Fire Protection Program is

described in LRA Section B.2.1.23, “Fire Protection Program.” In the LRA, the applicant stated

that this is an existing program. This program is consistent, with exceptions and enhancement,

with GALL AMP XI.M26, “Fire Protection Program.”

The applicant stated in the LRA that the Fire Protection Program manages the aging effects of

loss of material, cracking, and change of material properties for plant fire protection features

and components. The program manages these aging effects through the use of periodic

inspections and tests. The Fire Protection Program includes fire barrier inspections and

diesel-driven fire pump tests. Fire protection inspections and tests are mandated by the Fire
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Protection Report (FPR) Volume 1, which is incorporated by reference into UFSAR 10.11. The

FPR requires periodic visual inspection of fire barrier penetration seals, fire barrier walls,

ceilings, and floors, and periodic visual inspection of fire-rated doors to ensure that their

operability is maintained. The FPR requires that the diesel-driven fire pump be periodically

tested to ensure that the fuel supply line can perform the intended function. The FPR also

includes periodic inspection and test of the carbon dioxide fire suppression 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 its

BFN audit and review report. Furthermore, the staff reviewed the exceptions and enhancement

and their justifications to determine whether the AMP, with the exceptions and enhancement,

remains adequate to manage the aging effects for which it is credited.

Exception 1. Personnel performing fire seal and fire door inspections are not qualified to VT-1

and VT-3 requirements.

The staff’s review of LRA Section B.2.1.23 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. 

In RAI B.2.0.2, dated August 23, 2004, the staff questioned the exception to the GALL Report

regarding the qualifications of the personnel performing the inspections of fire barriers,

penetration seals, and fire doors who are not qualified to VT-1 and VT-3 requirements. In the

LRA the applicant had stated that the personnel performing these inspections are trained and

experienced in the fire protection requirements and that the quality of the inspections is

equivalent to VT-1 and VT-3 inspections. FPR Section 9.4.11.G discussed semi-annual

inspection of fire doors including a check of closers and latching mechanisms. The staff also

requested justifications for specific exceptions taken to the GALL Report AMP on fire doors.

The GALL Report recommends verification of door clearances to assure the door can perform

in a fire and remain latched. The staff further requested additional information concerning how

a visual inspection can verify proper closure of latching mechanism and asked the applicant to

confirm that the frequency of this surveillance is consistent with the FPR.

Fire Protection Report Volume1 Fire Protection Systems Surveillance Requirement 9.4.11.D,

CO2 systems, mandates the CO2 systems' requirements for demonstrating operability. This test

stipulates that the system, including associated ventilation system fire dampers and fire door

release mechanisms, actuates manually and automatically upon receipt of a simulated

actuation signal, and verify flow from each nozzle through a puff test. 

In its response, by letter September 30, 2004, the applicant stated:

Surveillance Instruction (SI) 0-SI-4.11.G.2, Semiannual Fire Door Inspection is

discussed in the AMP and is being credited as one of the BFN site specific procedures

credited for the Fire Protection Aging Management Program. A SI verifies the required

clearances are maintained and periodic functional tests of closing mechanisms are

performed. The only exception to the GALL in the AMP for fire doors is that inspectors

are not qualified to visual examination (VT-1 and VT-3) requirements. 
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The frequency and inspection of the fire doors is defined in the FPR and the SIs written

to satisfy the requirement. 

The staff reviewed the SI, acceptance criteria, including surveillance requirement 9.4.11.D,

above, and plant operating experience, and concurred the program is adequate for managing

the effect of aging in the fire doors. Therefore, the staff’s concern discussed in RAI B.2.0.2 is

resolved. 

Exception 2. The FPR requires testing and inspection of the CO2 system once every 18 months.

LRA Section B.2.1.23, Element 3 - “Parameters Monitored or Inspected” and Element 4 -

“Detection of Aging Effects,” takes exceptions over the inspection interval to test for the

halon/carbon dioxide fire suppression system every 18 months, instead of biannually as

recommended by the GALL Report. 

The applicant stated that the 18-month frequency is considered sufficient to ensure system

availability and operability based on the plant operating history, and that there has been no

aging-related event that has adversely affected system operation. The 18-month frequency is

included in the CLB. 

The staff reviewed the applicant's FPR basis document, plant operating experience, and fire

surveillance procedures. Because these aging effects occur over a considerable period of time,

the staff concluded that the 18-month inspection interval will be sufficient to detect aging of

CO2.

Enhancement 1. The FPR and procedures will be updated to include Unit 1 as an operating

rather than a shutdown unit. The Fire Protection Program will be fully implemented on Unit 1.

The enhancement is scheduled for completion prior to the period of extended operation

In the LRA, the applicant stated that “with the implementation of this enhancement, BFN will be

consistent with the affected program element for all three units.”

Operating Experience. The applicant reported that operating experience indicates a trend of

piping degradation, such as leaks, general corrosion, and biofouling. Piping is replaced as

required in response to findings of the inspection and testing activities which indicate the need

for corrective actions. 

UFSAR Supplement. In LRA Section A.1.21, the applicant provided the UFSAR supplement for

the Fire Protection Inspection program. The staff reviewed this section and determined that the

information in the UFSAR supplement provides an adequate summary description of the

program. The staff found this section of the UFSAR supplement met 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 program are consistent with the GALL program. 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. Also, the staff has reviewed the

enhancement and confirmed that the implementation of the enhancement prior to the period of
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extended operation and restart of Unit 1 would result in the existing AMP being consistent with

the GALL Report AMP to which it was compared. 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 UFSAR supplement for this AMP

and finds that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.0.3.2.17 Fire Water System Program

Summary of Technical Information in the Application. The applicant’s Fire Water System

Program is described in LRA Section B2.1.24, “Fire Water System Program.” In the LRA, the

applicant stated that this is an existing program. This program is consistent, with the exception

and enhancements, with GALL AMP XI.M27, “Fire Water System,” as modified by ISG-04.

The Fire Water System Program applies to water-based fire protection systems that consist of

sprinklers, nozzles, fittings, valves, hydrants, hose stations, standpipes, water storage tanks,

and aboveground and underground piping and components that are tested in accordance with

the applicable National Fire Protection Association (NFPA) codes and standards. The testing

assures the minimum functionality of the systems. The fire water system tests are mandated by

the FPR Volume 1, which is incorporated by reference into UFSAR 10.11. The Fire Water

System Program is an existing program that takes exceptions to GALL AMP XI.M27 evaluation

elements, as modified by ISG-04, and requires enhancements to be consistent with other GALL

AMP XI.M27 evaluation elements.

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 its

BFN audit and review report. Furthermore, the staff reviewed the exception and enhancements

and their justifications to determine whether the AMP, with the exception and enhancements,

remains adequate to manage the aging effects for which it is credited.

Exception. The applicant takes exception that water-based fire protection systems meet

the inspection, testing and maintenance requirements of current NFPA standards.

However, the Fire Water Program was developed using NFPA as well as other

applicable industry guides and standards and the design of the water-based system

generally meets the applicable NFPA standards. This exception affects the program

elements, “Parameters Monitored or Inspected” (Element 3), “Monitoring and Trending”

(Element 5), and “Operating Experience” (Element 10) which are discussed below.

Parameters Monitored or Inspected and Monitoring and Trending (As modified

by ISG-04) - The GALL Report for this program element specifies that loss of

material due to corrosion and biofouling could reduce wall thickness of the fire

protection piping system and result in system failure. Therefore, the parameters

monitored are the system's ability to maintain pressure and internal system

corrosion conditions. The GALL Report recommends that the applicant perform

periodic flow testing of the fire water system using the guidelines of NFPA 25,

“Standard for the Inspection, Testing, and Maintenance of Water-Based Fire

Protection System” Chapter 13, Annexes A & D at the maximum design flow or

perform wall-thickness evaluations to ensure that the system maintains its
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intended function. In evaluating the program elements, the applicant did not

confirm that periodic flow testing is performed using the guidelines of NFPA 25

as described in the parameters monitored or inspected program element, nor

monitor the results of system performance testing and trending, as specified by

the current NFPA codes and standards and described in the monitoring and

trending program element. However, the Fire Water System Program was

developed using NFPA as well as other applicable industry guides and

standards.

The applicant did not confirm that the water-based fire protection systems are inspected,

tested and maintained in accordance with current NFPA standards. Neither has the

applicant confirmed that the periodic water flow testing meets the requirements of NFPA

25. The staff reviewed SI 0-SI-4.11.B.1.g, “High Pressure Fire Protection System Flow

Test,” Revision 20, and concluded that the extent of the testing, the acceptance criteria,

and the analysis of the test data outlined in the document is detailed and adequate to

assess the ability of the system to perform its intended function. The staff was satisfied

with the review; therefore, the staff found the exception acceptable.

Enhancement 1. In LRA Section B.2.1.24, the applicant proposed an enhancement that

the FPR and procedures will be updated to include Unit 1 as an operating rather than a

shutdown unit. The Fire Water System Program will be fully implemented on Unit 1. This

enhancement is scheduled for completion prior to the period of extended operation. This

enhancement affects the program element “Scope of Program.” 

In evaluating the enhancement, the staff concluded that this enhancement will bring the

AMP common to all units and will be updated to bring Unit 1 to an operating status,

rather than shut down. The enhancement is, hence, acceptable.

Enhancement 2. In LRA Section B.2.1.24, the applicant proposed an enhancement.

BFN will perform flow tests or non-intrusive examinations (e.g., volumetric tests for wall

thickness of fire protection system piping) to identify evidence of loss of material due to

corrosion. The applicant stated that these inspections will be performed before entering

the period of extended operation. This enhancement affects the program elements,

“Parameters Monitored or Inspected” (Element 3) and “Detection of Aging Effects”

(Element 4).

Parameters Monitored or Inspected - In its evaluation, the applicant stated that

the Fire Water System Program monitors parameters that indicate the systems’

ability to maintain pressure and allow detection of internal system corrosion

conditions. The Fire Water System Program requires system and component

testing and inspections as well as periodic flow testing. Wall thickness

evaluations are determined by the system engineer when systems are opened

for maintenance and by pressure tests/leak detection. The Fire Water System

Program includes flow testing and system evaluations to ensure that the system

maintains its intended function. 

The staff evaluated the program element together with the ISG-04 revised

criteria for the GALL AMP XI.M27 for this program element. This revised

guidance no longer recommends the use of GL 89-13 in determining the
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system’s ability to maintain pressure and internal system corrosion conditions.

Rather, ISG-04 recommends either periodic flow testing of the fire water system

using the guidelines of NFPA 25, at the maximum design-flow, or periodic

wall-thickness evaluations to ensure that the system maintains its intended

function. Based on the applicant’s commitment to inspect fire water system

components, the staff determined that the program element is acceptable and

that it complies with ISG-04 recommendations.

.

Detection of Aging Effect - The applicant, in evaluating this element, stated that

the environmental and material conditions that exist on the interior surface of the

below grade fire water system piping are similar to the conditions that exist within

the above-grade fire water system piping. The results of the inspections of the

above grade fire water system piping will be extrapolated to evaluate the

condition of below-grade fire water system piping to ensure that the intended

function of below-grade fire water system piping will be maintained consistent

with the CLB for the period of extended operation. Repair and replacement

actions are initiated as necessary. The plant-specific inspection intervals are to

be determined by engineering evaluation of the fire protection piping to detect

degradation prior to the loss of intended function. The purpose is to ensure that

corrosion, MIC, or biofouling is managed such that the system function is

maintained. With the implementation of this enhancement, BFN will be

consistent with the affected program elements, except for the exception

previously described for the “Parameters Monitored or Inspected” element.

Based on the above evaluation of the two program elements,. the staff found that

enhancement 2 is acceptable.

Enhancement 3. In LRA Section B.2.1.24, the applicant proposed an enhancement; that

BFN will perform sprinkler head inspections before the end of the 50-year sprinkler head

service life and at 10-year intervals thereafter during the period of extended operation to

ensure that signs of degradation, such as corrosion, are detected in a timely manner.

This enhancement is scheduled for completion prior to exceeding the 50-year service

life for any sprinkler. This enhancement affects the program element “Detection of Aging

Effects” (Element 4).

Detection of Aging Effects - GALL AMP XI.M27 contains the criteria for the

program element “Detection of Aging Effects.” The applicant in evaluating this

element affected stated that a sample of sprinkler heads will be inspected using

the guidance of NFPA 25, 2002 Edition, Section 5.3.1.1.1. This NFPA section

states that “where sprinklers have been in place for 50 years, they shall be

replaced or representative samples from one or more sample areas shall be

submitted to a recognized testing laboratory for field service testing.” It also

contains guidance to perform this sampling every 10 years after the initial field

service testing.

In evaluating this program element, the staff stated that ISG-04 revised criteria

for the GALL AMP XI.M27 "Detection of Aging Effects” program element

recommends sprinkler head inspections before the end of the 50-year sprinkler

head service life and at 10-year intervals thereafter during the period of extended
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operation to ensure that signs of degradation are detected in a timely manner.

Based on the revised GALL Report criteria in ISG-04, and the applicant’s

commitment to rely upon applicable codes and standards to develop test

procedures, the staff determined enhancement 3 to be acceptable. 

Operating Experience. In LRA Section B.2.1.24, the applicant stated that the fire water system

parameters are monitored and tested, and that piping and component evaluations are

performed to ensure that the system maintains its intended function. The BFN Fire Water

System operating experience indicates a trend of piping degradation, such as leaks, general

corrosion, and biofouling, etc. Piping is being replaced, as required, in accordance with

corrective actions of the inspection and testing activities. The applicant also stated that the

continued implementation of the Fire Water System Program provides reasonable assurance

that aging effects will be managed so that the systems and components within the scope of this

program will continue to perform their intended functions consistent with the CLB for the period

of extended operation. 

UFSAR Supplement. In LRA Section A.1.22, the applicant provided the UFSAR supplement for

the Fire Water System Program. The staff reviewed this section and determined that the

information in the UFSAR supplement provides an adequate summary description of the

program. The staff found this section of the UFSAR supplement met the requirements of

10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant’s program, the staff determined

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 exception and the

associated justifications and determined that the AMP, with exceptions, is adequate to manage

the aging effects for which it is credited. Also, the staff reviewed the enhancements and

confirmed that the implementation of the enhancements prior to the period of extended

operation would result in the existing AMP being consistent with the GALL Report AMP to which

it was compared. The staff concluded that the applicant had demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff

also reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.18 Fuel Oil Chemistry Program

Summary of Technical Information in the Application. The applicant’s Fuel Oil Chemistry

Program is described in LRA Section B.2.1.27, “Fuel Oil Chemistry Program.” In the LRA, the

applicant stated that this is an existing program. This program is consistent, with two exceptions

(TVA submittal dated September 14, 2006), with GALL AMP XI.M30, “Fuel Oil Chemistry

Program.”

In LRA Section B.2.1.27, the applicant stated that the Fuel Oil Chemistry Program consists of

surveillance and maintenance procedures to mitigate corrosion, and measures to verify the

effectiveness of the AMP and to confirm the absence of an aging effect. Fuel oil quality is

maintained by monitoring and controlling fuel oil contamination in accordance with the

guidelines of the American Society for Testing Materials (ASTM) Standards D 1796, D 2276,

and D 4057. Exposure to fuel oil contaminants, such as water and microbiological organisms, is
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minimized by periodic draining of water or cleaning of tanks and by verifying the quality of new

oil before its introduction into the storage tanks. Procedures require performance of fuel oil tank

bottom and multi-level sampling on a quarterly basis to detect and remove water and sediment

from each tank. In addition, each 7-day diesel oil supply tank is cleaned and inspected at

intervals of approximately 10 years. A one-time inspection in accordance with the One-Time

Inspection Program (B.2.1.29) will be performed prior to entering the period of extended

operation and will consist of thickness measurements of the 7-day diesel oil supply tanks and

diesel driven fire pump fuel oil tank bottom surface.

The applicant also stated that this program provides a general description of items to be

included within the scope of the program, but does not specifically identify the 7-day diesel oil

supply tank as an item to be inspected.

Portions of the Fuel Oil Chemistry Program are mandated by TS 5.5.9, “Diesel Fuel Oil Testing

Program,” that requires a diesel fuel oil testing program to implement required testing of the fuel

oil in each 7-day fuel oil tank. The purpose of the program is to establish that the quality of the

fuel oil in each 7-day fuel oil tank is within the acceptable limits specified in Table 1 of ASTM

D-975-1989 when tested every 92 days; and total particulate concentration of the fuel oil in

each 7-day fuel oil tank is less than 10 mg/l, when tested every 92 days in accordance with

ASTM D-2276, Method A-2 or A-3.

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 its

BFN audit and review report. Furthermore, the staff reviewed the exception and justification to

determine whether the AMP, with the exception, remains adequate to manage the aging effects

for which it is credited.

The staff reviewed the program elements (see SER Section 3.0.2.1) contained in the Fuel Oil

Chemistry Program and associated bases documents, and compared them to those listed for

AMP XI.M30 in the GALL Report for consistency.

In its response to RAI 7.1.19-1, by letter dated May 25, 2005, the applicant stated:

The One-Time Inspection Program (B.2.1.29) has been revised to specifically identify

ultrasonic thickness measurements of the fuel oil storage tank bottom surfaces to

ensure that significant degradation is not occurring.

To implement this change, the “Program Description” section of LRA Appendix B.2.1.29,

One-Time Inspection Program, has been revised to include the following item:

 • Ultrasonic thickness measurements of tank bottoms to ensure that significant

degradation is not occurring for those tanks specified in the Fuel Oil Chemistry

Program (B.2.1.27) and the Aboveground Carbon Steel Tanks Program

(B.2.1.26).

The staff also reviewed BFN Procedure CI-130, “Diesel Fuel and Lube Oil Monitoring Program,”

and Procedure 0-SR-3.8.3.3 “Quarterly Fuel Oil Quality Determination of Unit 0 Diesel

Generator's 7-Day Storage Tank Supply.”
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Exception 1. In LRA Section B.2.1.27, the applicant identified an exception to GALL

AMP XI.M30 that affects three program elements. The applicant does not use ASTM

Standard D 2709 for guidance on the determination of water and sediment

contamination in diesel fuel, as specified in GALL AMP XI.M30. The applicant does

implement ASTM Standard D 1796 guidance on the determination of water and

sediment contamination, which is also specified in GALL AMP XI.M30.

The staff evaluation of the affected GALL Report program elements, “Scope of

Program” (Element 1), “Preventive Action” (Element 2), “Parameters Monitored or

Inspected” (Element 3), and “Acceptance Criteria” (Element 6), for the acceptability of

the exceptions is as follows:

Scope of Program - The program is focused on managing the conditions that

cause general pitting and MIC of the diesel fuel tank internal surfaces. The

program serves to reduce the potential of exposure of the tank internal surface

to fuel oil contaminated with water and microbiological organisms.

The staff evaluation of the affected GALL Report program elements for acceptability as

follows:

Preventive Action - On a quarterly basis, the diesel generator 7-day fuel oil tanks

and the diesel driven fire pump fuel oil tank are tested for water and sediments.

Water, if detected, is removed from these tanks. On a monthly basis, or when a

diesel generator is running for more than one hour, diesel generator fuel oil day

tanks are tested for water and drained as necessary if water is detected. Based

on a review of operating experience, these actions are effective in mitigating

corrosion inside of diesel generator 7-day fuel oil tanks, diesel generator fuel oil

day tanks, and the diesel driven fire pump fuel oil tank.

Parameters Monitored or Inspected - The Fuel Oil Chemistry Program monitors

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. The ASTM

Standard D 4057 is used for guidance on oil sampling. The ASTM Standards D

1796 and D 2709 are used for determination of water and sediment

contamination in diesel fuel. For determination of particulates, modified ASTM D

2276, Method A, is used. The modification consists of using a filter with a pore

size of 3.0 microns, instead of 0.8 microns. These are the principal parameters

relevant to tank structural integrity.

Acceptance Criteria - The ASTM Standard D 4057 is used for guidance on oil

sampling. The ASTM Standards D 1796 and D 2709 are used for guidance on

the determination of water and sediment contamination in diesel fuel. Modified

ASTM D 2276, Method A is used for determination of particulates. The

modification consists of using a filter with a pore size of 3.0 microns, instead of

0.8 microns.

The applicant concluded that the ASTM D 1796 test method is an acceptable laboratory

test method per ASTM D 975-89, “Standard Specification for Diesel Fuel Oils,” for the

determination of water and sediment contamination in the Grade 2 fuel oil used at BFN.
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Based on discussions with the applicant and review of implementing procedures, the

staff determined that, for fuel oils with the viscosity used at BFN, only ASTM standard D

1796 is applicable. Therefore, the staff found this exception to be acceptable.

Exception 2. In its submittal dated September 14, 2005, the applicant identified an additional

exception to GALL AMP XI.M.30 that neither biocides, stabilizers, nor corrosion inhibitors are

added to diesel fuel oil at BFN. Water, when detected, is removed from the diesel generator

7-day fuel oil tanks, diesel generator fuel oil day tanks, and the diesel driven fire pump fuel oil

tank. 

Staff Evaluation: Staff accepts this exception based on a review of plant specific and industry

operating experience, removal of water when detected has been effective in mitigating

corrosion inside of these tanks. Accordingly, the program description contained in LRA Section

A.1.24 was also revised to incorporate this exception.

LRA Section B.2.1.27 did not identify any enhancements; however, the staff noted that an

enhancement to achieve consistency with GALL AMP XI.M30, Element 4, “Detection of Aging

Effects,” is identified in the applicant’s AMP evaluation basis document. Specifically, the existing

Fuel Oil Testing and Monitoring Program needs to be enhanced to include ultrasonic thickness

measurements of the tank bottom surfaces to ensure that significant degradation is not

occurring.

The program description in LRA Section B.2.1.27 also identifies that a one-time inspection, in

accordance with the One-Time Inspection Program, will be performed prior to entering the

period of extended operation and will consist of thickness measurements of the 7-day diesel oil

supply tanks’ bottom surface. The staff reviewed the One-Time Inspection Program and noted

that it provides a general description of items to be included within the scope of the program,

but does not specifically identify the 7-day diesel oil supply tank as an item to be inspected.

The staff identified this issue in RAI 7.1.19-1, as documented in the staff’s BFN audit and

review report.

In response to this audit RAI and staff follow up on the subject, the applicant stated in a

docketed submittal dated May 25, 2005, as follows:

The One-Time Inspection Program (B.2.1.29) has been revised to specifically identify

ultrasonic thickness measurements of the fuel oil storage tank bottom surfaces to

ensure that significant degradation is not occurring. To implement this change, the

“Program Description” section of LRA Appendix B.2.1.29, One-Time Inspection

Program, has been revised to include the following item: “ Ultrasonic thickness

measurements of tank bottoms to ensure that significant degradation is not occurring for

those tanks specified in the Fuel Oil Chemistry Program (B.2.1.27) and the

Aboveground Carbon Steel Tanks Program (B.2.1.26).”

This program description change has been entered into a commitment item and will be suitably

incorporated into the Commitment Table in SER Appendix A. The staff considers the response

to be acceptable.
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Operating Experience. The Fuel Oil Chemistry Program includes identification of water and

particulate contamination in the diesel fuel oil system. Corrective actions were taken for the

water and particulate contamination removal and system/component inspections. However,

there have been no instances of fuel oil system component failures at BFN attributed to

contamination.

UFSAR Supplement. In LRA Section A.1.24, the applicant provided the UFSAR supplement for

the Fuel Oil Chemistry Program. The staff rev5iewed this section and determined that the

information in the UFSAR supplement, with revision, provides an adequate summary

description of the program. The staff found this section of the UFSAR supplement met the

requirements of 10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant’s program, the staff

determined, 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 exception and

the associated justifications and determined that the AMP, with the exception, is adequate to

manage the aging effects for which it is credited. In its review, the staff identified an

enhancement and confirmed that the implementation of the enhancement prior to the period of

extended operation would result in the existing AMP being consistent with the GALL Report

AMP to which it was compared. The staff concluded that the applicant had demonstrated that

the effects of aging will be adequately managed so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and

concluded that, with revision, it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.0.3.2.19 Reactor Vessel Surveillance Program

Summary of Technical Information in the Application. The applicant’s Reactor Vessel

Surveillance Program is described in LRA Section B.2.1.28, “Reactor Vessel Surveillance

Program.” In the LRA, the applicant stated that this is an existing program. This program is

consistent, with enhancements, with GALL AMP XI.M31, “Reactor Vessel Surveillance.”

The program was implemented to conform to the requirements of 10 CFR Part 50, Appendix H,

“Reactor Vessel Material Surveillance Program Requirements.” The Reactor Vessel

Surveillance Program is an integrated surveillance program in accordance with 10 CFR Part 50,

Appendix H paragraph III.C, that is based on requirements established by the BWRVIP.

Referencing of BWRVIP activities for license renewal was approved by the staff in its SER

regarding BWRVIP-74 of October 18, 2001. 

The applicant stated that the Reactor Vessel Surveillance Program is described in UFSAR

Section 4.2.6 and is based on BWRVIP-78, “BWR Integrated Surveillance Program (ISP) Plan,”

and BWRVIP-86, “BWR Vessel And Internals Project, BWR Integrated Surveillance Program

Implementation.” Use of the BWRVIP-78 and BWRVIP-86 was approved for referencing in the

staff’s safety evaluation dated February 1, 2000. Use of the BWRVIP ISP at Units 2 and 3 was

approved by the staff in its safety evaluation dated January 28, 2003.
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Enhancement 1. The applicant will confirm that the BWRVIP ISP for the period of extended

operation, if approved by the staff for the BWR fleet, is applicable to each reactor vessel and

will request the approval from the NRC, if necessary, to use the program at applicable reactor

vessels for the period of extended operation. This enhancement is scheduled for completion

prior to the period of extended operation, and it affects the program element affected “Scope of

Program” (Element 1).

In the LRA, the applicant state that the BWRVIP ISP described in BWRVIP-78 and BWRVIP-86

is only applicable for current license term of 40 years. However, the BWRVIP-78 and

BWRVIP-86 ISP provides for 13 capsules to be available for testing during the license renewal

period for the BWR fleet and establishes acceptable technical criteria for capsule withdrawal

and testing. The BWRVIP has submitted a report, BWRVIP-116, which provides the basis and

plan for extending the BWR ISP to address potential extended periods of operation for each

unit in the existing U.S. BWR fleet. The staff’s review of BWRVIP-116 is not complete. When

the staff review of BWRVIP-116 is complete, the applicant stated that it will evaluate the SER

and complete any SER Action Items. 

The applicant committed to implement the requirements of BWRVIP-116, when approved, for

all three reactor vessels. Therefore, the applicant did not submit a plant-specific program in its

LRA.

Enhancement 2. The applicant indicated in the LRA that for Unit 1 it would submit for staff

approval the BWRVIP ISP, or a plant-specific surveillance program, that meets the

requirements of 10 CFR Part 50, Appendix H for the period of extended operation. The

applicant proposed to implement the following actions:

 • Capsules will be removed periodically to determine the rate of embrittlement and at least

one capsule with neutron fluence of not less than once or greater than twice the peak

beltline neutron fluence will be removed before the expiration of the license renewal

period.

 • Capsules will contain material to monitor the impact of irradiation on the limiting beltline

materials and will contain dosimetry to monitor neutron fluence.

 • If capsules are not being removed during the license renewal period, operating

restrictions (i.e., inlet temperature, neutron spectrum, and flux) will be implemented with

NRC approval to ensure that the reactor vessel is operating within the environment of

the surveillance capsules, and ex-vessel dosimetry will be supplied for monitoring

neutron fluence. This enhancement is scheduled for completion prior to the period of

extended operation.

The applicant indicated that a plant-specific withdrawal schedule of the surveillance capsules

will be submitted to NRC for final approval in accordance with 10 CFR Part 50, Appendix H prior

to entering the period of extended operation. 

The applicant concluded that with the implementation of these enhancements, the Reactor

Vessel Surveillance Program will be consistent with GALL with respect to the scope of program

element for all three units, and this program provides reasonable assurance that the aging

effects will be managed so that the systems and components within the scope of this program
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will continue to perform their intended functions, consistent with the CLB basis, for the period of

extended operation.

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

BFN audit and review report. Furthermore, the staff reviewed the enhancements and their

justifications to determine whether the AMP, with enhancements, remains adequate to manage

the aging effects for which it is credited.

In LRA Section B.2.1.28, the applicant described the Reactor Vessel Surveillance Program to

manage irradiation embrittlement of the RV through testing that monitors RV beltline materials.

The LRA states that the Reactor Vessel Surveillance Program will be enhanced by making it

consistent with the BWRVIP ISP for periods of extended operation prior to the BFN units

entering their period of extended operation. The LRA further states that the enhanced program

will be consistent with GALL AMP XI.M31, “Reactor Vessel Surveillance,” described in the

GALL Report. For this AMP, the GALL Report recommends further evaluation. The staff also

reviewed the UFSAR supplement to determine whether it provides an adequate description of

the program. 

The applicant has implemented the BWRVIP ISP (as documented in BWRVIP-86-A) consistent

with the GALL AMP XI.M31, “Reactor Vessel Surveillance,” described in the GALL Report for

the period of the current units’ licenses. The staff concluded that the BWRVIP ISP in

BWRVIP-86-A is acceptable for BWR applicant implementation provided that all participating

applicants use one or more compatible neutron fluence methodologies acceptable to the staff

for determining surveillance capsule and RPV neutron fluences. Staff acceptance of the

BWRVIP ISP for the current term is documented in the SER dated February 1, 2002, from Bill

Bateman (NRC) to Carl Terry (BWRVIP Chairman). BWRVIP-116 provides guidelines for an

ISP to monitor neutron irradiation embrittlement of the reactor vessel beltline materials for all

U.S. BWR power plants for the period of license renewal. 

The staff’s review of LRA Section B.2.1.28 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 RAI B.2.1.28-1(A), dated December 1, 2004, the staff requested the applicant to make a

commitment to implement BWRVIP-116 ISP, which is currently being reviewed by the staff, or

to submit a plant-specific surveillance program for each unit, two years prior to entering the

period of extended operation.

In its response, by letter dated January 31, 2005, the applicant indicated that it will implement

either BWRVIP-116, as approved by the staff or, if the ISP is not approved two years prior to

entering the BFN units’ period of extended operation, submit to the staff a plant-specific

surveillance program for each unit. The applicant also stated that it will revise LRA

Section A.1.25 as shown in the subsection “UFSAR Supplement” of this section. This program

description change has been entered into a commitment item and will be suitably incorporated

into the Commitment Table in SER Appendix A. 
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The staff reviewed the applicant’s response and determined that the applicant must make a

formal commitment indicating that it will incorporate BWRVIP-116 as approved by the staff or a

plant-specific RV surveillance program for each unit, that will satisfy the requirements of

10 CFR Part 50, Appendix H.

In RAI B.2.1.28-1(B), dated December 1, 2004, the staff requested that the applicant provide an

explanation for not including Unit 1 in the ISP. The staff also requested that the applicant

provide a plant-specific surveillance program for Unit 1, or discuss how Unit 1 will be

incorporated into BWRVIP-116, and provide an evaluation of the vessel-to-capsule material

compatibility for the limiting plate and weld, as was performed for the ISP program, similar to

the other plants specified in BWRVIP-86 and BWRVIP-116. 

In its response, by letter dated January 31, 2005, the applicant indicated that LRA

Section B.2.1.28 discusses Unit 1 enhancements required to the Reactor Vessel Surveillance

Program. The applicant stated in LRA Section B.2.1.28 that, "Unit 1 will be included within the

BWRVIP Integrated Surveillance Program, or a plant-specific surveillance program will be

submitted for NRC approval that meets the requirements of 10 CFR Part 50, Appendix H for the

period of extended operation.”

The applicant indicated that the BWRVIP evaluated the Unit 1 Vessel and Surveillance Program

for participation in the ISP. The BWRVIP proposed in its letter from William A. Eaton

(Chairman, BWRVIP) to the NRC Document Control Desk, “Project No. 704 – BWRVIP

Response to NRC RAIs on BWRVIP-116,” dated January 11, 2005, to include Unit 1 in the ISP.

The BWRVIP indicated that Unit 1 is similar in design to the other BWRs in the ISP, and there

are no differences in irradiation conditions from the BWR fleet. The BWRVIP evaluated the

Unit 1 Reactor Vessel and Surveillance Program for participation in the ISP, consistent with the

methods and criteria previously established in BWRVIP-78 and BWRVIP-86 reports. The test

capsules representing limiting weld and plate materials are exposed to fluence values that

bound Unit 1 extended end of life (EOL) period fluences at the vessel 1/4t location. Based on

the information provided in the submittal, the staff concluded that the proposed representative

materials that are available for use in the ISP for Unit 1 could adequately provide information

related to any changes in the fracture toughness properties due to irradiation for the limiting

beltline materials during the period of extended operation. 

In RAI B.2.1.28-1(C), dated December 1, 2004, the staff requested that the applicant provide its

plan associated with testing of the capsules in accordance with the requirements of

BWRVIP-116 ISP. The plan should also identify capsules that need not be tested (standby

capsules). Tables 2-3 and 2-4 of BWRVIP-116 indicate that capsules from Unit 2 will be tested

and capsules from Unit 3 (standby capsules) will be not tested. These untested capsules were

originally part of the applicant’s plant-specific surveillance program and have received

significant amounts of neutron radiation. The staff requested the applicant to provide its

intentions with regard to maintenance of the standby capsules for further use. 

In its response, by letter January 31, 2005, the applicant stated:

Presently, there are no plans to withdraw surveillance capsules from the Unit 3 reactor

vessel since the BFN Unit 2 reactor vessel capsule provides the best representative

material for both units. As stated in NRC Safety Evaluation of the BWRVIP Integrated

Surveillance Program, dated February 1, 2002: “Although some surveillance capsules
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will be deferred and not tested as part of the ISP, all capsules that were previously

credited as part of plant-specific surveillance programs will continue to be irradiated in

their host reactors. Therefore, all irradiated material samples continue to remain

available to the ISP, if needed, and no overall reduction in the number of materials being

irradiated, number of specimen types, or number of specimens per reactor occurs as a

result of the ISP.” Unit 3 surveillance capsules will remain in place and will continue to

be irradiated during plant operation, including the period of extended operation.

Therefore, the Unit 3 irradiated material samples continue to remain available to the

ISP, if needed.

In response the staff requested the following standard license condition required of all LRA

applicants to be included in the SER (see SER Section 1.7):

Any changes to the BWRVIP ISP capsule withdrawal schedule must be submitted for

staff review and approval. Any changes to the BWRVIP ISP capsule withdrawal

schedule which affects the time of withdrawal of any surveillance capsules must be

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

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

in a condition which would support reinsertion into the RV, if necessary. 

On the basis of its review, the staff found the applicant had demonstrated that the effects of

aging due to loss of fracture toughness of the RV beltline region will be adequately managed

with the exceptions as stated above, 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).

Operating Experience. The applicant successfully implemented its Reactor Vessel Surveillance

Program that is consistent with RG 1.99, Revision 2, 10 CFR Part 50, Appendix H, and ASTM E

185, “Conducting Surveillance Tests For Light Water Cooled Reactor Vessels, E-706,”

predictions.

UFSAR Supplement. In LRA Section A.1.25, the applicant provided the UFSAR supplement for

the Reactor Vessel Surveillance Program.

As noted above, in its response to RAI B.2.1.28-1(A), by letter dated January 31, 2005, the

applicant stated that it will revise LRA Section A.1.25 as follows:

The BFN Reactor Vessel Surveillance Program is mandated by 10 CFR Part 50

Appendix H. The BFN Reactor Vessel Surveillance Program is an integrated

surveillance program in accordance with 10 CFR Part 50 Appendix H Paragraph III.C

that is based on requirements established by the BWR Vessel and Internals Project.

This program will be enhanced to implement either BWRVIP-116, as approved by the

staff, or, if the ISP is not approved two years prior to the commencement of the license

renewal period, a plant-specific surveillance program for each BFN unit will be submitted

that ensures the BFN Unit 1, Unit 2, and Unit 3 reactor vessels meet the requirements of

10 CFR Part 50 Appendix H. 

The applicant described the Reactor Vessel Surveillance Program as an existing program in

LRA Section A.1.25. The program uses periodic testing of metallurgical surveillance samples to
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monitor the loss of fracture toughness of the RPV beltline region materials consistent with the

requirements of 10 CFR Part 50, Appendix H and ASTM E 185. In its response regarding the

standby capsules (stated above), the applicant indicated that it would use Unit 3 surveillance

capsules as standby capsules for the period of extended operation. 

In a follow up on March 29, 2005, to RAI B.2.1.28-1(A), the staff requested the applicant to

commit that any changes to the BWRVIP ISP capsule withdrawal schedule must be submitted

for staff review and approval. Any changes to the BWRVIP ISP capsule withdrawal schedule

that affects the time of withdrawal of any surveillance capsules must be incorporated into the

licensing basis. If any surveillance capsules are removed without the intent to test them, these

capsules must be stored in a manner that maintains them in a condition that would support

re-insertion into the RV, if necessary. Units 1 and 3 surveillance capsules (standby capsules)

will remain in place and will continue to be irradiated during plant operation, including the period

of extended operation. Therefore, Units 1 and 3 irradiated material samples continue to remain

available to the ISP, if needed.

In its response dated May 25, 2005, the applicant agreed to comply with the staff request. This

satisfactorily resolves the staff RAI B.2.1.28-1(A). This program description change has been

entered into a commitment item and will be suitably incorporated into the Commitment Table in

SER Appendix A. 

The staff reviewed the applicant’s proposed revision to LRA Section A.1.25 and determined that

the applicant must implement the most recent staff-approved version of the BWRVIP ISP as the

method to demonstrate compliance with the requirements of 10 CFR Part 50, Appendix H.

The staff concluded that the information provided in the UFSAR supplement for the aging

management of systems and components discussed above is equivalent to the information in

the SRP-LR and, therefore, provides an adequate summary of program activities as required by

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. In addition, the staff reviewed the

enhancements and confirmed that the implementation of the enhancements prior to the period

of extended operation would result in the existing AMP being consistent with the GALL Report

AMP to which it was compared. 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 UFSAR supplement for this AMP and

concluded that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.0.3.2.20 ASME Section XI Subsection IWE Program

Summary of Technical Information in the Application. The applicant’s ASME Code Section XI

Subsection IWE Program is described in LRA Section B.2.1.32, “ASME Section XI Subsection

IWE Program.” In the LRA, the applicant stated that this is an existing program. This program is

consistent, with exceptions, with GALL AMP XI.S1, “ASME Section XI Subsection IWE.”
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The ASME Section XI Subsection IWE Inservice Inspection Program includes visual

examination and augmented inspection (visual and/or volumetric examinations) for steel

containments (Class MC). Inspections or testing are conducted on the steel containment shells

and their integral attachments; containment hatches and airlocks; seals, gaskets, and moisture

barriers; and pressure-retaining bolting. As required by 10 CFR 50.55a paragraph (g)(4)(ii), the

ASME Code Section XI Subsection IWE Inservice Inspection Program will incorporate the

requirements of the latest edition and addenda of the ASME Code by reference into

10 CFR 50.55a paragraph (b) 12 months prior to the start of each 120-month inspection

interval, subject to the limitations and modifications listed in 10 CFR 50.55a paragraph (b) and

with alternatives as authorized by the staff in accordance with 10 CFR 50.55a paragraphs (a)(3)

and (g)(6). Inspection of Class MC components, covered in the subsection IWE, is performed in

accordance with the 1992 edition through 1992 addenda for BFN current inspection intervals.

Based on the description of the program, the applicant, in its evaluation of the AMP, concluded

that the continued implementation of the ASME Code Section XI Subsection IWE Inservice

Inspection Program provides reasonable assurance that the aging effects will be managed so

that the structures within the scope of this program will continue to perform their intended

functions consistent with the CLB for the period of extended operation.

Staff Evaluation. During its 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 BFN audit and

review report. Furthermore, the staff reviewed the exceptions and their justifications to

determine whether the AMP, with exceptions, remains adequate to manage the aging effects

for which it is credited.

The staff evaluation consists of identifying and accepting departures from the provisions of the

GALL Report. In the program description, the applicant takes three exceptions, which are

discussed as follows.

Exception 1. The ASME Code Section XI, 1992 Edition, 1992 Addenda requires visual

examination VT-3 of containment seals and gaskets. In lieu of a visual examination, BFN takes

an exception to this requirement and requests exception that the test be performed in

accordance with the 10 CFR 50 Appendix J Program to determine degradation of seals and

gaskets. The applicant, in evaluating this exception, stated that examination of most seals and

gaskets require the joints to be disassembled. When the airlocks, hatches, electrical

penetrations, and flanged connections are tested in accordance with 10 CFR 50 Appendix J,

degradation of the seal or gasket material is revealed by an increase in the leakage rate.

Corrective measures can then be applied and the component re-tested. The applicant received

a relief from these requirements for Units 2 and 3 for the current interval.

Exception 2. The applicant seeks a second exception to the ASME Code of record for BFN,

which requires torque or tension testing on pressure-retaining bolted connections that have not

been disassembled and reassembled during the inspection interval. The applicant, however,

seeks to perform a test conforming to 10 CFR 50 Appendix J testing in lieu of a bolt torque or

tension test as required by the Code for these bolted connections. There is current relief that

authorizes this for Units 2 and 3 for the current interval.
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Exception 3. The applicant seeks a third exception to the ASME Code, which requires that,

when component examination results require evaluation of flaws, areas of degradation, or

repairs in accordance with article IWE-3000, and the component is found to be acceptable for

continued service, the areas containing such flaws, degradation, or repairs shall be reexamined

during the next inspection period listed in the schedule of the inspections program. When the

reexaminations reveal that the flaws, areas of degradation, or repairs remain essentially

unchanged for three consecutive inspection periods, the areas containing such flaws,

degradation, or repairs no longer require augmented examination in accordance with

Table IWE-2500-1 Examination Category E-C. At BFN, if the repair has restored the component

to an acceptable condition, reexaminations during subsequent inspection periods are not

performed.

 (1) Scope of Program - In the LRA, the scope of the program is as described in IWE-1000

of Subsection IWE, of the ASME Code together with the exemptions as identified in

IWE-1220, and additional requirements for inaccessible areas as promulgated in

10 CFR 50.55a(b)(2)(ix). The staff found that the plant-specific program scope is in

conformance with Section XI.S1 of the GALL Report. Therefore, the staff found the

program element acceptable.

 (2) Preventive Action - The applicant does not take exception to the program element.

 (3) Parameters Monitored or Inspected - The staff evaluated this program element and

studied the impacts on Exceptions 1 and 2. 

Staff evaluation: Exception 1 - ASME Code Examination Category E-D of

Table IWE-2500-1 requires visual examination of pressure boundary seals and gaskets.

The applicant stated in Exception 1 that it utilizes tests performed in accordance with

10 CFR 50 Appendix J, in lieu of a visual examination, to determine degradation of seals

and gaskets. In order to evaluate the exception, the staff needed additional information.

In RAI 3.5-2, dated December 10, 2004, the staff inquired about the aging management

of containment penetration seals and gaskets by pointing out that seals and gaskets

related to containment penetrations (in Item Number 3.5.1-6 of Table 3.5.1) are

proposed to be managed by the Containment Inservice Inspection Program and the

Containment Leak Rate Testing Program. As a result of Exception 1 to the ASME Code

Section XI Subsection IWE Program, the staff questioned whether the AMP will be

applicable for aging management of containment seals and gaskets. The staff said that

for equipment hatches and air-locks at BFN, the approach is that the leak rate testing

program will monitor aging degradation of seals and gaskets, as they are leak rate

tested after every opening. The staff wanted the applicant to clarify whether the

assumptions are correct. The staff also requested information for mechanical and

electrical penetrations with seals and gaskets, if the Type B leak rate testing and

frequency was adequate to monitor aging degradation of seals and gaskets of

containment drywell. The staff also requested the status of inspection and conditions of

the seals and gaskets of these penetrations at Unit 1.

With regard to Unit 1, the applicant stated that a Type B test will be performed as part of

the Unit 1 restart effort, and will continue to test at a frequency of 30 months until

sufficient test performance data are available to justify an extended test interval under

Option B.
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Details of RAI 3.5-2 are provided in SER Section 3.5.2.3.1. The staff, in evaluating the

applicant response, concluded that the applicant satisfactorily described the existing

process used in identifying degradation of the primary containment penetration seals

and gaskets. Also, since the applicant plans to continue with the testing and corrective

action process during the period of extended operation, the staff found the applicant’s

process of managing the aging of the pressure-retaining seals and gaskets of primary

containments and the exception under this program element acceptable. 

Staff evaluation of Exception 2 - ASME Code requires torque testing of

pressure-retaining bolts of Examination Category E-G, item E8.2 of Table IWE-2500-1.

The applicant in exception 2, takes exception from the ASME requirement and requests

to perform a test conforming to 10 CFR Part 50, Appendix J testing in lieu of a bolt

torque or tension test. The staff has provided relief to this IWE requirement to a number

of PWR licensees; however, in the case of BWR containments, the staff has a concern

about the adequacy of Type A, Appendix J, leak rate testing to monitor the aging

degradation of drywell head bolts, particularly as the Type A testing interval has been

extended to 10 and 15 years. During the AMR results review, staff developed RAI 3.5-3

for the applicant’s response.

In RAI 3.5-3, dated December 10, 2004, the staff requested information about the

testing and inspection of drywell-head components by noting that the containment

drywell-head to drywell joint consists of a pressure unseating containment boundary with

pre-loaded bolts. Loosened bolts and deteriorated gasket and/or seal can breach

containment pressure boundary. The staff felt that Exceptions 1 and 2, taken in the

containment ISI program will preclude examinations of seals and bolts of this joint. The

staff contended that only Type A leak rate testing and associated visual examination

requirements of Appendix J Program can be relied upon to detect defects and

degradation of this joint, whose test interval can be 10 to 15 years. The applicant was

requested to provide information regarding the plans and programs that are used to

ensure the integrity of this joint for each containment. The staff also requested the

applicant to provide the status of the components (O-rings and bolts) at this joint for

Unit 1.

In its response to RAI 3.5-3, dated January 31, 2005, the applicant stated that these

containment pressure boundary components will continue to be inspected consistent

with the BFN CLB under 10 CFR Part 50, Appendix J Program requirements. On Units 2

and 3 the Type A test frequency is currently on a 10-year interval. There have been no

performance-based Type A test failures on Units 2 or 3. The applicant in its response

stated that a Type A Integrated Leak Rate Test will be performed on Unit 1

prior-to-restart. Type B testing is also performed on the drywell-head seal every

refueling outage for all three units. Therefore, with the combination of the Type A tests

and Type B tests, integrity for this joint for each containment is assured. Exception 2

pertains to bolt torque or tension testing. Pressure-retaining bolting associated with the

containment drywell-head to drywell joint is examined in accordance with ASME Code

Section XI, Subsection IWE. The staff is satisfied that these two activities together with

periodic Type A testing will ensure the integrity of this joint. 

Therefore, the staff found the applicant’s practice of ensuring the integrity of this joint

acceptable and the exception 2 as proposed is acceptable.
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 (4) Detection of Aging Effects - The applicant does not take exception to the program

element.

 (5) Monitoring and Trending - The staff evaluated this program element and studied the

impacts of exception 3 on it. This exception concerns component examination results

that require evaluation of flaws, areas of degradation, or repairs in accordance with

Article IWE-3000, of ASME B&PV code (see above). The applicant in performing a

plant-specific evaluation of this element stated that the staff previously granted the

applicant a relief request (CISI-3) for Units 2 and 3 for its current inspection intervals

from the requirement of Paragraphs IWE-2420(b) and IWE-2420(c) to perform

reexaminations during subsequent inspection periods of the repaired areas if the repair

has restored the component to an acceptable condition. In evaluating the exception, the

staff took the position that if flaws and degradations had been repaired and restored in

accordance with the requirements of IWA-4000, the staff provided relief to a number of

licensees (and applicants) from the requirements of IWE-2420(b) and (c). In granting

that relief, staff considered the requirements as an unnecessary burden without a

commensurate safety benefit. Therefore, the staff found the exception as it impacted

this program element acceptable.

 (6) Acceptance Criteria - Acceptable, as no exception taken to GALL AMP X1.S1.

 (7) Corrective Actions - The applicant does not take exception to the program element.

 (8) Confirmation Process - Acceptable, as no exception taken to GALL AMP X1.S1.

 (9) Administrative Controls - Acceptable, as no exception taken to GALL AMP X1.S1.

 (10) Operating Experience - The applicant reviewed plant-specific ASME Section XI,

Inservice Inspection Program performance results that have been generally effective in

managing aging effects in ASME components. In LRA Section B.2.1.32, the applicant

provided the following description of plant-specific operating experience.

The drywell steel containment vessel is inaccessible (except for the drywell head) for visual

examination from the outside surface. There has been evidence of water leaking from the sand

bed drains on both Units 2 and 3. Since there is a horizontal weld connecting the first and

second course of drywell liner plates approximately 8 inches above the drywell concrete floor,

UT thickness measurements from the drywell floor up to this weld around the drywell

circumference would conservatively bound the sand pocket area. UT thickness measurements

of this area were obtained during the U2C10 and U3C8 refueling outages for Units 2 and 3,

respectively, and in 1999 and 2002 for Unit 1. The data indicated that the condition of the

drywell steel liner plate in this area is good, and that this area did not require augmented

examination.

The internal drywell steel containment vessel embedment zone is subject to corrosion if the

drywell floor-to-containment vessel moisture barrier fails, allowing moisture intrusion; or if the

concrete floor of the drywell cracks, allowing moisture seepage through to the steel liner. During

the Unit 2 U2C9 outage, a portion of the moisture barrier was replaced. Inspection of the

exposed drywell steel containment vessel area below the moisture seal indicated some minor

pitting and localized rust, but there was not a challenge to nominal wall thickness. No

propagation of iron oxide to the concrete surface was noted; its presence would have indicated

steel containment vessel corrosion below the concrete. The concrete floor above the embedded

steel containment vessel is examined as part of the Structures Monitoring Program (B.2.1.36).
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Based on existing inspection documentation and maintenance practices, this area has not

exhibited signs of accelerated degradation.

The penetration bellows at BFN have no documented failures as a result of routine testing by

the BFN Appendix J program or inspections conducted by the Containment Inservice Inspection

Program.

Inspections conducted under the Containment Inservice Inspection Program identified some

damaged areas of the moisture seal barrier (gaps, cracks, low areas/spots, or other surface

irregularities) in Units 2 and 3 that required repair.

Operating experience related to containment structure components: RAI 3.5-5, dated May 24,

2005, provides the details of the follow-up to RAI 3.5-4. The staff found that the applicant

comprehensively addressed all the issues. In closing out RAI 3.5-5, the staff concluded that the

applicant’s program was adequate and acceptable. The disposition and resolution of RAI 3.5-5

can be found in SER Section 3.5.2.3.1. 

Operating experience related to torus shells: NRC IN 88-82, "Torus Shells with Corrosion and

Degraded Coatings in BWR Containments," describes and discusses the problems associated

with corrosion of torus shells. In RAI B.2.1.32-1, dated December 10, 2004, the staff asked the

applicant to provide information regarding the status of torus shells. In applying NRC IN 88-82,

the staff requested the applicant to provide operating experience related to inspection of torus

shells at BFN. since the quality of torus water in Unit 1 torus may not have been monitored

during its long layup period, the staff requested additional discussion of the condition of the

torus for Unit 1.

In its response, by letter January 31, 2005, the applicant stated that the torus interior surfaces

at the waterline were subject to corrosion due to moisture and repeated wetting and drying in

the waterline region. Accessible portions of the torus inside surface were inspected each

refueling outage. UT thickness measurements taken in torus underwater areas of both Units 2

and 3 revealed no evidence of excessive degradation (all readings were within 10 percent of

nominal wall thickness). The applicant confirmed that previous inspections had documented

evidence of minor coating degradation at the waterline region. Based on the above, the

applicant concluded that the underwater region of the torus had not been subjected to

accelerated degradation. 

The applicant, furthermore, stated that, since evidence of repeated loss of coatings had been

documented in the waterline region, augmented examination of this area was warranted as a

conservative measure on Units 2 and Unit 3.

Regarding Unit 1, the applicant stated that during its layup period, the water in the Unit 1 torus

(pressure suppression pool) was maintained by the "chemistry program." The torus was drained

in the summer of 2003 for coating repair, which will be completed as a part of the Unit 1

recovery effort. The applicant also stated that a VT-3 visual examination was performed on the

Unit 1 torus in August 2003. This examination included 100 percent of the Code Class MC

boundary inside the torus, which included shell and ring girders, and both sides of the vent

system to include main vent line, vent header, and downcomers. The visual examination found 

light-to-medium rust or discoloration in several areas and heavy rust in smaller, less frequent

areas. There were also some instances of base metal encroachment, such as gouges,
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scratches, and tool marks. Engineering evaluation of the examination results determined that

the torus structural condition was acceptable as is, with no base metal repairs required.

Moreover, the applicant emphasized that the requirements of ASME Section XI Inservice

Inspection Subsection IWE, 1992 Edition with the 1992 Addenda will be implemented on Unit 1.

Type A, B, and C leak rate testing required by 10 CFR 50, Appendix J will also be performed

prior to Unit 1 restart.

The applicant reviewed site-specific work history data to confirm that an adequate number of

inspection opportunities are afforded by the IWE program. The applicant also stated in the LRA

that the plant Corrective Action Program, which captures internal and external plant operating

experience issues, provides reasonable assurance that operating experience will be reviewed in

the future to provide objective evidence to support the conclusion that the effects of aging will

be managed adequately.

The staff found the applicant's process of monitoring the condition of the torus in Units 2 and 3

acceptable, as its continuation during the period of extended operation provides adequate

assurance regarding the ability of the torus to perform its intended function. The applicant

stated in its response letter dated January 31, 2005, that it monitored the quality of water and

condition of torus surfaces in the immediate past (since 2003), and plans to continue the ISI

activities in accordance with this AMP. Therefore, the staff found the applicant's procedures

acceptable, as they will ensure the ability of the torus to perform its pressure-retaining function

during the period of extended operation. 

UFSAR Supplement. In LRA Section A.1.29, the applicant provided the UFSAR supplement for

the ASME Code Section XI Subsection IWE Program. The staff reviewed this section and

determined that the information in the UFSAR supplement provides an adequate summary

description of the program. The staff found this section of the UFSAR supplement met 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 determined 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 concluded that the

applicant had demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement

for this AMP and concluded that it provides an adequate summary description of the program,

as required by 10 CFR 54.21(d).

3.0.3.2.21 ASME Section XI Subsection IWF Program

Summary of Technical Information in the Application. The applicant’s ASME Code Section XI

Subsection IWF Program is described in LRA Section B.2.1.33, “ASME Section XI Subsection

IWF Program.” In the LRA, the applicant stated that this is an existing program. This program is

consistent with GALL AMP XI.S3, “ASME Section XI Subsection IWF.”
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The LRA states that 10 CFR 50.55a imposes the inservice inspection requirements of the

ASME B&PV Code Section XI for Class 1, 2, and 3 piping and component supports. Inspection

of equivalent Class 1, 2, and 3 piping and component supports covered in subsection IWF is

performed in accordance with the 1995 edition through the 1996 addenda for the Units 1 and 2

current inspection interval. Inspection of equivalent Class 1, 2, and 3 piping and component

supports covered in subsection IWF is performed in accordance with the 1989 edition and Code

Case N-491 “Alternative Rules for Examination of Class 1, 2, 3, and MC Component Supports

of Light-Water Power Plants, Section XI Division 1,” for the Unit 3 current inspection interval.

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

BFN audit and review report. Furthermore, the staff reviewed the exception and its justifications

to determine whether the AMP remains adequate to manage the aging effects for which it is

credited. 

In RAI B.2.1.33-1, dated December 13, 2004, the staff requested the applicant to address how

the supports of MC piping and components are inspected during the current licensing term.

In its response, by letter dated January 18, 2005, the applicant stated:

The Class MC boundaries include the steel containment vessel (SCV), which is

comprised of the drywell, pressure suppression chamber or torus and associated vent

piping, including vertical and circumferential structural stiffeners; penetrations,

reinforcement structure, the portion of the SCV embedded in the drywell concrete floor

slab, and attachment welds between structural attachments and the SCV pressure

retaining boundary or reinforcing structure. 

The applicant stated that there is no Class MC piping at BFN. Piping in the scope of license

renewal located in the containment that is not ASME equivalent Class 1, 2, or 3 is evaluated as

non-ASME piping, and covered in its AMR. The staff considered the above classification of the

MC component supports to be acceptable. Therefore, the staff’s concern described in

RAI B.2.1.33-1 is resolved with regard to piping. 

By letter dated January 24, 2005, the applicant responded that the ASME equivalent supports

and component listed in LRA Table 2.4.8.1 do not include the drywell lower ring support and

the drywell upper lateral support. The staff was not clear regarding the applicant's basis for

excluding the supports for Class MC components from the scope of ASME Section XI. The staff

requested that the applicant justify the above noted exclusion. In its response, by letter dated

May 31, 2005, the applicant stated that it will manage the Class MC supports per Section XI,

Subsection IWF. LRA Table 3.5.2.26 has been revised to reflect this commitment. Therefore,

the staffs concern described in RAI B.2.1.33-1 is resolved with regard to support.

In RAI B.2.1.33-3, dated December 13, 2004, the staff requested the applicant to describe the

method by which the supports on Class MC components in inaccessible areas will be managed

during the period of extended operation because the applicant’s discussion of the IWF Program

is focused on accessible supports on MC components. There is no discussion of components in

inaccessible areas. In its response, by letter dated January 18, 2005, the applicant stated that

none of the torus cradles, downcomer supports, or vent header supports located in containment

air or inside air environments are inaccessible. For the vent downcomer and vent header
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supports that are submerged in a torus water environment, the applicant stated that the

Chemistry Control Program and One-Time Inspection Program will be used to manage the

aging effects. The staff considered the applicant’s response to have adequately addressed its

concern on the aging management of inaccessible supports of MC components. RAI B.2.1.33-3

is, therefore, closed.

Based on the information provided in the LRA and the applicant’s responses to the RAIs, the

staff found that the applicant’s IWF Program is acceptable and no exceptions were taken. The

supports of MC components will be adequately managed during the period of extended

operation.

Operating Experience. The applicant did not indicate any adverse operating experience for this

program.

UFSAR Supplement. In LRA Section A.1.30, the applicant provided the UFSAR supplement for

the IWF Inspection Program The staff reviewed this section and determined that the information

in the UFSAR supplement provides an adequate summary description of the program. The staff

found this section of the UFSAR supplement met the requirements of 10 CFR 54.21(d).

Conclusion. On the basis of its review, the staff found that the applicant’s IWF program is

consistent with Section XI.S3 of the GALL. Based on the information provided by the applicant,

the staff concluded that the accessible supports of the MC components will be adequately

inspected by the IWF Program during the period of extended operation. The staff concluded

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). The staff also reviewed the UFSAR Supplement program summary for the

IWF Program and concluded that, it provides an adequate summary description of the program,

as required by 10 CFR 54.21(d).

3.0.3.2.22 Masonry Wall Program

Summary of Technical Information in the Application. The applicant’s Masonry Wall Program is

described in LRA Section B.2.1.35, “Masonry Wall Program.” In the LRA, the applicant stated

that this is an existing program. This program is consistent, with an enhancement, with GALL

AMP XI.S5, “Masonry Wall Program.”

In LRA Section B.2.1.35, the applicant stated that the Masonry Wall Program provides for

condition monitoring of masonry walls. The program is included in the Structures Monitoring

Program that implements the structures monitoring requirements of 10 CFR 50.65 Maintenance

Rule. Masonry wall condition monitoring is based on guidance provided in NRC Bulletin 80-11

“Masonry Wall Design” and IN 87-67 “Lessons Learned from Regional Inspections of Licensee

Actions in Response to I.E. Bulletin 80-11.” Visual inspections are performed consistent with

techniques identified in industry codes and standards such as American Concrete Institute

(ACI) 349.3 R-96, “Evaluation of Existing Nuclear Safety-Related Concrete Structures,” and

ANSI/American Society of Civil Engineers (ASCE) 11-90, “Guideline for Structural Condition

Assessment of Existing Buildings.”
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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

BFN audit and review report. Furthermore, the staff reviewed the enhancement and its

justifications to determine whether the AMP, with enhancement, remains adequate to manage

the aging effects for which it is credited.

The staff reviewed the program elements (see SER Section 3.0.2.1) for the Masonry Wall

Program and its associated bases documents, and compared them to those listed for

AMP XI.S5 in the GALL Report for consistency.

Enhancement. In the LRA Section B.2.1.35, the applicant identified an enhancement to make

this AMP consistent with GALL AMP XI.S5. Program procedures will be revised so that

structures with masonry walls within the scope of license renewal are clearly identified and the

qualification requirements for personnel who perform masonry wall walkdowns within the scope

of license renewal are clarified. This enhancement is scheduled to be completed prior to

entering the period of extended operation. The applicant concluded that, with the

implementation of this enhancement, BFN will ensure continued consistency with the affected

program elements.

The staff evaluation of the affected GALL Report program elements, “Scope of Program”

(Element 1), “Parameters Monitored or Inspected” (Element 3), and “Detection of Aging Effects”

(Element 4), for the acceptability of the exception is as follows:

Scope of Program. The scope includes all masonry walls identified as performing

intended functions in accordance with 10 CFR 54.4

Parameters Monitored or Inspected. The primary parameter monitored is wall cracking

that could invalidate the evaluation basis.

Detection of Aging Effects. Visual examination of the masonry walls by qualified

inspection personnel is sufficient. The frequency of inspection is selected to ensure

there is no loss of intended function between inspections. The inspection frequency may

vary from wall to wall, depending on the significance of cracking in the evaluation basis.

Unreinforced masonry walls that have not been contained by bracing warrant the most

frequent inspection, because the development of cracks may invalidate the existing

evaluation basis.

GALL AMP XI.S5 states that the scope includes all masonry walls identified as performing

intended functions in accordance with 10 CFR 54.4. The AMP evaluation states that structures

with masonry walls within the scope of license renewal include the BFN reactor buildings, Unit 1

and 2 diesel generator building, Unit 3 diesel generator building, Unit 2 turbine building (station

blackout (SBO) function), and the intake pumping station. BFN Technical Instruction 0-TI-346

will be enhanced to identify that the Unit 1,2, and 3 reactor buildings, Unit 1 and 2 diesel

generator building, Unit 3 diesel generator building, Unit 2 turbine building (SBO function), and

the intake pumping station are within the scope of license renewal.

The staff requested that the applicant identify the walls that are within the scope of license

renewal. The applicant, as documented in the staff’s audit and review report, stated that BFN

Technical Instruction 0-TI-346 identifies structures within the scope of license renewal for the

Maintenance Rule and will be enhanced to identify structures within the scope of license
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renewal that require aging management. LCEI-CI-C9 refers to BFN Technical Instruction

0-TI-346 for the detailed listing of structures in the scope of the Maintenance Rule and license

renewal. LCEI-CI-C9 requires inspection of masonry walls in structures identified in BFN

Technical Instruction 0-TI-346. The staff concurred that, with the enhancement, all the masonry

walls that are within the scope of license renewal will be covered by the referenced procedures.

GALL AMP XI.S5 also states that visual examination of the masonry walls by qualified

inspection personnel is sufficient. The BFN AMP evaluation states that the quality and value of

the results obtained from the walkdown assessment activity and the assessment evaluation are

dependant on the qualifications and capabilities of the inspection team, as discussed in Chapter

7 of ACI 349-3R-96. LCEI-CI-C9 will be enhanced as part of the Structures Monitoring Program

enhancements to clarify the qualification requirements for personnel who perform masonry wall

walkdowns and evaluations. The staff concurred that this enhancement is consistent with the

GALL Report. See the SER Section on Structures Monitoring Program below for information on

enhancements to the Structures Monitoring Program.

UFSAR Supplement. In LRA Section A.1.32, the applicant provided the UFSAR supplement for

the Masonry Wall Program. The staff reviewed this section and determined that the information

in the UFSAR supplement provides an adequate summary description of the program. The staff

found this section of the UFSAR supplement met the requirements of 10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant’s program, the staff determined

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 enhancement and

confirmed that the implementation of the enhancement prior to the period of extended operation

would result in the existing AMP being consistent with the GALL Report AMP to which it was

compared. The staff concluded that the applicant had demonstrated that the effects of aging

will be adequately managed so that the intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.23 Structures Monitoring Program

Summary of Technical Information in the Application. The applicant’s Structures Monitoring

Program is described in LRA Section B.2.1.36, “Structures Monitoring Program.” In the LRA,

the applicant stated that this is an existing program. This program is consistent, with

enhancements, with GALL AMP XI.S6, “Structures Monitoring Program.”

In the LRA Section B.2.1.36, the applicant stated that the Structures Monitoring Program

includes periodic inspection and monitoring of the condition of accessible areas of structures.

The Structures Monitoring Program implements the requirements of 10 CFR 50.65,

“Maintenance Rule.” The program incorporates the guidance of RG 1.160, Revision 2, and

Nuclear Management and Resources Council 93-01, Revision 2. The Structures Monitoring

Program provides inspection guidelines and walkdown checklists for concrete features, roofs,

structural steel, masonry walls, seismic gaps, tanks, earthen structures, buried piping, and

miscellaneous components such as doors.
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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

BFN audit and review report. Furthermore, the staff reviewed the enhancements and

justifications to determine whether the AMP, with enhancements, remains adequate to manage

the aging effects for which it is credited.

The staff reviewed the program elements (see SER Section 3.0.2.1) contained in the AMP and

associated bases documents, and compared them to those listed for AMP XI.S6 in the GALL

Report for consistency.

The staff noted that the basis document does not address protective coating monitoring and

maintenance; however, BFN Technical Instruction 0-TI-346 Section 3.3 includes

“damaged/degraded coatings” under concrete and structural steel. LCEI-CI-C9 does not

address protective coatings in the walkdown procedures. As documented in the staff’s audit and

review report, the applicant confirmed that protective coatings are not credited to manage aging

effects for license renewal.

The staff noted that the program is being expanded to include the inspection of piles and asked

the applicant to clarify the types of inspections that will be performed for piles. The applicant

stated that piles associated with gate structure Number 3 and the diesel high pressure fire

protection (HPFP) house will be visually inspected by the Structures Monitoring Program. The

portion of the piles exposed to the submerged and outside air environments will be visually

inspected by the Structures Monitoring Program. The staff concluded that the AMP would not

require any further enhancements to perform the inspections of piles as described by the

applicant.

In LRA Section B.2.1.36, the applicant identified three enhancements to make this AMP

consistent with GALL AMP XI.S6. 

Enhancement 1. The applicant will enhance procedures implementing the 10 CFR 50.65

Maintenance Rule Program to identify all structures and structural components within the scope

of license renewal and all aging effects and associated mechanisms for inspection. The staff

evaluation of the affected GALL program elements “Scope of Program” (Element 1) and

“Parameters Monitored or Inspected” (Element 3), for the acceptability of the first enhancement

is as follows:

Scope of Program. The applicant specifies the structure/aging effect combinations that

are managed by its Structures Monitoring Program.

Parameters Monitored or Inspected. For each structure/aging effect combination, the

specific parameters monitored or inspected are selected to ensure that aging

degradation leading to loss of intended functions will be detected and the extent of

degradation can be determined. Parameters monitored or inspected are to be

commensurate with industry codes, standards and guidelines, and are to also consider

industry and plant-specific operating experience. Although not required, ACI 349.3R-96

and American National Standards Institute (ANSI)/ASCE 11-90 provide an acceptable

basis for selection of parameters to be monitored or inspected for concrete and steel

structural elements and for steel liners, joints, coatings, and waterproofing membranes

(if applicable). If necessary for managing settlement and erosion of porous concrete
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subfoundations, the continued functionality of a site dewatering system is to be

monitored. The plant-specific Structures Monitoring Program is to contain sufficient

detail on parameters monitored or inspected to conclude that this program attribute is

satisfied.

The staff asked the applicant how the structural components and supports that are identified as

an enhancement to the scope of the AMP are currently being managed and if a baseline

inspection of these structural components and supports will be performed prior to the period of

extended operation.

The applicant, as documented in the staff’s audit and review report, stated that the identified

structural component supports that are to be added to the Structures Monitoring Program are

currently being managed by the plant work control procedures and the Corrective Action

Program. The applicant further stated that all Structures Monitoring Program enhancements

required to document structural components and structural support inspections will receive a

baseline inspection prior to the period of extended operation. Structures Monitoring Program

baseline inspections are currently required by Section 5.1 of LCEI-CI-C9.

The staff noted that the AMP evaluation states that procedures in BFN Technical Instruction

0-TI-346 and LCEI-CI-C9 will be enhanced to identify all aging effects and associated aging

mechanisms to be inspected. Aging effects and mechanisms considered will be consistent with

the GALL Report and Section 4 of ACI 349.3R-96. BFN operating experience is considered for

selecting each structure/aging effect combination. The aging effects for structures monitored

and inspected that will be identified in 0-TI-346 and LCEI-CI-C9 enhancements are documented

in the staff’s BFN audit and review report.

The staff concurred that this enhancement is consistent with the GALL Report.

Enhancement 2. The applicant will enhance LCEI-CI-C9 implementing the 10 CFR 50.65

Maintenance Rule Program sampling approach to include examinations of representative

samples of below-grade concrete when excavated for any reason. The staff evaluation of the

affected GALL program element “Detection of Aging Effects” (Element 4) for the acceptability of

the second enhancement is as follows:

Detection of Aging Effects. For each structure/aging effect combination, the inspection

methods, inspection schedule, and inspector qualifications are selected to ensure that aging

degradation will be detected and quantified before there is loss of intended functions.

Inspection methods, inspection schedule, and inspector qualifications are to be commensurate

with industry codes, standards and guidelines, and are to also consider industry and

plant-specific operating experience. Although not required, ACI 349.3R-96 and ANSI/ASCE

11-90 provide an acceptable basis for addressing detection of aging effects. The plant-specific

Structures Monitoring Program is to contain sufficient detail on detection to conclude that this

program attribute is satisfied.

The staff concurred that this enhancement is consistent with the GALL Report.

Enhancement 3. The staff evaluation of the affected GALL program element “Detection of

Aging Effects” (Element 4) for the acceptability of the third enhancement is as follows:
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Detection of Aging Effects. (See element description above) 

The applicant will enhance LCEI-CI-C9 implementing 10 CFR 50.65, the Maintenance Rule

Program, to include the guidance provided in ACI 349.3R-96 Chapter 7 to clarify the “suitably

knowledgeable or trained” inspector qualifications to “training and proficiency demonstration of

inspectors for structural aging effects and long term performance issues.” The procedures will

also be clarified to identify the “responsible engineer” as the “Structures Monitoring Program

engineer” to avoid confusion with industry guidance. LCEI-CI-C9 will also be clarified to identify

the “responsible engineer” as the “Structures Monitoring Program engineer” to avoid confusion

with industry guidance.

The staff had a follow up question in a May 4, 2005, teleconference regarding evaluation of

inspection personnel qualification based on industry guidance ACI 349.3R-96 as stated in the

Structures Monitoring Program. The staff stated that this industry guidance alone will not be

adequate to qualify the inspectors for the examination of steel supports for the Structures

Monitoring Program. The staff requested that the applicant reevaluate the program element

from previous staff positions and submit the description for staff review. The applicant

responded to the staff’s question and committed to manage the aging effects of Class MC

supports under ASME Code Section XI Subsection IWF. In its response to a follow up to

RAI B.2.1.33-1, the applicant also agreed to include the inspector’s qualification in accordance

with the requirements of ASME Code Section XI Subsection IWF and not per the BFN

Structures Monitoring Program. In its response to a follow up to RAI B.2.1.33-1,by letter dated

May 31, 2005, the applicant responded to the staff’s question and committed to manage the

aging effects of Class MC supports under ASME Code Section XI Subsection IWF. The

applicant also agreed to include the inspector’s qualification in accordance with the

requirements of ASME Code Section XI Subsection IWF and not per the BFN Structures

Monitoring Program.

Subject to the applicant’s complying by submitting this resolution of this confirmatory item, the

staff concurred that this enhancement is consistent with the GALL Report.

Operating Experience. In LRA Section B.2.1.36, the applicant stated that plant-specific

performance results of the Structures Monitoring Program had been reviewed. The program

has been shown to be effective in managing aging effects of structural features and

components. Examples of the plant-specific operating experience issues are documented in the

staff’s BFN audit and review report and were determined to be insignificant with respect to

maintaining structural adequacy. Defects were identified as PERs and dispositioned in

accordance with the Maintenance Rule Program by methods such as repair, cause

determination, cause mitigation, or monitoring to ensure the continued availability of the

function.

In addition to the operating experience discussed in the AMP, the AMP evaluation stated that a

baseline inspection for the Structures Monitoring Program was established in 1997 and is

documented in calculation CDQ-0303-970086. Defect evaluations performed since the baseline

inspection and inspection results from the 2002 Structures Monitoring Program are documented

in calculation CDQ-0303-2003-0260. Observed aging effects for structures within the scope of

license renewal were evaluated not to significantly challenge the ability of structures to meet

design requirements or perform their intended function. 
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During the onsite audit, the staff noted that the applicant incorporates internal and external

plant operating experience issues into the plant Corrective Action Program on a continuing

basis. The staff concluded there is reasonable assurance that operating experience will

continue to be reviewed in the future to ensure that the effects of aging will be adequately

managed, consistent with the guidance in the GALL Report.

UFSAR Supplement. In LRA Section A.1.33, the applicant provided the UFSAR supplement for

the Structures Monitoring Program. The staff reviewed this section and determined that the

information in the UFSAR supplement provides an adequate summary description of the

program. The staff found this section of the UFSAR supplement met the requirements of

10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant’s program, the staff determined

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 enhancements and

confirmed that the implementation of the enhancements prior to the period of extended

operation would result in the existing AMP being consistent with the GALL Report AMP to which

it was compared. The staff concluded that the applicant had demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff

also reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.24 Inspection of Water-Controlled Structures Program

Summary of Technical Information in the Application. The applicant’s Inspection of

Water-Controlled Structures Program is described in LRA Section B.2.1.37, “Inspection of

Water-Controlled Structures Program.” In the LRA, the applicant stated that this is an existing

program. This program is consistent, with enhancements, with GALL AMP XI.S7, “RG 1.127,

Inspection of Water-Controlled Structures Associated with Nuclear Power Plants.”

In LRA Section B.2.1.37, the applicant stated that the Inspection of Water-control Structures

Program manages age-related deterioration, degradation due to extreme environmental

conditions, and the effects of natural phenomena that may affect water-control structures. BFN

is not committed to RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear

Power Plants,” but has a program in place that is consistent with the elements of RG 1.127, as

evaluated in the GALL Report. The program is included in the Structures Monitoring Program

(B.2.1.36), which implements the structures monitoring requirements of 10 CFR 50.65

“Maintenance Rule.” The Inspection of Water-control Structures Program includes in-service

inspection and surveillance activities for dams, slopes, canals, and other water-control

structures.

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

BFN audit and review report. Furthermore, the staff reviewed the enhancements and its

justifications to determine whether the AMP, with enhancements, remains adequate to manage

the aging effects for which it is credited.
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The staff reviewed the program elements (see SER Section 3.0.2.1) contained in the AMP,

associated bases documents, and the implementing documents, and compared them to those

listed for AMP XI.S7 in the GALL Report for consistency. The staff did not request any

clarifications or additional information from the applicant for this AMP.

Enhancement 1. The applicant will enhance program documents to ensure that required

structures and structural components within the scope of license renewal are identified.

Although the LRA indicates that this enhancement affects GALL Report program element

“Parameters Monitored or Inspected” (Element 3), the staff noted that the description of the

enhancement in the LRA more appropriately pertains to GALL Report program element, “Scope

of Program” (Element 1). Therefore, the staff evaluated this enhancement against the GALL

Report element as follows.

Scope of Program - RG 1.127 applies to water-control structures associated with

emergency cooling water systems or flood protection of nuclear power plants. The

water-control structures included in the RG 1.127 program are concrete structures;

embankment structures; spillway structures and outlet works; reservoirs; cooling water

channels and canals, and intake and discharge structures; and safety and performance

instrumentation.

The applicant’s AMP basis document (AMP evaluation) states that the scope of the Inspection

of Water-Controlled Structures Program includes the following list of structures identified in

BFN Technical Instruction 0-TI-346, Attachment 38:

 • intake pumping station

 • gate structure No. 3

 • intake channel

 • north bank of cool water channel east of gate structure Number 2

 • south dike of cool water channel between gate structure Number 2 and 3 (only

that portion of the south dike over the RHRSW discharge piping)

Procedures, 0-TI-346 and LCEI-CI-C9, will be enhanced to identify all structures and structural

components within the scope of license renewal. Component enhancements will expand the

walkdown checklist of structural steel components to include items such as anchors, bolts,

fasteners, and other miscellaneous steel and non-ferrous materials. Component enhancements

will also require expanding the checklist for seismic gaps to include seals and caulking that are

used to prevent flooding. Component enhancements will be based on the list of structural

components within the scope of license renewal in the AMR.

BFN Technical Instruction 0-TI-246 augments LCEI-CI-C9 in that it provides the inspection

requirements for water holding or transporting earthen structures. The scope of 0-TI-246 is

identified in Appendix A and includes the intake channel, north bank of cool water channel east

of gate structure Number 2, and the south dike of cool water channel between gate structure

Numbers 2 and 3. Appendix A of BFN Technical Instruction 0-TI-246 will be enhanced to

indicate that the intake channel, north bank of cool water channel east of gate structure Number

2, and south dike of cool water channel between gate structure Numbers 2 and 3 (only that

portion of the south dike over the RHRSW discharge piping) are within the scope of license

renewal and require aging management. The staff concurred that this enhancement is

consistent with the GALL Report.
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Parameters Monitored or Inspected. RG 1.127 identifies the parameters to be monitored

and inspected for water-control structures. The parameters vary depending on the

particular structure. Parameters to be monitored and inspected for concrete structures

include cracking, movements (e.g., settlement, heaving, deflection), conditions at

junctions with abutments and embankments, erosion, cavitation, seepage, and leakage.

Parameters to be monitored and inspected for earthen embankment structures include

settlement, depressions, sink holes, slope stability (e.g., irregularities in alignment and

variances from originally constructed slopes), seepage, proper functioning of drainage

systems, and degradation of slope protection features. Further details of parameters to

be monitored and inspected for these and other water-control structures are specified in

Section C.2 of RG 1.127.

The applicant’s AMP basis document states that 0-TI-346 and LCE-CI-C9 provide for

monitoring of concrete structures, structural steel, non-ferrous components, and earthen

structures. BFN Technical Instruction 0-TI-246 augments LCEI-CI-C9 and provides the

inspection requirements for water holding or transporting earthen structures such as ponds,

channels, and associated dikes. BFN Technical Instruction 0-TI-346 and LCEI-CI-C9 will be

enhanced to identify aging effects and associated aging mechanisms to be inspected,

consistent with GALL Chapter III for Group 6 structures, Section 4 of ACI 349-3R-96, and the

EPRI Structural Tools document. The aging effects identified in the 0-TI-346 and LCEI-CI-C9

enhancements are included as enhancements to the Structures Monitoring Program. The staff

concurred that these enhancements are consistent with the GALL Report. 

Enhancement 2. The applicant’s program will enhance the documents to include special

inspections following the occurrence of large floods, earthquakes, tornadoes, and intense

rainfall. The staff evaluation of the affected GALL Report program element “Detection of Aging

Effects” (Element 4) for the acceptability of the second enhancement is as follows:

Detection of Aging Effects. Visual inspections are primarily used to detect degradation

of water-control structures. In some cases, instruments have been installed to measure

the behavior of water-control structures. RG 1.127 indicates that the available records

and readings of installed instruments are to be reviewed to detect any unusual

performance or distress that may be indicative of degradation. RG 1.127 describes

periodic inspections, to be performed at least once every five years. Similar intervals of

five years are specified in ACI 349.3R for inspection of structures continually exposed to

fluids or retaining fluids. Such intervals have been shown to be adequate to detect

degradation of water-control structures before they have a significant effect on plant

safety. RG 1.127 also describes special inspections immediately following the

occurrence of significant natural phenomena, such as large floods, earthquakes,

hurricanes, tornadoes, and intense local rainfalls.

The applicant’s AMP basis document states that 0-TI-246 Section 7.2 specifies a special

inspection of water-holding or water-transporting earthen structures within 30 days following

extreme environment or natural phenomena. LCEI-CI-C9 will be enhanced to include a special

inspection for the intake pumping station and gate structure No. 3, following the occurrence of

large floods, earthquakes, tornadoes, and intense rainfall. The staff concurred that this

enhancement is consistent with the GALL Report.
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Operating Experience. In LRA Section B.2.1.37, the applicant stated that plant-specific

performance results of the inspection of the Water-Control Structures Program, as implemented

by the Structures Monitoring Program to meet the requirements of 10 CFR 50.65, were

reviewed. The program has been shown to be effective in managing aging effects of structural

features and components. The applicant identified two examples of plant-specific operating

experience. 

 • Intake pumping station: very minor concrete surface cracks and platform grating clipped

 • Gate structure No. 3: very minor concrete surface cracks and spalling 

Neither was considered significant enough to affect the function of a structure.

In addition to the operating experience discussed in the LRA, the AMP evaluation stated that a

review of the operating experience for water-control structures within the scope of license

renewal did not identify any PERs (SPP-3.1 Corrective Action Program) related to RG 1.127,

“Inspection of Water-Control Structures Associated with Nuclear Power Plants.” A baseline

inspection for the Structures Monitoring Program was established in 1997 and is documented in

Calculation CDQ-0303-970086. Defect evaluations performed since the baseline inspection and

inspection results from the 2002 Structures Monitoring Program are documented in calculation

CDQ-0303-2003-0260. The Structures Monitoring Program inspections noted the above aging

effects and associated defect evaluations for water-control structures within the scope of

license renewal. Observed aging effects for water-control structures in the scope of license

renewal were evaluated not to significantly challenge the ability of water-control structures to

meet design requirements or perform their intended function.

During the onsite audit, the staff noted that the applicant incorporates internal and external

plant operating experience issues into the plant Corrective Action Program on a continuing

basis. The staff concluded there is reasonable assurance that operating experience will

continue to be reviewed in the future to ensure that the effects of aging will be adequately

managed.

The staff found that the applicant had adequately considered operating experience, consistent

with the guidance in the GALL Report.

UFSAR Supplement. In LRA Section A.1.34, the applicant provided the UFSAR supplement for

the Inspection of Water-Controlled Structures Program. The staff reviewed this section and

determined that the information in the UFSAR supplement provides an adequate summary

description of the program. The staff found this section of the UFSAR supplement met the

requirements of 10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant’s program, the staff determined

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 enhancements and

confirmed that the implementation of the enhancements prior to the period of extended

operation would result in the existing AMP being consistent with the GALL Report AMP to which

it was compared. The staff concluded that the applicant had demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff
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also reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.25 Environmental Qualification Program

Summary of Technical Information in the Application. The applicant’s EQ Program is described

in LRA Section B.3.1, “Environmental Qualification Program.” In the LRA, the applicant stated

that this is an existing program. This program is consistent, with enhancement, with GALL

AMP X.E1, “Environmental Qualification of Electric Components.”

LRA Section 4.4 affirms the applicant’s compliance with generic safety issue (GSI)-168,

“Environmental Qualification of Low-Voltage Instrumentation and Control Cables,” and follow-up

NRC Regulatory Issue Summary 2003-9, “Environmental Qualification of Low-Voltage

Instrumentation and Control Cables,” May 2, 2003, which the GALL Report cites as a currently

open generic issue with ongoing research.

The applicant follows nuclear station EQ requirements in 10 CFR 50.49. The requirements are

that each licensed facility establish an EQ Program to demonstrate that electrical components

located in harsh plant environments are qualified to perform their safety function in those harsh

environments while withstanding the effects of inservice aging. The effects of significant aging

mechanisms must be addressed as part of EQ.

In LRA Section B.3.1, the applicant stated that the EQ Program manages component thermal,

radiation, and cyclical aging effects 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 are considered TLAAs for license renewal. The staff’s evaluation is included in

SER Section 4 (see SER Section 4.4). 

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

BFN audit and review report. Furthermore, the staff reviewed the enhancement and its

justifications to determine whether the AMP, with enhancement, remains adequate to manage

the aging effects for which it is credited.

In LRA Section B.3.1, the applicant stated that the EQ Program is consistent with GALL

AMP X.E1. The staff reviewed the program elements (see SER Section 3.0.2.1) contained in

the AMP and associated bases documents, and compared them to those listed for GALL

AMP X.E1 for consistency. The staff identified three differences in the EQ component

reanalysis attributes, as discussed below.

In the AMP basis document, the applicant stated that the analytical models used in the

re-analysis of an aging evaluation will, in most cases, be the same as those applied during the

initial qualification. However, the description of GALL AMP X.E1 states that the analytical

models used in the re-analysis of an aging evaluation should be the same as those previously

applied during the prior evaluation. The staff asked under what circumstances the analytical

models used in the re-analysis of an aging evaluation would not be the same as those applied

during the initial qualification.
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The applicant stated, as documented in the staff’s BFN audit and review report, that BFN will

use the same analytical methods used in the original EQ evaluations. If a different method is

used, the basis for using the method will be documented in the EQ package. The staff found

this acceptable.

The staff noted that the LRA does not address the recommendation in GALL AMP X.E1 that a

representative number of temperature measurements be conservatively evaluated to establish

the temperatures used in an aging evaluation. 

The applicant, as documented in the staff’s audit and review report, stated that BFN currently

has no plans to monitor temperatures to extend the qualified life of EQ components. If the need

arises, a representative number of temperature measurements will be used to establish the

temperature used in the aging analysis. The collection methodology and the data collected will

be documented as part of the EQ package. The staff found this acceptable.

The staff also noted that the LRA does not address the recommendation in GALL AMP X.E1

that any changes to material activation energy values as part of a re-analysis are to be justified

on a plant-specific basis. 

The applicant stated, as documented in the staff’s audit and review report, that BFN currently

has no plans to change activation energies as part of the evaluation to extend the life of EQ

components. If during the evaluation process an activation energy is changed, the basis for

changing the value will be documented in the EQ package. The staff found this acceptable.

Enhancement. In LRA Section B.3.1, the applicant identified one enhancement to make this

AMP consistent with AMP X.E1 in the GALL Report. The EQ Program will be implemented on

Unit 1. The enhancement is scheduled for completion prior to Unit 1 re-start from its current

extended outage. The staff found this enhancement acceptable since it will make the

applicant’s program consistent for all three units.

Operating Experience. In LRA Section B.3.1, the applicant stated that operating experience is a

vital consideration in maintaining the current EQ Program and in modifying qualification bases

and conclusions, including qualified life. The engineering, technical, and programmatic

requirements and processes followed in establishing and maintaining the EQ Program include a

review of licensing, industry, and other generic documentation for EQ applications and

involvement in various utility groups.

Further, industry operating experience was incorporated into the license renewal process

through a review of industry documents to identify aging effects and mechanisms that could

challenge the intended function of SSCs within the scope of license renewal. A review of

plant-specific operating experience was also performed to identify plant-specific aging effects

and none were found.

During the onsite audit, the staff noted that the applicant incorporates internal and external

plant operating experience issues into the plant Corrective Action Program on a continuing

basis. The staff concluded there is reasonable assurance that operating experience will

continue to be reviewed in the future to ensure that the effects of aging will be adequately

managed.
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The staff found that the applicant had adequately considered operating experience, consistent

with the guidance in the GALL Report.

UFSAR Supplement. In LRA Section A.1.35, the applicant provided the UFSAR supplement for

the EQ Program. The staff reviewed this section and determined that the information in the

UFSAR supplement provides an adequate summary description of the program. The staff found

this section of the UFSAR supplement met the requirements of 10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant’s program, the staff determined

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 enhancement and

confirmed that the implementation of the enhancement prior to the period of extended operation

would result in the existing AMP being consistent with the GALL Report AMP to which it was

compared. The staff concluded that the applicant had demonstrated that the effects of aging

will be adequately managed so that the intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.26 Fatigue Monitoring Program

Summary of Technical Information in the Application. The applicant’s Fatigue Monitoring

Program is described in LRA Section B.3.2, “Fatigue Monitoring Program.” In the LRA, the

applicant stated that this is an existing program. This program is consistent, with

enhancements, with GALL AMP X.M1, “Metal Fatigue of Reactor Coolant Pressure Boundary.”

In the LRA, the applicant stated that the Fatigue Monitoring Program is used for management

of metal fatigue of select components in the reactor coolant pressure boundary and primary

containment. The fatigue monitoring program provides for monitoring fatigue stress cycles to

ensure that the design fatigue usage factor limit is not exceeded.

Aging evaluations for fatigue monitored components are considered TLAAs for license renewal.

The staff's evaluation is included in SER Section 4 (see SER Section 4.3).

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

BFN audit and review report. Furthermore, the staff reviewed the enhancements and its

justifications to determine whether the AMP, with enhancements, remains adequate to manage

the aging effects for which it is credited.

The staff reviewed the program elements (see SER Section 3.0.2.1) contained in the AMP

basis document and compared them to those listed for AMP X.M1 in the GALL Report for

consistency. The staff concluded that the elements of the Fatigue Monitoring Program are

consistent with the elements of the AMP in the GALL Report. 

The staff during the GALL consistency audit questioned how the current (starting) fatigue

cumulative usage factor (CUF) will be calculated for locations to be added to the scope of the

Fatigue Monitoring Program, as identified under program enhancements. This is needed as

initial input to either a manual or automated tracking system.
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The applicant described two alternate fatigue monitoring approaches, (1) stress-based fatigue

(SBF) and (2) cycle-based fatigue (CBF), each with a different procedure, used for calculating

the starting CUF. The staff reviewed the two procedures and concluded that the procedure to

be utilized with CBF, based on plant records of experienced transients, is reasonable and

conservative, while the procedure to be utilized with SBF, based on linear projection, is

potentially nonconservative. The staff asked the applicant to provide its technical basis for

concluding that the procedure to be utilized with SBF is reasonable and conservative, especially

in light of the industry operating experience cited by the applicant (i.e., “concerns that early-life

operating experience, at some units, had caused CUF values to increase at a faster rate than

anticipated in the original plant design”).

The applicant, as documented in the staff’s audit and review report, stated that the same

procedure, based on plant records of experienced transients, will be used to calculate the

starting CUF for both the SBF and CBF fatigue monitoring approaches. Detailed results of the

staff’s onsite audits are documented in “Audit Report for Plant Aging Management Programs

and Aging Management Reviews - Browns Ferry Nuclear Plant Units 1, 2, and 3,” dated

April 26, 2005. The staff found this acceptable.

Enhancement. In LRA Section B.3.2, the applicant identified an enhancement to make this AMP

consistent with AMP X.M1 in the GALL Report. The staff evaluation of the affected GALL

program element, “Scope of Program” (Element 1), for the acceptability of the enhancement is

as follows:

Scope of Program. The program includes preventive measures to mitigate fatigue

cracking of metal components of the reactor coolant pressure boundary caused by

anticipated cyclic strains in the material.

The applicant will, prior to the period of extended operation, enhance the Fatigue Monitoring

Program by using the EPRI-licensed FatiguePro® cycle-counting and fatigue-usage tracking

computer program. This program calculates stress cycles and resulting CUF values from

operating cycles. These calculations will be automated and performed periodically based on

information downloads from the plant’s instrumentation computers. The enhancements will

include expansion of the program coverage to include selected reactor vessel locations as

specified in LRA Table 4.3.1.1; the locations identified by NUREG/CR-6260 for environmental

fatigue evaluation, as discussed in LRA Section 4.3.4 and in accordance with the GALL Report

Section X.M1; and fatigue monitoring of the suppression chamber and suppression chamber

vents, including the vent headers and downcomers, as specified in LRA Section 4.6.1.

The staff found that the enhanced program will be consistent with GALL AMP X.M1.

Operating Experience. In the LRA, the applicant stated that since the original licensing of BFN,

the industry has sponsored the development of the EPRI-licensed FatiguePro® computer

program. This action was taken in response to staff concerns that early-life operating

experience at some units had caused CUF values to increase at a faster rate than anticipated in

the original plant design. This program provides for the incorporation of operating experience,

and is designed to ensure that the CUF values do not exceed acceptable limits in the remainder

of a unit’s operating life.
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The staff found there is reasonable assurance that the Fatigue Monitoring Program will be

effective in monitoring fatigue usage factors at critical locations, on the basis that the program

is consistent with GALL AMP X.M1.

During the onsite audit, the staff noted that the applicant incorporates internal and external

plant operating experience issues into the plant Corrective Action Program on a continuing

basis. The staff concluded there is reasonable assurance that operating experience will

continue to be reviewed in the future to ensure that the effects of aging will be adequately

managed.

UFSAR Supplement. In LRA Section A.1.36, the applicant provided the UFSAR supplement for

the Fatigue Monitoring Program. The staff reviewed this section and determined that the

information in the UFSAR supplement provides an adequate summary description of the

program. The staff found this section of the UFSAR supplement met the requirements of

10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant’s program, the staff determined

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 enhancement and

confirmed that the implementation of the enhancement prior to the period of extended operation

would result in the existing AMP being consistent with the GALL Report AMP to which it was

compared. The staff concluded that the applicant had demonstrated that the effects of aging

will be adequately managed so that the intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

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

In LRA Appendix B, the applicant identified the following plant-specific AMPs:

 • Systems Monitoring Program (B.2.1.39)

 • Bus Inspection Program (B.2.1.40)

 • Diesel Starting Air Program (B.2.1.41)

 • Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program (B.2.1.13)

For AMPs that are not consistent with or not addressed by the GALL Report, the staff

performed a complete review of the AMPs to determine if they were adequate to monitor or

manage aging. The staff’s review of these plant-specific AMPs is documented in the following

sections of this SER.

3.0.3.3.1 Systems Monitoring Program

Summary of Technical Information in the Application. The applicant’s Systems Monitoring

Program is described in LRA Section B.2.1.39, “Systems Monitoring Program.” In the LRA, the

applicant stated that this is an existing plant-specific 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 B.2.1.39, 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.

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 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 Program - In LRA Section B.2.1.39, the applicant stated that the program

requirements are for visual inspections to identify material condition (i.e., loss of

material, corrosion etc) of surfaces and components within the scope of license renewal

as identified in the AMRs. The staff found the scope of the program to be

comprehensive and acceptable because it includes the components that credit this

program, as identified in the AMR tables.

The staff confirmed that the scope of the 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 - In LRA Section B.2.1.39, the applicant stated that the Systems

Monitoring Program is a condition monitoring program; thus, there are no preventive

actions. The staff concurred with this assessment and does not identify the need for any

preventive actions associated with this program.

The staff confirmed that the preventive actions program element satisfies the criterion

defined in SRP-LR Section A.1.2.3.2. The staff concluded that this program attribute is

acceptable.

 (3) Parameters Monitored or Inspected - The LRA states that the Systems Monitoring

Program includes visual inspections to identify material condition (i.e., loss of material,

corrosion, etc.) of surfaces of systems and components prior to the loss of their

intended function. The staff found that the parameters monitored or inspected will

provide symptomatic evidence of potential degradation and, therefore, are acceptable.

The staff confirmed that the parameters monitored or inspected program element

satisfies the criterion defined in SRP-LR Section A.1.2.3.3. The staff concluded that this

program attribute is acceptable.
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 (4) Detection of Aging Effects - In LRA Section B.2.1.39, the applicant stated that the

program includes visual inspections to identify material condition (i.e., loss of material,

corrosion, etc.) of surfaces of systems and components prior to the loss of their

intended function. The system visual inspections are performed on a periodic basis and

provide for data collection on systems and components for monitoring and trending to

ensure timely detection of aging effects. Visual inspection is a continuous process with

results periodically reported in system health reports.

The staff’s review of LRA Section B.2.1.39 identified an area in which additional

information was necessary to complete the review of the applicant’s program element.

The applicant responded to the staff’s RAI as discussed below. 

In RAI B.2.1.39-1, dated October 12, 2004, the staff asked the applicant if a sampling

approach is used and, if so, to justify that the sample size is adequate. The applicant

was also requested to clarify how external surfaces of systems that are covered by

insulation, or are located in normally inaccessible areas, are to be visually inspected.

Further, the applicant was requested to clarify how elastomer degradation would be

detected by visual inspection and to clarify how external surface inspections would

detect internal aging effects caused by exposure to treated water for the flexible

connectors in the diesel generator system. 

In its response by letter dated November 3, 2004, the applicant clarified that visual

inspection is performed on accessible components during system walkdowns and that

visual inspections should encompass all or part of the total accessible system, such that

the entire system is covered over time. The applicant also clarified that the portions of

the system that are inaccessible during power operation should be walked down during

the refueling outages or forced outages. In regard to flexible connectors in the diesel

generator system, the applicant explained that the AMP identified by the LRA is

incorrect and that the internal aging effects are managed by the One-Time Inspection

Program and the external effects are managed by the Systems Monitoring Program.

The staff found the applicant’s response acceptable on the basis that there is

reasonable assurance that visual inspections of accessible surfaces of systems and

components, combined with inspections during outages, are capable of detecting the

aging effects that are covered by this program. The use of visual inspections to detect

external degradation is consistent with industry practice.

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 - In LRA Section B.2.1.39, the applicant stated that the

inspected systems and components are monitored, trended, and documented by the

use of System Health Reports, the Corrective Action Program, and the Corrective

Maintenance Program. The staff found that the overall monitoring and trending

proposed by the applicant are acceptable because there is reasonable assurance that

an effective walkdown program combined with the Corrective Action Program and the

Corrective Maintenance Program will effectively manage the applicable aging effects.
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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 - In LRA Section B.2.1.39, the applicant stated that during a system

or component visual inspection, system engineers use their knowledge of the UFSAR,

TSs, design basis documents, operating experience, and the plant operating, technical,

and maintenance procedures to evaluate system physical attributes and operational

characteristics. In RAI B.2.1.39-1, the applicant was also requested to clarify the

acceptance criteria applied in the inspection or evaluation of degradation. In its

response, the applicant provided guidance to the system engineer, which is that there

should be no evidence of steam or water leakage and system wastage, and that surface

condition of welds appear satisfactory. The staff found that a detailed look at the

material condition and degraded components by a knowledgeable system engineer,

combined with effective corrective actions, are a reasonable approach to detect and

evaluate degradation in applying design basis acceptance criteria.

The staff confirmed that the acceptance criteria program element satisfies the criteria

defined in SRP-LR Section A.1.2.3.6. The staff concluded that this program attribute is

acceptable.

 (10) Operating Experience - In LRA Section B.2.1.39, the applicant stated that the Systems

Monitoring Program produces system health reports, which provide a review of systems

and components’ operating experience. The LRA also states that the effectiveness of

the corrective actions have been evaluated and documented in system health reports. In

RAI B.2.1.39-1, the staff further asked the applicant to identify specific operating

experience that provides objective evidence to support the conclusion that the Systems

Monitoring Program is effective in managing aging effects on the external surfaces of

systems and components within the scope of the program. In the response dated,

November 3, 2004, the applicant clarified that the Systems Monitoring Program, through

the use of PERs and WOs, tracks and trends corrective actions and provides objective

evidence to support a determination that the effects of aging will be adequately

managed so that the systems and components intended function will be maintained

during the period of extended operation. The staff found that there is reasonable

assurance that the applicant’s use of system health reports combined with PERs and

WOs should provide objective evidence to support the conclusion that the program will

adequately manage the aging effects in the systems and components that credit this

program. Therefore, the staff’s concerns described in RAI.2.1.39-1 are resolved.

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.

UFSAR Supplement. In LRA Section A.2.1, the applicant provided the UFSAR supplement for

the Systems Monitoring Program. The staff reviewed this section and determined that the

information in the UFSAR supplement provides an adequate summary description of the

program. The staff found this section of the UFSAR supplement met the requirements of

10 CFR 54.21(d).
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Conclusion. On the basis of its review, RAI response, and audit of the applicant’s program, the

staff concluded that the applicant had demonstrated that the effects of aging will be adequately

managed so that the intended functions will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the

UFSAR supplements for this AMP and found that they provide an adequate summary

description of the program, as required by 10 CFR 54.21(d).

3.0.3.3.2 Bus Inspection Program

Summary of Technical Information in the Application. The applicant’s Bus Inspection Program is

described in LRA Section B.2.1.40, “Bus Inspection Program.” In the LRA, the applicant stated

that this is a new plant-specific program. 

In the LRA, the applicant stated that the Bus Inspection Program will be initiated prior to the

period of extended operation. This commitment is identified on the applicant's license renewal

commitment list as Item 38. The applicant stated that this is a non-GALL program and will

provide reasonable assurance that the bus ducts will continue to perform their intended function

consistent with the CLB through the period of extended operation.

The Bus Inspection Program will provide reasonable assurance that the intended functions of

isolated and nonsegregated phase bus will be maintained consistent with the CLB through the

period of extended operation. It will manage nonsegregated phase bus insulation exposed to

adverse localized environments caused by heat in the presence of oxygen and loosening the

fastening hardware associated with isolated and non-segregated phase bus due to cyclic

loading resulting in thermal expansion and contraction. The program will also include inspection

of the bus enclosure. 

This program will manage all portions of isolated and non-segregated phase bus associated

with the unit station service transformers, main transformers, and common station service

transformers within the scope of license renewal. 

The aging mechanisms managed by this program include degradation of the nonsegregated

phase bus insulation caused by heat in the presence of oxygen and cyclic loading of isolated

and non-segregated phase bus causing thermal expansion and contraction of the bus, which

could loosen the bus connection fastening hardware. Any one of these conditions could lead to

a failure, preventing the phase bus from performing its intended function. 

The program will be performed in conjunction with routine maintenance activities. The program

will include visual inspection and electrical testing of in-scope, non-segregated phase bus for

evidence of loosened bolted bus connections and damage to bus insulation. The program will

also include visual inspection and electrical testing of in-scope isolated phase bus for evidence

of loosened bolted bus connections and visual inspection of the in-scope isolated and

non-segregated phase bus enclosure for excessive dust build up, evidence of water intrusion,

and debris.

Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information

included in LRA Section B.2.1.40, regarding the applicant’s demonstration of the Bus Inspection

Program to ensure that the effects of aging will be adequately managed so that the intended
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functions will be maintained consistent with the CLB throughout the period of extended

operation. 

The staff reviewed the Bus Inspection Program against the AMP elements found in 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.

The staff’s review of LRA Section B.2.1.40 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. 

In RAI 3.6-4, dated November 4, 2004, the staff requested the applicant to provide additional

information regarding details of the program elements of the AMP.

In its response, by letter December 9, 2004, the applicant provided the augmented details for

the seven program elements as follows.

 (1) Scope of Program - This program applies to the isolated phase bus duct, as well as the

non-segregated bus ducts associated with the unit station service transformers, main

transformers, and common station service transformers within the scope of license

renewal.

The staff confirmed that the scope of the 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 - In LRA Section B.2.1.40, the applicant stated that the Bus

Inspection Program will be a condition monitoring program. No actions will be taken as

part of this program to prevent or mitigate aging degradation. This is acceptable

because the staff found no need for such actions.

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 - In LRA Section B.2.1.40, the applicant stated that

the bus insulation will be visually inspected for embrittlement, cracking, melting,

discoloration, or other damage. In addition, the bus insulation will be tested using a

proven test for detecting deterioration of the insulation system, such as insulation

resistance, or other testing that is state-of-the-art at the time the test is performed. The

specific type of test performed will be determined prior to the initial test. Bolted bus
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connections will be visually inspected for evidence of burning or heat-up on tape

connections, loose connections or arcing on boot-type cover sleeves, and evidence of

tracking, corrosion, or ground faults on uninsulated connections. In addition, the bolted

bus connections will be tested using a proven test for detecting deterioration of the

bolted connection, such as micro-ohm resistance or other testing that is state-of-the-art

at the time the test is performed. The specific type of test performed will be determined

prior to the initial test.

The applicant stated that the bus enclosure internal will be visually inspected for foreign

debris, excessive dust build-up, and evidence of water intrusion. Additionally, the

internal bus supports and insulators that are visible from the inspection hatches will be

inspected for structural integrity and signs of cracks.

The staff found that the visual inspection of bus ducts, bus bar, and internal bus

supports will provide an indication of aging effects. Additionally, testing of bolted

connections and insulation system will provide assurance that bus ducts are not

exposed to excessive ohmic or ambient heating. 

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 this

program attribute is acceptable.

 (4) Detection of Aging Effects - In LRA Section B.2.1.40, the applicant stated that the

detection of aging effects will commence prior to the expiration of the current 40-year

license for each unit, and will be conducted at least once every 10 years thereafter

throughout the period of extended operation. The staff found that the 10-year inspection

frequency is an adequate period to preclude failure of bus ducts because industry

experience has shown that the aging degradation is a slow process.

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 - In LRA Section B.2.1.40, the applicant stated that trending is

not a required attribute of this program. 

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 - In LRA Section B.2.1.40, the applicant stated that phase bus

insulation must be free of embrittlement, cracking, melting, discoloration, or other

damage; and it must pass the acceptance criteria established for the test being

performed. The bus enclosure will be free of unacceptable indications of cracks,

corrosion, foreign debris, excessive dust build-up, and evidence of water intrusion.

Bolted bus connection splice shall not have any of the following signs:

 • For taped connections: tape burning/heating-up, tape cracking, corona effects,

or other damage
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 • For boot type cover splices: "as found" loose connections and arcing damage

 • For uninsulated connections: evidence of tracking, corrosion, or ground faults 

It shall also pass the acceptance criteria established for the test being performed.

The staff found this to be acceptable since the acceptance criteria are based on the

inspections and test acceptance criteria.

The staff confirmed that the acceptance criteria program element satisfies the criteria

defined in SRP-LR Section A.1.2.3.6. The staff concluded that this program attribute is

acceptable.

 (10) Operating Experience - In LRA Section B.2.1.40, the applicant stated that this is a new

AMP; therefore, no operating experience exists. In response to the staff’s RAI 3.6-4, the

applicant stated that both industry and plant-specific experience was reviewed and

considered in the program. The staff found that the proposed program will provide

assurance that bus ducts are not exposed to excessive ohmic or ambient heating.

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.

In reviewing the program elements and based on implementation of the Bus Inspection

Program, the staff found that there is reasonable assurance that the aging effects of

non-segregated phase bus insulation and loosening of fastening hardware associated with

isolated and non-segregated phase bus will be adequately managed such that isolated and

non-segregated phase bus will continue to perform its intended functions for the period of

extended operation. 

UFSAR Supplement. In LRA Section A.2.2, the applicant provided the UFSAR supplement for

the Bus Inspection Program. The staff reviewed this section and determined that the

information in the UFSAR supplement provides an adequate summary description of the

program. The staff found this section of the UFSAR supplement met 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 concluded that the applicant had demonstrated that the effects of aging will be adequately

managed so that the intended functions will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the

UFSAR supplements for this AMP and found that they provide an adequate summary

description of the program, as required by 10 CFR 54.21(d).

3.0.3.3.3 Diesel Starting Air Program

Summary of Technical Information in the Application. The applicant’s Diesel Starting Air

Program is described in LRA Section B.2.1.41, “Diesel Starting Air Program.” In the LRA, the

applicant stated that this is an existing plant-specific program. 
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The Diesel Starting Air Program manages the emergency diesel generator (EDG) starting air

system. This program was originally developed in response to plant operating experience with

corrosion in the system, and will be enhanced with additional inspections for license renewal.

The program includes the preventive actions of replacing filters and desiccant, and inspections

of the system components to verify that unacceptable corrosion is not occurring. The Diesel

Generator Starting Air Program is credited for managing the loss of material due to general

corrosion of carbon, low-alloy, cast iron, and cast-iron alloy components in the diesel generator

starting air system (LRA Table 3.3.2.30). 

Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information

included in LRA Section B.2.1.41, regarding the applicant’s demonstration of the Diesel Starting

Air 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 Diesel Starting Air 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 discussed in SER Section 3.0.4. The remaining seven elements

are discussed below.

 (1) Scope of Program - In LRA Section B.2.1.41, the applicant stated that the program

scope includes the starting air systems for the EDGs. LRA Table 3.3.2.30 shows that

the program is used to manage general corrosion of carbon and 

low-alloy steel, as well as cast iron and cast-iron alloy components in an air/gas internal

environment. The components include air-start motors, fittings, piping, strainers, tanks,

tubing, and valves. 

The staff confirmed that the scope of the 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 - In LRA Section B.2.1.41, the applicant stated that the mitigative

actions include filter replacement and desiccant replacement. These actions maintain

the air quality and thereby reduce corrosion. The staff found that these are appropriate

preventive measures for reducing the effects of aging of the EDG air system.

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 - In LRA Section B.2.1.41, the applicant stated that

the program provides for periodic inspection of moisture traps, pilot valves, and lift check
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valves for corrosion, erosion, pitting, and wear. These inspections are beyond the

identified aging effects of the long-lived passive components covered by the scope of

the Rule (and included in LRA Table 3.3.2.20), but are acceptable because they will

provide early indication of aging that would result from a reduction of air quality, and will

address the plant operating experience (see below). The LRA also states that the diesel

generator starting air piping and receivers will be inspected for loss of material using the

One-Time Inspection Program. The staff considers this an acceptable inspection for

confirming that any aging is not significant.

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 this

program attribute is acceptable.

 (4) Detection of Aging Effects - In LRA Section B.2.1.41, the applicant stated that the

detection of aging effects is through the periodic visual inspection of the moisture traps,

pilot valves, and lift check valves. The inspections are for corrosion, erosion, pitting, and

wear. In addition, the LRA states that the One-Time Inspection Program will be used to

inspect for loss of material in the emergency diesel starting air system piping and

receivers. The staff’s review of the One-Time Inspection Program is in SER

Section 3.0.3.1.7. The staff found that these are appropriate inspections for the

identified aging effects.

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 - In LRA Section B.2.1.41, the applicant stated that this

program is implemented through the Preventive Maintenance Program, which includes

provisions for monitoring and trending. In addition, failure to meet acceptance criteria

will result in corrective actions. The staff found that this is reasonable and acceptable

monitoring and trending. 

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 - In LRA Section B.2.1.41, the applicant stated that the acceptance

criteria are typically qualitative. An example would be “absence of corrosion.” If these

criteria are not met, corrective actions result in an evaluation to ensure that the intended

functions are maintained. The staff found that performing an evaluation to ensure the

intended functions are maintained is an acceptable method of managing aging.

The staff confirmed that the acceptance criteria program element satisfies the criteria

defined in SRP-LR Section A.1.2.3.6. The staff concluded that this program attribute is

acceptable.

 (10) Operating Experience - In LRA Section B.2.1.41, the applicant stated that during the

1980s, the diesel generator air-start system experienced failures of the air-start solenoid

valves during a start sequence. The air-start motor did not disengage due to corrosion
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debris, which pitted the air solenoid valve seats, preventing the air-start solenoid valves

from completely closing. In response, the applicant modified the system by installing air

dryers and moisture traps, implemented periodic maintenance including the replacement

of filters and desiccant, and verified the effectiveness of the modifications with

inspections.

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.

UFSAR Supplement. In LRA Section A.2.3, the applicant provided the UFSAR supplement for

the Diesel Starting Air Program. The staff reviewed this section and determined that the

information in the UFSAR supplement provides an adequate summary description of the

program. The staff found this section of the UFSAR supplement met the requirements of

10 CFR 54.21(d).

Conclusion. On the basis of its review of the applicant’s program, the staff determined that the

applicant had demonstrated that it will adequately manage the effects of aging so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement

for this AMP and concluded that it provides an adequate summary description of the program,

as required by 10 CFR 54.21(d). 

3.0.3.3.4 Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program (B.2.1.13)

Summary of Technical Information in the Application. In its response to RAI 3.1.2.2-9 (see

Section 3.1.2.3.17), the applicant determined that this program should be deleted, however, the

staff decided to keep the evaluation as follows for the limited program scope.

The Thermal Aging Embrittlement of CASS Program is discussed in LRA Section B.2.1.13. The

applicant stated that the only CASS components within the scope of license renewal that were

determined to be susceptible to thermal aging embrittlement are the main steam line

flow-restricting venturis. The material of the venturis is low-molybdenum with a delta ferrite

content of 18.3 percent. The venturis are exposed to a reactor steam environment that is less

than 320 °C (610 °F). The applicant stated that, based on evaluation of material and

environmental characteristics in accordance with the guidelines of EPRI Technical Report

1000976, “Evaluation of Thermal Aging Embrittlement for Cast Austenitic Stainless Steel

Components - January 2001,” a Thermal Aging Embrittlement of CASS Program is not

required.

Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the applicant’s

Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program to determine the

validity of the applicant’s conclusion that a Thermal Aging Embrittlement of CASS Program is

not required, and to ensure that the intended function(s) of the components will be maintained

consistent with the CLB for the period of extended operation.

CASS exposed to elevated temperatures is subject to thermal aging during service. The effects

of thermal aging include increases in tensile and a decrease in fracture toughness. The

decrease in fracture toughness is proportional to the level of ferrite in the material. Thermal
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aging of susceptible materials will continue until a saturation or fully aged point is reached. The

staff’s position regarding thermal aging of CASS components is detailed in the letter from

Christopher Grimes (NRC) to Douglas Waters, (NEI), dated May 19, 2000. In order to

determine if the applicant evaluated the CASS components in accordance with the

aforementioned letter, the staff requested additional information from the applicant. The

applicant responded to the staff’s RAI as discussed below. 

In RAI B.2.1.13-1, the staff requested that the applicant provide the material specification

including material grade, chemical content, casting method, percent ferrite, and operating

temperature for the flow-restricting venturis. The staff also requested the applicant to confirm

that the flow-restricting venturis had been evaluated in accordance with the above referenced

staff letter dated May 19, 2000, and to state if the venturis were potentially susceptible to

thermal aging embrittlement when screened using the criteria outlined in the aforementioned

letter. 

In its response, by letter dated December 9, 2004, the applicant stated that the main steam line

flow-restricting venturis are ASTM A 351 Grade CF8. The actual chemistry and casting method

are not known by the applicant. The operating temperature of the main steam line is 550 °F,

and the applicant calculated the delta ferrite content to be 18.3 percent. Although the applicant

does not know the precise chemistry of the components, it used worst-case values for the

chemistry range of ASTM A 351 Grade CF8, as listed in the 1975 Annual Book of ASTM

Standards, to calculate the delta ferrite content using Hull’s equivalent factors in

NUREG/CR-4513, “Estimation of Fracture Toughness of Cast Stainless Steels During Thermal

Aging in LWR Systems.”

Based on the screening criteria listed in Table 2 of the NRC letter dated May 19, 2000, neither

statically or centrifugally cast components with a low molybdenum content (0.5 percent max.)

and a delta ferrite level less than 20 percent are susceptible to thermal aging embrittlement.

The applicant stated in its response to RAI B.2.1.13-1 that the CASS flow-restricting venturis

have been evaluated for thermal aging in accordance with the guidance detailed in the May 19,

2000, NRC letter. Based on the applicant’s evaluation of the flow-restricting venturis in

accordance with the NRC letter, the staff found acceptable the applicant’s conclusion that a

CASS AMP is not required. 

Conclusion. The staff reviewed the information provided in LRA Section B.2.1.13 as

supplemented by the applicant’s response to the staff’s RAI. On the basis of this review, the

staff concluded that the applicant had demonstrated that a thermal aging embrittlement of

CASS AMP is not required and hence no aging management for Thermal Aging Embrittlement

of Cast Austenitic Stainless Steel Program, as required by 10 CFR 54.21(a)(3), is required for

the only CASS components within the scope of license renewal in the LRA application.

3.0.3.3.5 Unit 1 Periodic Inspection Program (B.2.1.42)

Summary of Technical Information in the Application. In the LRA, the applicant did not include a

description of the new, plant-specific AMP B.2.1.42, “Unit 1 Periodic Inspection Program.”

During the course of the staff’s AMR of Unit 1 systems in layup for the extended outage, it was

realized that neither the GALL-recommended one-time inspection nor the Unit 1 restart

inspection would be sufficient in itself to monitor the effects of any new degradation that will

manifest during the period of extended operation. This plant-specific program is designed to
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monitor the condition of and perform periodic inspections of components that were in layup and

have been requalified without replacement. A program description and a history of the program

development is described below (see Sections 3.7.1.2 and 3.7.1.3).

Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information

included in AMP B.2.1.42 regarding the applicant’s demonstration of the Unit 1 Periodic

Inspection Program to ensure that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB throughout the period of extended

operation. 

The staff reviewed the Periodic Inspection Program against the AMP elements found in the

SRP-LR Section A.1.2.3 and Table A.1-1, and focused on how the program manages aging

effects through the effective incorporation of the 10 program 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.

The program was initially submitted for review by TVA letter dated August 4, 2005. The staff

review determined that the required information submitted was not entirely complete or

consistent with the information identified in SRP-LR Section A.1.2.3. On September 2, 2005, in

an informal communication (8 staff questions) and in a formal meeting summary dated October

31, 2005, the staff requested additional information to support their review. The program was

revised and resubmitted by TVA letter dated November 16, 2005.

In NRC Question 1, the staff requested the applicant to review the entire SRP-LR Section

A.1.2.3 and to include additional applicable information. In NRC Question 2, the staff also

identified a general concern that, in the description of the program, the use of the term “failures”

is not appropriate for license renewal. In response, the applicant revised the term “failures” to

read, “acceptable degradation.” The applicant also revised the UFSAR Section A.2.4 and the

description of each element to include the information identified in SRP-LR Section A.1.2.3, as

discussed below.

 (1) Scope of Program - In AMP Section B.2.1.42, the applicant stated that the program

provides periodic monitoring of the non-replaced piping/fittings that were not in service

supporting operation of Units 2 and 3. This piping is carbon/low-alloy or stainless steel

that was exposed to air, treated water, or raw water during the extended Unit 1

shutdown. The susceptible locations identified are those areas determined to have the

highest potential for service-induced wear or latent aging effects. The staff found, in

general, the scope of the program to be comprehensive and acceptable because it

includes components that were subject to lay-up at locations most susceptible to

degradation as a result of the extended outage. The applicant’s response to Question 3,

letter dated November 16, 2005 revision, did not include a detailed AMR table (Table 3)

in a standard format. The format should include listing of system and components, and

specify reference to the new Inspection program, “B.2.1.42 Unit 1 Periodic Inspection
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Program.” as the AMP. This did not allow a staff review of specific combinations of

components, materials, environments and aging effects to be managed by the new Unit

1 Periodic Inspection Program. In addition, the applicant did not respond to NRC

Question 3(b) concerning the number of sample locations. Instead, the applicant stated

that its earlier response, dated May 18, 2005, in a table titled,“NDE Examinations

Performed for Original Non-replaced Piping, (3 sheets),” had identified specific

components, piping, and welds that will be included in the scope of this new program.

The applicant stated that the table included piping and welds in the RHRSW, Fire

protection, EECW, RCW, CRD, CS, FW, HPCI, MS, RCIC, RHR, and RBCCW systems.

 The staff accepts this list to satisfy the requirement of the program element “scope” in

lieu of the detailed AMR table for purpose of this evaluation. However, in a

teleconference with the applicant on December 7, 2005, the applicant agreed (letter

dated December 20, 2005) to perform a revision of the LRA AMR Tables (Table 3) to

add the newly identified piping and components that will be included in the scope of the

program and identify these in appropriate systems tables in a future revision. Also, the

applicant agreed to review the adequacy of the number of sample locations on the basis

of a 95/95 confidence level.

The staff confirmed that the scope of the program element satisfies the criterion defined

in SRP-LR Section A.1.2.3.1. The staff concluded that the program attribute is

acceptable.

 (2) Preventive Actions - In the initial program Element 2, the applicant identified the Unit 1

Periodic Inspection Program as a detection program. Programs are normally identified

as condition monitoring, performance monitoring, or prevention and mitigation

programs. In NRC Question 5, the staff requested the applicant to clarify that the

program is a condition monitoring program. In the revised AMP Section B.2.1.42, the

applicant stated that the program is a condition monitoring program and, thus, there are

no preventive actions. The staff concurred with this assessment and does not identify

the need for any preventive actions associated with this program.

The staff confirmed that the preventive actions program element satisfies the criterion

defined in SRP-LR Section A.1.2.3.2. The staff concluded that the program attribute is

acceptable.

 (3) Parameters Monitored or Inspected - In AMP Section B.2.1.42, the applicant clarified

that the Unit 1 Periodic Inspection Program is a condition monitoring program and only

the first two items of the SRP-LR are applicable. The applicant identified that the

selected sample will be examined by the same or equivalent, methodology (UT

thickness for piping and UT shear wave and surface exam for weld), as performed to

determine acceptability of not replacing piping sections prior to restart. The applicant

stated that the susceptible locations were those areas determined to have the highest

potential for service-induced wear or latent aging effects, which includes all types of

corrosion. The applicant also identified that the inspection techniques utilized evaluate

internal conditions and are sensitive to the presence of unacceptable conditions,

including wear, erosion, corrosion (including crevice corrosion) if present. In addition,

the applicant initially identified that the sample selected for periodic inspection will be

based on a 90/90 confidence level consistent with the methodology identified in EPRI

107514. The staff was concerned that a 90/90 confidence level may not be appropriate
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and that EPRI 107514 had not been reviewed by the staff. In NRC Question 4, the staff

requested the applicant to clarify whether application of EPRI 107514 represented an

industry consensus for selecting a sample on the basis of 90/90 criteria. The applicant

was also requested to identify the sample size on the basis of 90/90 criteria versus

95/95 and to justify selecting a sample size on the basis of the 90/90 criteria versus the

more restrictive 95/95 criteria. In its response, dated November 16, 2005, the applicant

revised the sample size basis to reflect a confidence level of 95/95 and replaced the

EPRI reference with “Elementary Statistical Analysis.” The staff’s review of the

acceptability of the revised basis for the sample size is further discussed under

Element 4. The staff found that the parameters monitored or inspected will provide

symptomatic evidence of potential degradation and, therefore, are acceptable.

The staff confirmed that the parameters monitored or inspected program element

satisfies the criterion defined in SRP-LR Section A.1.2.3.3. The staff concluded that this

program attribute is acceptable.

 (4) Detection of Aging Effects - SRP Section A.1.2.3.4 states that the applicant is to provide

justification, including codes and standards referenced, that the inspection technique

and frequency are adequate to detect the aging effects before a loss of SC intended

function. In the initial submittal of AMP B.2.1.42, the applicant did not identify any codes

and standards. In NRC Question 6, the staff requested the applicant to include

additional information to demonstrate that the technique and frequency of future

inspections is justified. In revised AMP Section B.2.1.42, in its submittal dated

November 16, 2005, the applicant stated that the program is not covered by industry

codes or standards and the selected inspection methodologies are based on the

inspections performed to determine whether components require replacement prior to

restart. The applicant also stated that the examination techniques utilized for the

baseline inspection were ultrasonic thickness measurements for the piping and

ultrasonic shear wave for welds. The applicant identified that the restart inspections can

be used as a baseline and additional periodic inspections of sample locations will be

performed after Unit 1 is returned to service and again within the first ten years of the

period of extended operation. The use of ultrasonic thickness measurements and

ultrasonic shear wave techniques should be capable of detecting most forms of internal

degradation of the piping and welds caused by the extended outage. The staff was

concerned that inspections may not be performed to recognized codes and standards

and UT inspection may not be the best technique to detect certain types of corrosion.

The staff believes that codes and standards such as ASME Section V and ASTM, are

appropriate references. Based on industry standards such as ASTM G46-94 and

standard practices identified in EPRI documents and the GALL Report, visual

inspections may be a more appropriate technique to identify certain types of internal

degradation, such as pitting and MIC. Therefore, the applicant was requested to identify

specific codes and standards used for periodic inspections and evaluate the

acceptability of UT alone to detect all forms of corrosion. In a teleconference with the

applicant on December 7, 2005 (applicant submittal dated December 20, 2005) the

applicant indicated that internal visual inspections are performed as part of other aging

management programs when the system is open, but UT is preferred for periodic

inspection trending purposes, since opportunistic internal inspections are limited by

accessibility. The applicant stated that it will also perform suitable trending for
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degradations that could appear during the extended operation, and will apply BFN’s

Corrective Action Program including appropriate mitigative action if any degradation

could lead to loss of intended function. The staff found that a combination of

opportunistic internal visual inspections combined with periodic UT inspections to be

acceptable techniques to detect latent aging effects. 

In regard to the basis for the sample size addressed in the SRP-LR “Detection of Aging

Effects” element, the applicant described the sample size basis under Element 3,

“Parameters Monitored or Inspected.” The applicant applied a statistical analysis to

establish a confidence level of 95/95 for selecting a sample size within a common

material and environment. In SER Section A.2.4, submitted by letter dated October 19,

2005, the applicant stated that if unacceptable degradation is identified, the sample size

will be appropriately expanded. Although the applicant did not respond to staff’s request

in NRC Question 3(b) concerning the number of sample locations (scope) to be

inspected, the applicant did adequately identify the basis for the sample size. 

The staff concurred that application of periodic internal visual and ultrasonic inspections

are acceptable to detect that aging effects may be occurred during the extended outage.

The staff found that the 95/95 confidence level is an acceptable basis for determining an

adequate sample size and that a provision to expand the sample size is consistent with

industry practice and SRP-LR Section A.1.2.3.4. The staff concluded that this program

attribute is acceptable.

 (5) Monitoring and Trending - In the initial submittal of AMP B.2.1.42, the applicant did not

identify if results will be monitored and trended. In NRC question 7, the staff requested

the applicant to clarify that results will be monitored and trended. In its response, the

applicant confirmed that the program has been revised to clarify the requirement to

monitor and trend the results of periodic inspections. In revised AMP Section B.2.1.42,

the applicant stated that the inspection frequency is re-evaluated each time the

inspection is performed and can be changed based on the trend of the results. SRP-LR

Section A.1.2.3.5 states that plant-specific and/or industry-wide operating experience

may be considered in evaluating the appropriateness of the technique and frequency.

The staff found that the overall monitoring and trending proposed by the applicant are

acceptable because there is reasonable assurance that effective periodic inspections

combined with the Corrective Action Program will effectively manage the applicable

aging effects.

The staff confirmed that the monitoring and trending program element satisfies the

criterion defined in SRP-LR Section A.1.2.3.5. The staff concluded that this program

attribute is acceptable.

 (6) Acceptance Criteria - In AMP Section B.2.1.42, the applicant stated that the acceptance

criteria is that the pipe wall will remain above minimum acceptable wall thickness until

the next periodic inspection, and that no unacceptable weld cracks exist. The staff found

that the application of minimum wall thickness and no unacceptable weld cracks based

on the Code of record to be reasonable and appropriate acceptance criteria to maintain

the intended functions of the components inspected.
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The staff confirmed that the acceptance criteria program element satisfies the criterion

defined in SRP-LR Section A.1.2.3.6. The staff concluded that this program attribute is

acceptable.

 (10) Operating Experience - In NRC Question 8 of the informal staff request of September 2,

2005, the staff requested the applicant to identify a commitment to provide (or have

available for review) operating experience for this new program in the future to confirm

its effectiveness. The applicant’s response confirmed that the program has been revised

to clarify the requirement to evaluate the results of the periodic inspections to verify

program effectiveness. In the revised version of AMP Section B.2.1.42, the applicant

stated that the Unit 1 Periodic Inspection Program is a new program that will monitor the

operating conditions of Unit 1 components that were not replaced during the Unit 1

restart. The applicant credits the trending data developed in Element 5 to demonstrate

the effectiveness of the Unit 1 Periodic Inspection Program. The staff found that there is

reasonable assurance that the use of trending data will provide objective evidence to

determine the effectiveness of the periodic inspection program.

The staff confirmed that the operating experience program element satisfies the criterion

defined in SRP-LR Section A.1.2.3.10. The staff concluded that this program attribute is

acceptable.

UFSAR Supplement. By letter dated November 16, 2005, the applicant provided the following

UFSAR supplement for the Unit 1 Periodic Inspection Program:

The Unit 1 Periodic Inspection Program is a new program that performs periodic

inspections of the non-replaced piping/fittings that were not in service supporting

operation of Units 2 and 3 following the extended Unit 1 outage to verify that no latent

aging effects are occurring, and to correct degraded conditions prior to loss of function. 

During the Unit 1 restart project, examinations were performed to verify acceptability of

the existing piping that was not replaced. The specific examinations are discussed in the

TVA Letter to the U.S. Nuclear Regulatory Commission, Document Control Desk,

“Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 - License Renewal Application

(LRA) – Response to NRC Request for Additional Information Concerning the Unit 1

Lay-up Program (TAC Nos. MC1704, MC1705, and MC1706)” dated May 18, 2005. This

piping is carbon/low-alloy or stainless steel that was exposed to air, treated water, or

raw water during the extended Unit 1 shutdown. The Unit 1 Periodic Inspection Program

will examine a sample of those locations examined for plant restart as discussed in the

referenced letter to verify that no latent aging effects are occurring. The sample size will

be determined in accordance with the sampling methodology described in S. S. Wilks,

“Elementary Statistical Analysis,” Princeton University Press, 1948. If unacceptable

degradation is identified, the sample size will be appropriately expanded. The initial

sample, once selected, will be utilized in subsequent inspections, if practical.

These periodic inspections are in addition to the restart inspections performed prior to

Unit 1 restart. The Unit 1 periodic inspections will be performed after Unit 1 is returned

to operation. The susceptible locations identified are those areas determined to have the

highest potential for service-induced wear or latent aging effects. The inspection
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techniques utilized evaluate internal conditions that are sensitive to the presence of

unacceptable conditions including wear, erosion, and corrosion (including crevice

corrosion) if present. For these locations, the restart inspections can be utilized as a

baseline for comparison.

The Unit 1 periodic inspections will be performed after Unit 1 is returned to operation

and prior to the end of the current operating period. The second periodic inspection of

all sample locations will be completed within the first ten E2-9 years of the period of

extended operation. The inspection frequency is re-evaluated each time the inspection

is performed and can be changed based on the trend of the results. The inspections will

continue until the trend of the results provides a basis to discontinue the inspections.

The staff reviewed the above UFSAR supplement and determined that it provides an adequate

summary description of the program. The staff found that this section of the UFSAR

supplement met the requirements of 10 CFR 54.21(d).

Conclusion. On the basis of its review of the applicant’s program, the staff found that the Unit 1

Periodic Inspection Program adequately addresses the 10 program elements identified in

Appendix A of the SRP-LR, and that the program will adequately manage the aging effects for

which it is credited. The staff also reviewed the UFSAR supplement for this aging management

program 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. 

SRP-LR, Branch Technical Position RLSB-1, "Aging Management Review - Generic," describes

ten attributes of an acceptable AMP. Three of these ten attributes are associated with the

quality assurance activities of corrective action, confirmation processes, and administrative

controls. Table A.1-1, "Elements of an Aging Management Program for License Renewal," of

Branch Technical Position RLSB-1 provides the following description of these quality attributes:

 • Corrective actions, including root cause determination and prevention of recurrence,

should be timely.

 • The confirmation process should ensure that preventive actions are adequate and that

appropriate corrective actions have been completed and are effective.

 • Administrative controls should provide a formal review and approval process.

SRP-LR, Branch Technical Position IQMB-1, "Quality Assurance For Aging Management

Programs," noted that those aspects of the AMP that affect quality of SR SSCs are subject to

the quality assurance (QA) requirements of 10 CFR Part 50, Appendix B. Additionally, for NSR

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, the confirmation process, and

administrative controls. Branch Technical Position IQMB-1 provides the following guidance with

regard to the QA attributes of AMPs:
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 • SR structures and components 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 NSR SCs that are subject to an AMR for license renewal, an applicant has an option

to expand the scope of its 10 CFR Part 50 Appendix B program to include these

structures and components to address corrective actions, the confirmation process, and

administrative controls for aging management during the period of extended operation.

In this case, the applicant should document such a commitment in the FSAR

supplement in accordance with 10 CFR 54.21(d).

3.0.4.1 Summary of Technical Information in the Application

LRA Section 3.0, "Aging Management Review Results," provides an AMR summary for each

unique structure, component, or commodity group at Units 2 and 3, (Unit 1 is in an extended

outage) 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 Appendix A, "UFSAR Supplement," and Appendix B, "Aging

Management Program Descriptions," demonstrate how the identified programs manage aging

effects using attributes consistent with the industry and staff guidance. In LRA Appendix A, the

applicant does not commit that the QA Program includes the elements of corrective action,

confirmation process, and administrative controls or that it is applicable to both SR and NSR

SSCs that are within the scope of license renewal. However, in LRA Section B.1.3, “Quality

Assurance and Administrative Controls," in "Aging Management Program Descriptions," the

applicant stated that the QA Program implements the requirements of 10 CFR Part 50,

Appendix B, and is consistent with the summary in SRP-LR Appendix A.2 (Reference B-1). The

QA Program includes the elements of corrective action, confirmation process, and

administrative control, and it is applicable to the SR and NSR 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 a Problem Evaluation Report (PER) in accordance with the applicant’s nuclear

procedure established to implement the provisions of 10 CFR Part 50 Appendix B. Plant

procedures require the initiation of a PER to document actual or potential problems, including

unexpected plant equipment degradation, damage, failure, malfunction, or loss. Site procedures

that implement aging management activities for license renewal require that a PER be prepared

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 a PER also be initiated if required.

Confirmation Process. The confirmation process ensures that follow-up actions are taken to

verify effective implementation of corrective actions. The measure of effectiveness is in terms of

correcting the adverse conditions and precluding their recurrence. Relevant applicant

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. The procedure requires determinations. The corrective action
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process also requires monitoring for potentially adverse trends. A PER is required if adverse

trends persist. Since the same 10 CFR 50, Appendix B, corrective action and confirmation

process is applied for nonconforming SR and NSR SCs subject to AMR for license renewal, the

Corrective Action Program is consistent with the GALL Report.

Administrative Controls. AMPs 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, and, therefore

are consistent with SRP-LR.

3.0.4.2 Staff Evaluation

The staff reviewed the applicant's QA controls for AMPs as described in the LRA. The purpose

of this review was to assure that the aging management activities were consistent with the

staff's guidance described in SRP-LR, Section A.2, “Quality Assurance for AMPs (Branch

Technical Position IQMB-1)," regarding QA attributes of AMPs. Based on the staff's evaluation,

the descriptions and applicability of the plant-specific AMPs and their quality attributes provided

in LRA Appendix B.1.3 are consistent with the staff's position regarding QA for aging

management. In particular, the applicant noted that its QA Program provides elements of

corrective action, confirmation processes, and administrative controls for both SR and NSR

SSCs. However, the applicant did not describe the use of the QA Program and its associated

attributes in LRA Appendix A, "UFSAR" Appendix A. Specifically, consistent with Branch

Technical Position IQMB-1, the applicant should either document a commitment to expand the

scope of its 10 CFR Part 50 Appendix B program to include NSR SCs subject to an AMP to

address the AMP quality attributes during the period of extended operation, or propose an

alternate means to address this issue. In RAI 2.1-3. dated July 30, 2004, the staff requested the

applicant to clarify its position with regard to the quality attributes of AMPs in LRA Appendix A.

By letter dated September 3, 2004, the applicant responded as follows:

The following statement supplements LRA Appendix A.1, "Aging Management Programs:"

The integrated plant assessment for license renewal identified new programs,

enhancements to existing programs, and existing programs necessary to continue

operation of BFN Units 1, 2, and 3 during the additional twenty years beyond the initial

license term. This chapter describes those programs. The TVA Nuclear Quality

Assurance Program implements the requirements of 10 CFR 50, Appendix B. The TVA

Nuclear Quality Assurance Program includes elements of corrective action, confirmation

process, and administrative controls. These elements are applicable to all aging

management programs credited for license renewal. The Corrective Action Program

ensures corrective actions, including root cause determinations and prevention of

recurrence are timely. The Corrective Action Program also includes the confirmation

process that ensures preventive actions are adequate and that appropriate corrective

actions have been complete and are effective. Administrative controls provide for a

formal review and approval process of program implementing documents.

The staff reviewed the statement and requested that the applicant revise the statement made in

its September 24, 2004, response to explicitly state that the applicant's 10 CFR Part 50,
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Appendix B, Quality Assurance Program will apply to both SR and NSR SSCs within the scope

of license renewal and subject to one or more of the AMPs. 

By letter dated October 18, 2004, the applicant provided a supplemental response, which

stated, in part, that the elements (corrective action, confirmation process, and administrative

controls) are applicable to all AMPs, SSCs, systems, and components. The staff reviewed the

revised response and finds that it adequately addresses the staff's concerns regarding

application of the AMPs to both SR and NSR SSCs within the scope of license renewal and

subject to one or more of the AMPs, and is, therefore, acceptable. The staff considered the

information provided by the applicant acceptable and the staff’s concern described in RAI 2.1-3

is resolved.

3.0.4.3 Conclusion

The staff found that the QA attributes of the applicant’s AMPs are consistent with

10 CFR 54.21(a)(3). Specifically, the applicant described the quality attributes of the programs

and activities for managing the effects of aging for both SR and NSR SSCs within the scope of

license renewal and stated that 10 CFR Part 50 Appendix B provides corrective actions,

confirmation processes, and administrative controls. Therefore, the applicant’s QA description

for its AMPs is acceptable. 
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3.1 Aging Management Review of Reactor Vessel, Internals, and Reactor Coolant

System

This section of the SER documents the staff’s review of the applicant’s AMR results for the

reactor vessel, internals, and reactor coolant system components and component groups

associated with the following systems:

 • reactor vessel

 • reactor vessel internals

 • reactor vessel vents and drains

 • reactor recirculation

3.1.1 Summary of Technical Information in the Application

In LRA Section 3.1, the applicant provided AMR results for components. In LRA Table 3.1.1,

“Summary of Aging Management Review Evaluations for Reactor Coolant System Evaluated in

Chapter IV of NUREG-1801,” the applicant provided a summary comparison of its AMRs with

the AMRs evaluated in the GALL Report for the reactor vessel, internals, and reactor coolant

system components and component groups.

The applicant’s AMRs incorporated applicable operating experience in the determination of

AERMs. These reviews included evaluation of plant-specific and industry operating experience.

The plant-specific evaluation included reviews of condition reports and discussions with

appropriate site personnel to identify AERMs. The applicant’s review of industry operating

experience included a review of the GALL Report and operating experience issues identified

since the issuance of the GALL Report.

3.1.2 Staff Evaluation

The staff reviewed LRA Section 3.1 to determine if the applicant had provided sufficient

information to demonstrate that the effects of aging for the reactor vessel, internals, and reactor

coolant system components that are within the scope of license renewal and subject to an AMR

will be adequately managed so that the intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).

The staff performed an onsite audit of AMRs during the weeks of June 21 and July 26, 2004, to

confirm the applicant’s claim that certain identified AMRs were consistent with the GALL

Report. The staff did not repeat its review of the matters described in the GALL Report;

however, the staff did verify that the material presented in the LRA was applicable and that the

applicant had identified the appropriate GALL AMRs. The staff’s evaluations of the AMPs are

documented in SER Section 3.0.3. Detail of the staff’s audit evaluation are documented in the

BFN audit and review report and are summarized in SER Section 3.1.2.1.

In the onsite audit, the staff also selected AMRs that were consistent with the GALL Report and

for which further evaluation is recommended. The staff confirmed that the applicant’s further

evaluations were consistent with the acceptance criteria in SRP-LR Section 3.1.2.2. The staff’s

audit evaluations are documented in the BFN audit and review report and are summarized in

SER Section 3.1.2.2.
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In the onsite audit, the staff also conducted a technical review of the remaining AMRs that were

not consistent with, or not addressed in, the GALL Report. The audit and technical review

included evaluating whether all plausible aging effects were identified and evaluating whether

the aging effects listed were appropriate for the combination of materials and environments

specified. The staff’s audit evaluations are documented in the BFN audit and review report and

are 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 UFSAR 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.

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

Components in the GALL Report

Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

Reactor coolant

pressure boundary

components

(Item Number

3.1.1.1)

Cumulative fatigue

damage

TLAA, evaluated in

accordance with

10 CFR 54.21(c)

TLAA This TLAA is

evaluated in

Section 4.3, Metal

Fatigue

Isolation condenser

(Item Number

3.1.1.3)

Loss of material

due to general,

pitting, and crevice

corrosion

Inservice Inspection

Program; Water

Chemistry Program

N/A Not applicable

BFN does not have

isolation condenser

The isolation

condenser function

is performed by the

RCIC system

Pressure vessel

ferritic materials

that have a neutron

fluence greater than

1017 n/cm2

(E > 1 MeV)

(Item Number

3.1.1.4)

Loss of fracture

toughness due to

neutron irradiation

embrittlement

TLAA, evaluated in

accordance with

Appendix G of

10 CFR 50 and

RG 1.99

Reactor Vessel

Surveillance

Program

TLAA

Consistent with

GALL which

recommends further

evaluation 

(See Section

3.1.2.2.3)

This TLAA is

evaluated in

Section 4.2,

Neutron

Embrittlement of

Reactor Vessel and

Internals
Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

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Reactor vessel

beltline shell and

welds 

(Item Number

3.1.1.5)

Loss of fracture

toughness due to

neutron irradiation

embrittlement

Reactor Vessel

Surveillance

Program

Reactor Vessel

Surveillance

Program

Consistent with

GALL which

recommends further

evaluation 

(See Section

3.1.2.2.3)

Small-bore reactor

coolant system and

connected systems

piping

(Item Number

3.1.1.7)

Crack initiation and

growth due to stress

corrosion cracking

(SCC), intergranular

stress corrosion

cracking (IGSCC),

and thermal and

mechanical loading

Inservice Inspection

Program; Water

Chemistry Program;

One-Time

inspection Program

Inservice Inspection

Program; Chemistry

Control Program;

One-Time

inspection Program

Consistent with

GALL which

recommends further

evaluation 

(See Section

3.1.2.2.4)

Jet pump sensing

line and reactor

vessel flange leak

detection line

(Item Number

3.1.1.8)

Crack initiation and

growth due to SCC,

IGSCC, or cyclic

loading

Plant-specific Stress Corrosion

Cracking Program;

Inservice Inspection

Program; Chemistry

Control Program;

One-Time

Inspection Program

See Section

3.1.2.3.6

Isolation condenser

(Item Number

3.1.1.9)

Crack initiation and

growth due to SCC

or cyclic loading

Inservice Inspection

Program; Water

Chemistry Program

N/A Not applicable

BFN does not have

isolation condenser

The isolation

condenser function

is performed by the

RCIC system (See

Section 3.1.2.2.4)

Reactor vessel

closure studs and

stud assembly

(Item Number

3.1.1.22)

Crack initiation and

growth due to SCC

an/or IGSCC

Reactor Head

Closure Studs

Program

Reactor Head

Closure Studs

Program

Consistent with

GALL which

recommends no

further evaluation 

(See Section

3.1.2.1.12)

CASS pump casing

and valve body

(Item Number

3.1.1.23)

Loss of fracture

toughness due to

thermal aging

embrittlement

Inservice Inspection

Program

Inservice Inspection

Program

Consistent with

GALL which

recommends no

further evaluation 

(See Section

3.1.2.3.17)

CASS piping

(Item Number

3.1.1.24)

Loss of fracture

toughness due to

thermal aging

embrittlement

Thermal Aging

Embrittlement of

CASS Program

N/A Not applicable

No RCPB CASS

piping and fittings

are used in BFN 

(See Section

3.1.2.3.17)
Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

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BWR piping and

fittings; steam

generator

components

(Item Number

3.1.1.25)

Wall thinning due to

flow accelerated

corrosion

Flow Accelerated

Corrosion Program

Flow Accelerated

Corrosion Program

Consistent with

GALL which

recommends no

further evaluation 

(See Section

3.1.2.2.12)

Reactor coolant

pressure boundary

(RCPB) valve

closure bolting,

manway and

holding bolting,

closure bolting in

high-pressure and

high-temperature

systems

(Item Number

3.1.1.26)

Loss of material

due to wear; loss of

preload due to

stress relaxation;

and crack initiation

and growth due to

cyclic loading

and/or SCC

Bolting Integrity

Program

Bolting Integrity

Program

Consistent with

GALL which

recommends further

evaluation 

(See Section

3.1.2.3.4)

Feedwater and

control rod drive

(CRD) return line

nozzles

(Item Number

3.1.1.27)

Crack initiation and

growth due to cyclic

loading

Feedwater Nozzle

Program; CRD

Return Line Nozzle

Program

Feedwater Nozzle

Program; CRD

Return Line Nozzle

Program

Consistent with

GALL which

recommends no

further evaluation 

(See Sections

3.1.2.2.4, 3.1.2.3.9)

Vessel shell

attachment welds

(Item Number

3.1.1.28)

Crack initiation and

growth due to SCC

and/or IGSCC

BWR Vessel ID

Attachment Welds

Program; Water

Chemistry Program

BWR Vessel ID

Attachment Welds

Program; Chemistry

Control Program

Consistent with

GALL with

exceptions 

(See Section

3.1.2.3.7)

Nozzle safe ends,

recirculation pump

casing, connected

systems piping and

fittings, body and

bonnet of valves

(Item Number

3.1.1.29)

Crack initiation and

growth due to SCC

and/or IGSCC

BWR Stress

Corrosion Cracking

Program; Water

Chemistry Program

BWR Stress

Corrosion Cracking

Program; Chemistry

Control Program

Consistent with

GALL which

recommends further

evaluation 

(See Section

3.1.2.3.8)

Penetrations

(Item Number

3.1.1.30)

Crack initiation and

growth due to SCC,

IGSCC, and/or

cyclic loading

BWR Bottom Head

Penetrations

Program; Water

Chemistry Program

BWR Bottom Head

Penetrations

Program; Chemistry

Control Program

Consistent with

GALL which

recommends further

evaluation 

(See Section

3.1.2.3.11)
Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

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Core shroud and

core plate, support

structure, top guide,

core spray lines and

spargers, jet pump

assemblies, control

rod drive housing,

nuclear instrument

guide tubes

(Item Number

3.1.1.31)

Crack initiation and

growth due to SCC,

IGSCC, and/or

irradiation assisted

stress corrosion

cracking ( IASCC)

BWR Vessel

Internals Program;

Water Chemistry

Program

BWR Vessel

Internals Program;

Chemistry Control

Program

Consistent with

GALL which

recommends further

evaluation 

(See Section

3.1.2.3.16)

Core shroud and

core plate access

hole cover (welded

and mechanical

covres)

(Item Number

3.1.1.32)

Crack initiation and

growth due to SCC,

IGSCC, and/or

IASCC

ASME Section XI

Inservice Inspection

Program; Water

Chemistry Program

ASME Section XI

Inservice Inspection

Program; Chemistry

Control Program

Consistent with

GALL which

recommends further

evaluation 

(See Section

3.1.2.3.2)

Jet pump assembly

castings and

orificed fuel support

(Item Number

3.1.1.33)

Loss of fracture

toughness due to

thermal aging and

neutron irradiation

embrittlement

Thermal Aging and

Neutron Irradiation

Embrittlement

N/A Not required for

BFN 

(See Section

3.1.2.3.17)

Unclad top head

and nozzles

(Item Number

3.1.1.34)

Loss of material

due to general,

pitting, and crevice

corrosion

Inservice Inspection

Program; Water

Chemistry Program

Inservice Inspection

Program; Chemistry

Control Program

Consistent with

GALL which

recommends further

evaluation 

(See Section

3.1.2.3.18)

The staff’s review of the BFN component groups 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 reactor coolant system 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 reactor coolant 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 3.1.2.3, involves the staff’s

review of the AMR results for components in the reactor vessel, internals, and reactor coolant

system that the applicant indicated are not consistent with, or not addressed in, the GALL

Report. The staff’s review of AMPs that are credited to manage or monitor aging effects of the

reactor vessel, internals, and reactor coolant system 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 Application. In LRA Section 3.1.2.1, the applicant

identified the materials, environments, and AERMs. The applicant identified the following
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programs that manage the aging effects related to the reactor vessel, internals, and reactor

coolant system components:

 • ASME Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program

 • BWR Control Rod Drive Return Line Nozzle Program

 • BWR Feedwater Nozzle Program

 • BWR Penetrations Program

 • BWR Vessel ID Attachment Welds Program

 • BWR Stress Corrosion Cracking Program

 • Chemistry Control Program

 • One-time Inspection Program

 • Reactor Head Closure Studs Program

 • Reactor Vessel Surveillance Program

 • BWR Vessel Internals Program

 • Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel

(CASS) Program

 • Bolting Integrity Program

 • Flow-Accelerated Corrosion Program

 • Systems Monitoring Program

 • Open-Cycle Cooling Water System Program

 • Selective Leaching of Materials Program

Staff Evaluation. In LRA Tables 3.1.2-1 through 3.1.2-4, the applicant provided a summary of

AMRs for the reactor vessel, internals, and reactor coolant system components, and identified

which AMRs it considered to be consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed

consistency with the GALL Report, and for which the GALL Report does not recommend further

evaluation, the staff performed an audit and review to determine whether the plant-specific

components contained in these GALL Report component groups 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 audited those AMRs with

Notes A through E, which 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.
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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 is different from, but consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent

with the AMP identified by the GALL Report. This note indicates that the applicant 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 is different from, but consistent with,

the GALL Report for material, environment, and aging effect. In addition, the AMP takes some

exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify

consistency with the GALL Report. The staff 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 BFN 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.

For aging management evaluations that the applicant stated are consistent with the GALL

Report and for which further evaluation is not recommended, the staff conducted its audit of the

LRA to determine if the applicant’s reference to the GALL Report is acceptable. 

The staff reviewed the LRA to confirm that the applicant: (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 reactor vessel, internals, and RCS system components that are subject to an AMR.
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A review of the Table 2s identified the following issues:

The staff identified that LRA Table 3.1.2.2 presents the AMR for the reactor vessel internals

core shroud and core plate (row 1). The corresponding GALL Report Item IV.B1.1-d indicates

that the access hole cover (AHC) welds would require an augmented inspection (UT or other

demonstrated acceptable inspection) to manage crack initiation due to SCC in the crevice

regions of the access hole covers which are not amenable to visual inspections. This issue has

been addressed in GE Service Information Letter (SIL) 462 (1988) after circumferential SCC

was found in a creviced AHC fabricated from nickel alloy 600. BFN Technical Justification

Number TJ-2004-02, dated 3-02-2004, provides justification for variance from GE SIL 462,

revision 1, that provides guidance on inspection of core shroud AHCs. BFN has implemented

the GE SIL requirements for Units 2 and 3, and they will be applicable to all three units upon

re-start of Unit 1. Details of AHC replacements are provided in RAI 3.1.2-6(A) response, by

letter dated January 31, 2005 and May 25, 2005, respectively. The staff found this acceptable.

The staff identified that LRA Table 3.1.2.2, is not consistent with the GALL Report,

Item IVB1.4-d, and asked the applicant for an explanation. By letter dated October 8, 2004, the

applicant submitted its formal response to the staff, stating that the GALL Report item should

have been IVB1.6-a instead of IVB1.4-d and the table will be corrected. The staff found this

acceptable because it is consistent with the GALL Report.

LRA Table 3.1.2.3, row 51, presents the AMR for the stainless steel valves in treated water

internal environment for the reactor vessel vents and drains systems. The staff identified a

difference in crediting AMPs for this commodity group. The table includes the Chemistry Control

Program, BWR Stress Corrosion Cracking Program, and One-Time Inspection Program to

manage crack initiation and growth due to SCC, and cross-references LRA Table 3.1.1,

Item 3.1.1.29. However, LRA Table 3.1.1, Item 3.1.1.29, does not specify the One-Time

Inspection Program. During the onsite audit, the staff asked the applicant to explain this

difference. By letter dated October 8, 2004, the applicant submitted its formal response to the

staff, stating that the One-Time Inspection Program will be removed from LRA Table 3.1.2.3,

row 51. The staff found this acceptable because it is consistent with the GALL Report.

LRA Table 3.1.2.4, row 48, presents the AMR for the stainless steel fittings, including flow

restrictors, in treated water internal environment for the reactor recirculation system. The staff

identified a difference in crediting AMPs for this commodity group. The table does not identify

the Chemistry Control Program to manage crack initiation and growth due to SCC. However,

the referenced GALL Report Item IV.C1.1-I identified the Chemistry Control Program. During

the onsite audit, the staff asked the applicant to explain this difference. By letter dated

October 8, 2004, the applicant submitted its formal response to the staff, stating that the

Chemistry Control Program will be added to LRA Table 3.1.2.4, row 48. The staff found this

acceptable because it is consistent with the GALL Report.

On the basis of its audit, 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
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staff concluded that the AMR results, which the applicant claimed to be consistent with the

GALL Report, are consistent with the AMRs in the GALL Report. Therefore, the staff concluded

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

For some line items in LRA Tables 3.1.2.1 through 3.1.2.4 that are identified to be consistent

with the GALL Report, the applicant cross-referenced specific line items in LRA Tables 3.1.1

through 3.4.1, for which the GALL Report recommends further evaluation. Where the GALL

Report recommends further evaluation, the staff reviewed the applicable further evaluations

provided in LRA Sections 3.1.2.2, 3.2.2.2, 3.3.2.2, and 3.4.2.2 against the criteria provided in

SRP-LR Sections 3.1.2.2, 3.2.2.2, 3.3.2.2, and 3.4.2.2, respectively. The following provides the

staff’s assessment of the applicant’s further evaluations applicable to the reactor vessel,

internals, and reactor coolant system.

Summary of Technical Information in the Application. In LRA Section 3.1.2.2, the applicant

provided further evaluation of aging management as recommended by the GALL Report for the

reactor vessel, internals, and reactor coolant system components. The applicant provided

information concerning how it will manage the following aging effects:

 • cumulative fatigue damage (3.1.2.2.1)

 • loss of material due to general corrosion (3.1.2.2.2)

 • loss of fracture toughness due to neutron irradiation embrittlement (3.1.2.2.3)

 • crack initiation and growth due to thermal and mechanical loading or stress corrosion

cracking (3.1.2.2.4)

 • crack growth due to cyclic loading (3.1.2.2.5, PWR only)

 • changes in dimension due to void swelling (3.1.2.2.6/PWR only)

 • crack initiation and growth due to stress corrosion cracking or primary water stress

corrosion cracking (PWSCC)(3.1.2.2.7/PWR only)

 • crack initiation and growth due to stress corrosion cracking or irradiation assisted stress

corrosion cracking(3.1.2.2.8/ PWR only)(3.1.2.2.8/PWR only)

 • loss of preload due to stress relaxation(3.1.2.2.9/PWR only)

 • loss of section thickness due to erosion (3.1.2.2.10/PWR only)

 • crack initiation and growth due to PWSCC, outside-diameter stress corrosion cracking,

or intergranular attack or loss of material due to wastage and pitting corrosion or loss of

section thickness due to fretting and wear or denting due to corrosion of carbon steel

tube support plate (3.1.2.2.11/PWR)

 • loss of section thickness due to flow-accelerated corrosion (3.1.2.2.12/PWR)
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 • ligament cracking due to corrosion (3.1.2.2.13/PWR)

 • loss of material due to flow accelerated corrosion (3.1.2.2.14/PWR)

 • quality assurance for aging management of non-safety-related components

Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant

has claimed consistency with the GALL Report, and for which the GALL Report recommends

further evaluation, the staff audited and reviewed the applicant’s evaluation to determine

whether it adequately addressed the issues that were further evaluated. In addition, the staff

reviewed the applicant’s further evaluations against the criteria contained in Section 3.1.2.2 of

the SRP-LR. Details of the staff’s audit are documented in the staff’s BFN audit and review

report. The staff’s evaluation of the aging effects is discussed in the following sections.

3.1.2.2.1 Cumulative Fatigue Damage

For LRA Table 3.1.1, item 3.1.1.1, the applicant references LRA Section 3.1.2.2.1. This is a

TLAA, and is evaluated in SER Section 4.

3.1.2.2.2 Loss of Material due to General Corrosion

The staff reviewed LRA Section 3.1.2.2.2 against the criteria in SRP-LR Section 3.1.2.2.2.

The SRP-LR identifies that the only BWR component covered by this further evaluation is the

isolation condenser. This is not applicable because BFN does not have an isolation condenser.

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.

Consistent with the SRP-LR, the applicant references LRA Section 4.2. This is a TLAA, and is

evaluated in SER Section 4.

Also consistent with the SRP-LR, the applicant references the Reactor Vessel Surveillance

Program, described in LRA Section B.2.1.28. This AMP is reviewed and evaluated in SER

Section 3.0.3.2.19. 

The AMP recommended by the GALL Report for managing loss of fracture toughness due to

neutron irradiation embrittlement of the RV is GALL AMP XI.M31, "RV Surveillance," which

complies with the requirements of 10 CFR Part 50, Appendices G and H. Loss of fracture

toughness due to neutron irradiation embrittlement could occur in the RV. An RV materials

surveillance program monitors neutron irradiation embrittlement of the RV. RV surveillance

programs may be plant-specific, depending on matters such as the composition of limiting

materials, availability of surveillance capsules, and projected fluence levels or may be an ISP

based on the criteria in 10 CFR Part 50, Appendix H. In accordance with

10 CFR Part 50, Appendix H, an applicant is required to submit its proposed withdrawal

schedule for approval prior to implementation. 
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LRA Section 3.1.2.2.3 addresses (1) loss of fracture toughness due to neutron irradiation

embrittlement for ferritic materials that have a neutron fluence of greater than 1017 n/cm2 at the

end of the license renewal term, and (2) loss of fracture toughness due to irradiation

embrittlement of the RV beltline material. Loss of fracture toughness due to neutron irradiation

embrittlement for ferritic materials that have a neutron fluence of greater than 1017 n/cm2 at the

end of the license renewal term is a TLAA, and the staff's review of the applicant's evaluation of

this TLAA is documented in LRA Section 4.2. In performing this review, the staff followed the

guidance in SRP-LR Section 4.2. 

The RV Surveillance Program is mandated by 10 CFR Part 50, Appendix H. The RV

Surveillance Program is an ISP in accordance with 10 CFR Part 50, Appendix H Paragraph III.C

that is based on requirements established by the BWRVIP. Referencing of BWRVIP activities

for license renewal was approved by the staff in its SER regarding BWRVIP-74 of October 18,

2001. The demonstration of compliance with the required actions of the SE is summarized in

LRA Section 3.1.2.2.16. The applicant stated that the RV Surveillance Program, as supported

by associated TLAA evaluations (LRA Section 4.2), will manage loss of fracture toughness of

RV beltline components due to irradiation embrittlement by addressing the limiting RV beltline

shells and welds.

The applicant also stated that the RV Surveillance Program is described in UFSAR

Section 4.2.6 and is based on BWRVIP-78, "BWR Vessel Integrated Surveillance Program

Plan," and BWRVIP-86, BWR Vessel and Internal Project Updated BWR Integrated

Surveillance Program (ISP) Implementation Plan." Use of the BWRVIP-78 and BWRVIP-86 to

address a 40-year license period was approved for referencing in the staff's SER dated

February 1, 2000. Use of the BWRVIP ISP for Units 2 and 3 was approved by the staff in its

SER dated January 28, 2003. The technical criteria specified in the BWRVIP-78 and

BWRVIP-86 were incorporated in the BWRVIP-116, "BWR Vessel and Internals

Project-Integrated Surveillance Program (ISP)-Implementation for License Renewal."

BWRVIP-116 extends the ISP to cover the BWR fleet through an extended period of operation

for all units. The applicant committed to implement the requirements of BWRVIP-116, when

approved, for all three RVs. Therefore, the applicant did not submit a plant-specific program in

its LRA. The details of the staff's review of this aging effect are included in SER Section 3.0.3.2. 

The applicant stated that it will implement the BWRVIP ISP for the period of extended

operation, if approved by the staff for the BWR fleet, as applicable to each RV and will request

the approval from the staff, if necessary, to use the program at applicable RVs for the period of

extended operation. This enhancement is scheduled for completion prior to the period of

extended operation.

The staff found that by implementing the ISP program as dictated by the RV Surveillance

Program, the applicant demonstrated that it complies with all the recommendations specified in

GALL AMP XI.M31. Therefore, the staff accepted the implementation of the RV Surveillance

Program for managing the aging effect due to loss of fracture toughness due to neutron

irradiation embrittlement of the RVs.

Conclusion. On the basis of its review, the staff found that the applicant appropriately evaluated

AMR results involving management of loss of fracture toughness due to neutron irradiation

embrittlement 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
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that the effects of aging will be adequately managed so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3).

3.1.2.2.4 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.

LRA Table 3.1.2.3 and Table 3.1.2.4 present the AMRs for small bore piping and fittings

(including flow restrictors) less than NPS 4 in treated-water environment for the RCS. These

AMRs reference LRA Table 1 Item 3.1.1.7, which references LRA Section 3.1.2.2.4 for the

further evaluation.

In the LRA Section 3.1.2.2.4, the applicant addressed the potential for crack initiation and

growth due to thermal and mechanical loading or SCC (including IGSCC) that could occur in

small-bore RCS and connected system piping less than NPS 4. 

SRP-LR Section 3.1.2.2.4 applicable to BFN (BWRs) states the following:

 1. Crack initiation and growth due to thermal and mechanical loading or SCC (including

IGSCC) could occur in small-bore reactor coolant system and connected system piping

less than NPS 4. The existing program relies on ASME Section XI ISI and on control of

water chemistry to mitigate SCC. 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 extended

period. The AMPs should be augmented by verifying that service-induced weld cracking

is not occurring in the small-bore piping less than NPS 4, including pipe, fittings, and

branch connections. A one-time inspection of a sample of locations is an acceptable

method to ensure that the aging effect is not occurring and the component’s intended

function will be maintained during the period of extended operation. 

 2. Crack initiation and growth due to thermal and mechanical loading or SCC (including

IGSCC) could occur in BWR reactor vessel flange leak detection line and BWR jet pump

sensing line. The GALL Report recommends that a plant-specific AMP be evaluated to

mitigate or detect crack initiation and growth due to SCC of vessel flange leak detection

line. Acceptance criteria are described in Branch Technical Position RLSB-1

(Appendix A.1 of this standard review plan).

The applicant should verify that service-induced weld cracking is not occurring in small-bore

piping less than NPS 4. A one-time inspection of a sample of locations is an acceptable method

to ensure that the aging effect is not occurring and 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 NPS 4), does

not receive volumetric inspection. 

The BFN-proposed One-Time Inspection Program includes volumetric examination of a sample

of susceptible locations in small bore piping and pipe fittings. During the onsite audit, which took
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place the weeks of June 21 and July 26, 2004, the staff asked the applicant to explain the

selection criteria for these sample locations. In its response, the applicant stated:

The one-time inspections utilized to verify the effectiveness of the Chemistry Control

Program for preventing loss of material will select the susceptible locations based on

plant operating experience, with an emphasis on locations that potentially have low or

stagnant flow conditions.

The staff expanded the question in a subsequent teleconference with the applicant. In

response, the applicant stated:

The BFN One-Time Inspection Program includes a sample inspection of Reactor

Coolant Pressure (RCPB) Boundary piping less than four inch NPS exposed to reactor

coolant for cracking.

The Browns Ferry One-Time Inspection Program provides the following description of

how cracking will be detected.

The inspection includes a representative sample of the system population, and,

where practical, focuses on the bounding or lead components most susceptible

to aging due to time in service, severity of operating conditions, and lowest

design margin. For small-bore piping, actual inspection locations are based on

physical accessibility, exposure levels, NDE techniques, and locations identified

in Nuclear Regulatory Commission (NRC) Information Notice (IN) 97-46.

Combinations of NDE, including visual, ultrasonic, and surface techniques, are

performed by qualified personnel following procedures consistent with the ASME

Code and 10 CFR 50, Appendix B. For small-bore piping less than NPS 4 in.,

including pipe, fittings, and branch connections, a plant-specific destructive

examination of replaced piping due to plant modifications or NDE that permits

inspection of the inside surfaces of the piping is to be conducted to ensure that

cracking has not occurred. Follow-up of unacceptable inspection findings

includes expansion of the inspection sample size and locations.

The inspection and test techniques prescribed by the program verify any aging

effects because these techniques, used by qualified personnel, have been

proven effective and consistent with staff expectations. With respect to

inspection timing, the one-time inspection is to be completed before the end of

the current operating license. The applicant may schedule the inspection in such

a way as to minimize the impact on plant operations. However, the inspection is

not to be scheduled too early in the current operating term, which could raise

questions regarding continued absence of aging effects prior to and near the

extended period of operation.

In its letter, dated October 8, 2004, in response to the staff’s question, the applicant stated: 

... Aging Management Program XI.M32, One-Time Inspection, Evaluation and Technical

Basis Section, Detection of Aging Effects, states:
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Combinations of NDE, including visual, ultrasonic, and surface techniques, are

performed by qualified personnel following procedures consistent with the ASME

Code and 10 CFR 50, Appendix B. For small-bore piping less than NPS 4 in.,

including pipe, fittings, and branch connections, a plant-specific destructive

examination of replaced piping due to plant modifications or NDE that permits

inspection of the inside surfaces of the piping is to be conducted to ensure that

cracking has not occurred. 

As noted from this paragraph, either destructive examination or NDE that is capable of

detecting inside surface cracking is required. Since there are UT-inspectable, full

penetration butt welds within scope of license renewal, BFN has chosen the second

method for our program and no destructive examination of socket welds will be

performed. Once this inspection methodology was selected, the possible sample

population is full penetration butt welds. BFN has no identified butt welds in ASME

Class 1 piping 1-inch NPS and less. Therefore, 1-inch NPS and less piping will not be

selected for small-bore piping NDE E-67 examination. This sample population provides

adequate indication of whether inside diameter cracking is occurring in small-bore

piping.

The staff disagreed with the applicant’s response in that socket-welded piping, 1-inch NPS and

less, is adequately represented by the applicant’s sample selection criteria for small bore piping

included in the scope of the One-Time Inspection Program. The staff disputed that, historically,

piping 1-inch NPS and less, is more susceptible to failure. The geometry of and joining methods

for socket welds make them more susceptible to cracking than full penetration butt welds. But,

the staff would be willing to accept NDE of full penetration butt welds in piping greater than

1-inch NPS as being representative of socket-welded piping, 1-inch NPS and less. 

In RAI 3.1.2.4-7, dated March 11, 2005, the staff questioned why the applicant was not

complying with the GALL Report recommendation 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 extended period.

In its response, dated April 5, 2005, the applicant stated that:

The One-Time Inspection Program will evaluate a sample of welds in small-bore piping

less than 4 inches NPS for internal surface cracking by NDE as specified by

NUREG-1800, Aging Management Program XI.M32, "One-Time Inspection.” The BFN

One-Time Inspection Program sample will be selected from full penetration butt welds

where ultrasonic testing can be performed. The basis for this sample population is:

 • this sample will evaluate the welds with the most susceptibility to the aging

effects of stress corrosion cracking and thermal fatigue;

 • this sample will evaluate the welds with the most significant consequences and

risks; and

 • this sample will allow the welds to be identified, scheduled, and performed in a

systematic manner.
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Socket weld cracking generally occurs due to weld defect propagation by vibrational

fatigue. Stress corrosion cracking and thermal fatigue rarely cause socket weld failures.

Vibration induced socket weld failures is a design issue that has been observed in the

nuclear power industry and can result in crack initiation and growth. Vibration induced

fatigue is fast acting and is typically detected early in a component’s life. Corrective

measures typically include actions to preclude recurrence of the failure mechanism.

Corrective actions to preclude recurrence may involve modifications to the plant, such

as addition of supplemental restraints to a piping system, shortening the vent piping,

replacement of tubing with flexible hose, etc. Based upon these measures, cracking due

to vibration-induced fatigue is not considered an aging effect for the period of extended

operation.

Previously, plants have excluded piping based strictly on consequences of the potential

pipe failure. Although this was not done in the BFN Risk Informed ISI Program, a plant

specific calculation demonstrates that BFN can tolerate 2-inch NPS and smaller breaks

with normal makeup. At BFN, all Class 1 piping was included in the BFN Risk Informed

ISI Program. No welds less than 4 inches NPS were identified as high risk. The BFN

One-Time Inspection Program sample will select full penetration butt welds where

ultrasonic testing can be performed. The butt welds are more susceptible to stress

corrosion cracking and thermal fatigue, which are the primary crack initiation and growth

aging mechanisms. This sample also allows a selection of the most risk-significant

small-bore piping locations (i.e., locations with the highest susceptibility to cracking and

highest consequences of failure) to be identified, scheduled, and performed in a

systematic manner, rather than attempting to track modifications for 20 years while

awaiting the possible removal of a piece of small-bore piping containing a weld for

destructive testing. 

The staff evaluated the applicant's response and concurred with the evaluation. Therefore, the

staff’s concern described in RAI 3.1.2.4-7 is resolved.

The staff also asked the applicant where GALL Report Volume 1, Table 1, Item 3.1.1.8, jet

pump sensing line and reactor vessel flange detection line, as stated in LRA Section 3.1.2.2.4,

are addressed in the AMR. By letter dated October 8, 2004, the applicant submitted its formal

response to the staff. The applicant stated:

GALL Volume 1, Table 1, Item 3.1.1.8 states that the corresponding GALL Volume 2

line items are IV.A1.1-d and IV.B1.4-d.

GALL Volume 2, Line IV.A1.1-d: 

The Browns Ferry top head enclosure - vessel flange leak detection line is not

consistent with GALL Volume 2, Line IV.A1.1-d. The Browns Ferry components included

in this line item are carbon and low-alloy steel, whereas GALL Volume 2, Line IV.A1.1-d

refers to stainless steel. The components included in this line item are the penetration

through the carbon steel vessel flange and a short segment of carbon steel piping and

fittings external to the reactor vessel. Therefore this line was not shown as

corresponding to GALL Volume 1, Table 1, Item 3.1.1.8. 

Currently, One-Time Inspection is listed as the aging management program for this line

item. The Browns Ferry reactor vessel flange leak detection line is ASME Class 2
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Equivalent and should have included the ASME Section XI Subsections IWB, IWC and

IWD Inservice Inspection Program as an aging management program. ASME Section XI

Subsections IWB, IWC and IWD Inservice Inspection Program will be added to this line

item.

The remaining portion of the vessel flange leak detection line is stainless steel. This

stainless steel piping is in the Feedwater System (003) at Browns Ferry. Aging of this

piping is addressed in Table 3.4.2.3 and corresponds to GALL, Volume 2, Item C1.1-i,

piping and fittings - small bore piping less than NPS 4.

GALL Volume 2, Line IV.B1.4-d: 

The Browns Ferry jet pump assemblies - jet pump sensing line is not consistent with

GALL Volume 2, Line IV.B1.4-d. Section IV.B1 addresses BWR reactor vessel internals.

The jet pump sensing lines internal to the reactor vessel have been determined to not

be within the scope of license renewal for Browns Ferry. Therefore this line was not

shown as corresponding to GALL Volume 1, Table 1, Item 3.1.1.8. 

The jet pump instrumentation penetration is stainless steel clad carbon steel and is

included with GALL Volume 2, Line IV.A1.5-a, Penetrations. External to the reactor

vessel, the stainless steel jet pump sensing lines are included in GALL, Volume 2, Item

C1.1-i, piping and fittings - small bore piping less than NPS 4.

In a follow-up response to the staff’s question, the applicant provided the following ARM

table information:

Jet Pump

 • Internal to RV – not in scope

 • Penetration – Table 3.1.2.1, Items 63, 64, and 65

 • External to RV – Table 3.4.2.3, Items 40 and 41

RV flange leak detection line

 • Penetration – Table 3.1.2.1, Item 9

 • External to RV – Table 3.1.2.4, Items 88, 89, and 90

The staff found the response acceptable on the basis that the applicant had adequately

described its AMR for the jet pump and RV flange leak detection line, and also identified an

appropriate correction to the AMR for the RV flange leak detection line.

During the onsite audit, the staff asked the applicant a question related to proposed AMPs for

cracking of small bore piping due to cyclic loading. GALL Report Volume 1, Table 1, Item

3.1.1.7 identifies the Chemistry Control, the One-Time Inspection, and the ASME ISI Programs

for managing this aging effect. However, the applicant has not included the Chemistry Control

Program as one of the proposed AMPs. By letter dated October 8, 2004, the applicant

submitted its formal response to the staff, stating:

GALL Volume 1, Table 1 specifies that consistency with GALL Volume 2, Line IV.C1.1-i

establishes consistency with GALL Volume 1, Table 1, Item 3.1.1.7. Previous to the

Browns Ferry LRA, all license renewal applications have been written at the aging effect

level and did not address aging mechanisms. The primary difficulty in determining GALL

line item consistency is that the aging management programs should be consistent with
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the aging effects listed, not necessarily with the individual aging mechanisms listed.

Therefore when reviewing the aging mechanism “crack initiation/growth due to cyclic

loading” instead of the aging effect “crack initiation/growth,” some interpretation of the

GALL line item was required. 

GALL Report Item IV.C1.1-i addresses specific concerns with small bore piping and

fittings less than NPS 4. The GALL line item provides a comprehensive listing of

potential aging mechanisms and aging management programs for the crack initiation

and growth aging effect. To address that all materials and aging management

programs are not applicable to each aging mechanism, this GALL line item was

interpreted follows for the various materials and aging mechanisms.

Stainless steel/Treated water (Note 1)

Aging Effect

 • Crack initiation and growth/ Stress corrosion cracking, inter-granular stress

corrosion cracking

Aging Management Programs

 • ASME Section XI Subsections IWB, IWC and IWD Inservice Inspection Program

(B.2.1.4)

 • Chemistry Control Program (B.2.1.5) 

 • One-Time Inspection Program (B.2.1.29)

Stainless steel/Treated water (Note 2)

Aging Effect

 • Crack initiation and growth/ Thermal and mechanical loading

Aging Management Programs

 • ASME Section XI Subsections IWB, IWC and IWD Inservice Inspection Program

(B.2.1.4)

 • One-Time Inspection Program (B.2.1.29)

Carbon steel/Treated water (Note 3)

Aging Effect

 • Crack initiation and growth/ Stress corrosion cracking, inter-granular stress

corrosion cracking

Aging Management Programs

 • None 

Carbon steel/Treated water (Note 4)

Aging Effect

 • Crack initiation and growth/ Thermal and mechanical loading
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Aging Management Programs

 • ASME Section XI Subsections IWB, IWC and IWD Inservice Inspection Program

(B.2.1.4)

 • One-Time Inspection Program (B.2.1.29)

NOTES:

 1. For crack initiation and growth due to stress corrosion cracking and

inter-granular stress corrosion cracking of stainless steel, the three aging

management programs included in GALL line item IV.C1.1-i are applicable and

are specified by the Browns Ferry LRA.

 2. For crack initiation and growth due to thermal and mechanical loading of

stainless steel, continued application of cyclic stresses can produce crack growth

once a crack or crack-like flaw has initiated. This is a purely mechanical function

and is not managed or mitigated by the Chemistry Control Program. The

purpose of these examinations is to identify flaws that may lead to unstable

crack growth in the pressure boundary during service. The welds in the piping

and fittings are basically the same material as one or both of the parts being

joined and are regarded as having higher potential for flaws than base material

to experience flaw growth during plant operation. Therefore, the ASME

Section XI Subsections IWB, IWC and IWD Inservice Inspection Program

focuses on welds and a One-Time Inspection Program augments the ASME

Section XI Subsections IWB, IWC and IWD Inservice Inspection Program for

verifying that service-induced cracking is not occurring in the small-bore piping

less than NPS 4.

 3. For crack initiation and growth due to stress corrosion cracking and

inter-granular stress corrosion cracking of carbon and low-alloy steels, no aging

management programs are applicable as carbon and low-alloy steels are not

susceptible to stress corrosion cracking in this application.

 4. For crack initiation and growth due to thermal and mechanical loading of carbon

and low-alloy steels, continued application of cyclic stresses can produce crack

growth once a crack or crack-like flaw has initiated. This is a purely mechanical

function and is not managed or mitigated by the Chemistry Control Program. The

purpose of these examinations is to identify flaws that may lead to unstable

crack growth in the pressure boundary during service. The welds in the piping

and fittings are basically the same material as one or both of the parts being

joined and are regarded as having higher potential for flaws than base material

to experience flaw growth during plant operation. Therefore, the ASME

Section XI Subsections IWB, IWC and IWD Inservice Inspection Program

focuses on welds and a One-Time Inspection Program augments the ASME

Section XI Subsections IWB, IWC and IWD Inservice Inspection Program for

verifying that service-induced cracking is not occurring in the small-bore piping

less than NPS 4.

The staff found the applicant's basis for not crediting the Chemistry Control Program to be

appropriate and acceptable. The GALL Report specifies AMP XI.M1, "ASME Section XI

Inservice Inspection, Subsections IWB, IWC, and IWD," to detect crack initiation and growth in
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components, and AMP XI.M2, "Water Chemistry," to mitigate crack initiation and growth due to

SCC. The GALL Report further specifies AMP XI.M32, "One-Time Inspection," as an

acceptable method to verify that cracking is not occurring in small bore piping. Since cracking

due to cyclic loading is caused by mechanical or thermal loads, as opposed to an adverse

chemical environment, the staff accepted the applicant's basis for not crediting the Chemistry

Control Program as an AMP for managing cracking due to cyclic loading. The applicant

appropriately credited the Chemistry Control Program to mitigate crack initiation and growth due

to SCC. 

On the basis of its review of the scope of Chemistry Control Program, One-Time Inspection

Program, and the ASME ISI Program, the staff found that the applicant appropriately evaluated

AMR results involving management of crack initiation and growth due to thermal and

mechanical loading and SCC, consistent with the recommendations in the GALL Report.

3.1.2.2.5 Crack Growth due to Cyclic Loading

Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not

applicable to BFN.

3.1.2.2.6 Changes in Dimension due to Void Swelling

Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not

applicable to BFN.

3.1.2.2.7 Crack Initiation and Growth due to Stress Corrosion Cracking or Primary Water

Stress Corrosion Cracking

Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not

applicable to BFN.

3.1.2.2.8 Crack Initiation and Growth due to Stress Corrosion Cracking or Irradiation Assisted

Stress Corrosion Cracking

Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not

applicable to BFN.

3.1.2.2.9 Loss of Preload due to Stress Relaxation

Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not

applicable to BFN.

3.1.2.2.10 Loss of Section Thickness due to Erosion

Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not

applicable to BFN.
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3.1.2.2.11 Crack Initiation and Growth due to Primary Water Stress Corrosion Cracking,

Outside-Diameter Stress Corrosion Cracking, or Intergranular Attack or Loss of Material due to

Wastage and Pitting Corrosion or Loss of Section Thickness due to Fretting and Wear or

Denting due to Corrosion of Carbon Steel Tube Support Plate

Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not

applicable to BFN.

3.1.2.2.12 Loss of Section Thickness due to Flow Accelerated Corrosion

Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not

applicable to BFN.

3.1.2.2.13 Ligament Cracking due to Corrosion

Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not

applicable to BFN.

3.1.2.2.14 Loss of Material due to Flow Accelerated Corrosion

Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not

applicable to BFN.

3.1.2.2.15 Quality Assurance for Aging Management of Non-Safety-Related Components

The applicant referenced LRA Section B.1.3. The staff’s evaluation of LRA Section B.1.3 is

provided in SER Section 3.0.4.

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 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 Results That Are Not Consistent with or Not Addressed in the GALL Report

Summary of Technical Information in the Application. In LRA Tables 3.1.2.1 through 3.1.2.4, the

staff reviewed additional details of the results of the AMRs for material, environment, aging

program (MEAP) combinations that are not consistent with the GALL Report, or that are not

addressed in the GALL Report.

In LRA Tables 3.1.2.1 through 3.1.2.4, the applicant indicated, via Notes F through J, that the

combination of component type, material, environment, and AERM does not correspond to a

line item in the GALL Report, and provided information concerning how the aging effect will be

managed. Specifically, Note F indicated that the material for the AMR line item component is
3-142

not evaluated in the GALL Report. Note G indicated that the environment for the AMR line item

component and material is not evaluated in the GALL Report. Note H indicated that the aging

effect for the AMR line item component, material, and environment combination is not evaluated

in the GALL Report. Note I indicated that the aging effect identified in the GALL Report for the

line item component, material, and environment combination is not applicable. Note J indicated

that neither the component nor the material and environment combination for the line item is

evaluated in the GALL Report.

Staff Evaluation. For component type, material, and environment combinations that are not

evaluated in the GALL Report, the staff reviewed the applicant’s evaluation to determine

whether the applicant 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. The staff’s evaluation is discussed in the following sections.

During the onsite audit, the staff reviewed selected AMR results in LRA Tables 3.1.2.1 through

3.1.2.4, for MEAP combinations that are not consistent with the GALL Report.

3.1.2.3.1 Reactor Vessel – Summary of 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

component groups.

During the onsite audit, the reactor vessel components evaluated by the staff were the reactor

vessel attachment welds, the reactor vessel closure studs and nuts, the reactor vessel support

skirt and attachment welds, the refueling bellows support skirt, and the stabilizer bracket. 

The staff reviewed LRA Table 3.1.2.1, which summarizes the results of the applicant’s AMR

evaluations for the reactor vessel pressure boundary component groups. 

The onsite audit scope for the reactor vessel components did not include any MEAP

combinations that are not consistent with the GALL Report.

For the carbon and low-alloy steel components (reactor vessel support skirt and attachment

welds, the refueling bellows support skirt, and the stabilizer bracket), exposed externally to

inside air of the containment, the applicant identified cracking due to fatigue as a TLAA. TLAAs

are evaluated in SER Section 4. 

3.1.2.3.2 Reactor Vessel Internals – Summary of 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 internals component groups.

In LRA Table 3.1.2.2, the applicant’s AMR for almost all the RVI components is consistent with

the GALL Report. In addition, the applicant has identified several stainless steel and nickel-alloy

RVI components (i.e., core shroud and core plate, top guide, spray lines and spargers, fuel

support, CRD housing, and dry tubes and guide tubes), in a treated-water environment, as

being subject to loss of material due to crevice and pitting corrosion; this is not addressed in the

GALL Report. To manage this aging effect, the applicant credits the BWR Vessel Internals
3-143

Program, and Chemistry Control Program. The staff accepted the Chemistry Control Program

to minimize the potential for loss of material in these components. The BWR Vessel Internals

Program would detect any loss of material, if it is occurring. The BWR Vessel Internals Program

includes BWRVIP recommendations for an effective inservice inspection of reactor vessel

internal components.

In LRA Table 3.1.2.2, the applicant credits the BWR Vessel Internals Program and Chemistry

Control Program to manage cracking in nickel-alloy components of the core spray lines and

sparger assembly, and the stainless steel fuel supports. The staff found that the applicant will

manage cracking in a manner consistent with the GALL Report. 

In LRA Table 3.1.2.2, the applicant identified no aging effect for (1) stainless steel CRD housing

external surfaces exposed to containment air and (2) stainless steel dry tube/guide tube internal

surfaces exposed to air/gas. Air is not identified in the GALL Report as an environment for

these components and materials. On the basis of current industry research and operating

experience, an internal/external environment of gas (which is similar to dry air) on metal will not

result in aging that will be of concern during the period of extended operation. Therefore, the

staff concluded that there are no applicable aging effects for stainless steel in a gas

environment. 

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 during the

period of extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.3.3 Reactor Vessel Vents and Drains System – Summary of Aging Management

Evaluation – Table 3.1.2.3

The staff reviewed LRA Table 3.1.2.3, which summarizes the results of AMR evaluations for the

reactor vessel internals component groups.

In LRA Table 3.1.2.3, the applicant included pressure boundary components (i.e., piping, pipe

fittings, and valves) for vents and drains associated with the RCS. The GALL Report includes

some of these RCS components as part of the steam and power conversion systems in GALL

Report Chapter VIII. Most of these components are made of either carbon/low-alloy steel or

stainless steel, and are exposed to air/gas, inside air, or treated-water environment.

The applicant identified no aging effects for stainless steel components exposed to an internal

environment of air/gas for piping and fittings, or for carbon/low-alloy steel components exposed

to inside air greater than 212 °F on external surfaces. Gas is not identified in the GALL Report

as an environment for these components and materials. On the basis of current industry

research and operating experience, the staff concluded that an internal environment of gas

(which is similar to dry air) on stainless steel components will not result in aging that will be of

concern during the period of extended operation, and found that the applicant’s AMR is

acceptable for stainless steel exposed to a gas environment. For carbon/low-alloy steel

components exposed to inside air greater than 212 °F on external surfaces, the staff found that

the applicant’s AMR is acceptable, because the high environmental temperature precludes the

presence of moisture on the external surfaces.
3-144

The applicant proposes to manage loss of material of carbon steel piping and valve component

groups exposed to air/gas using the One-Time Inspection Program, which is a new

plant-specific program. Visual inspections of the internal surfaces of plant components and

plant commodities are performed during the performance of maintenance to determine loss of

material. The staff found that the One-Time Inspection Program is acceptable for managing

loss of material due to general corrosion since visual inspection will be performed on internal

surfaces of components to detect any sign of aging degradation.

In LRA Table 3.1.2.3, the applicant identified the Flow-Accelerated Corrosion Program, to

manage loss of material due to flow accelerated corrosion in piping and fittings made of

carbon/low-alloy steel. This program includes analysis to determine critical locations, baseline

inspections to determine the extent of thinning at these locations, and follow-up inspections to

confirm the predictions. Repair, replacements, or re-evaluations are performed as necessary.

The staff found that the applicant identified the appropriate AMP for this aging effect.

In LRA Table 3.1.2.3, the applicant identified that loss of material due to general, crevice, pitting

and galvanic corrosion in both carbon/low-alloy steel and stainless steel piping and fittings in

the reactor vessel vents and drains lines is managed by the Chemistry Control Program and

One-Time Inspection Program. The Chemistry Control Program relies on monitoring and control

of reactor water chemistry based on BWRVIP-79 to prevent loss of material from general,

pitting, crevice or galvanic corrosion. However, high concentrations of impurities at crevices and

locations of stagnant flow conditions could cause corrosion. Therefore, verification of the

effectiveness of the Chemistry Control Program needs to be performed to ensure that corrosion

is not occurring. The one-time inspection of selected components at susceptible locations is an

acceptable method for ensuring that corrosion is not occurring and that the component’s

intended function will be maintained during the period of extended operation. 

In RAI 3.1.2.3-1, dated December 1, 2004, the staff stated that, in LRA Table 3.1.2.3, the

applicant identified loss of bolting function (loss of material) as an applicable aging effect due to

wear. The bolting is exposed externally to the inside air environment and the applicant credited

its Bolting Integrity Program with management of this aging effect. Therefore, the staff

requested that the applicant provide information on the scope and techniques of past

inspections, the results obtained, applied mitigative methods, repairs, frequency of the

inspections, and any other relevant information.

In its response, by letter dated January 31, 2005, the applicant stated that bolting degradation

due to wear could occur at locations of repeated relative motion of mechanical component

bolted joints. Wear of bolted joint components is generally not a concern as demonstrated by

industry operation experience and is not an AERM for the period of extended operation. For

license renewal purposes only, wear is assumed as a potential mechanism for critical bolting

applications. Critical bolting applications constitute RCPB components where closure bolting

failure could result in loss of reactor coolant and jeopardize safe operation of the plant.

The staff concurred with the applicant’s identification of loss of bolting function due to wear in

carbon and low-alloy steel and stainless steel bolting associated with GALL Report Items

IV.C1.3-e and IV.C1.2-d. For those components that fall under the GALL Report Item IV.C1.2-d,

the applicant indicated that the material listed in the GALL Report is different from the material

used at BFN (LRA Table 3.1.2.4, Footnote F). The applicant stated that the bolting used for

recirculation pump closure bolting is ASTM A540 Grade B23. Although the GALL Report lists
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high-strength low-alloy (HSLA) steel SA-193 Grade B7 for the applicable component, the staff

concludes that degradation due to wear of ASTM A540 Grade B23 bolting will be adequately

managed by the applicant’s Bolting Integrity Program and is acceptable. Therefore, the staff’s

concern described in RAI 3.1.2.3-1 is resolved.

The staff found that the applicant 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).

3.1.2.3.4 Reactor Vessel Recirculation System – Summary of Aging Management Evaluation –

Table 3.1.2.4

The staff reviewed LRA Table 3.1.2.4 and Section 3.1.2.1.4. which summarize the results of

AMR evaluations for the reactor recirculation system component groups. The component

groups for this system include piping and fittings (including flexible connections, flow restricting

orifices and strainers), valves, pumps, tanks, and heat exchangers. The bolting group in this

system is not part of the onsite audit scope.

In LRA Table 3.1.2.4, the applicant identified no aging effects in reactor recirculation

component groups, for stainless steel and copper alloy carrying air/gas; for carbon/low-alloy

steel, glass (fittings), and stainless steel, with external surface exposed to inside air; and for

cast iron/cast-iron alloys, carbon/low-alloy steel, copper alloys, glass (fittings), and stainless

steel carrying lubricating oil. Air and lubricating oil are not identified in the GALL Report as

environments for these components and materials. Those components carrying lubricating oil

are not subject to wetting and their surfaces always remain oil-coated because they are

continuously in service.

During the onsite audit, the staff asked the applicant if there exists any contamination of water

in the components that carry lubricating oil. By letter dated October 8, 2004, the applicant

submitted its formal response to the staff, stating that:

Lubricating oil systems generally do not suffer appreciable degradation by cracking or

loss of material since the environment is not conducive to corrosion mechanisms. In

addressing the question, "Is there a potential for water contamination?" plant experience

(i.e., maintenance/ operating history) is utilized as a basis for conclusions reached. The

lubricating oil applications where there is no history of water contamination do not have

any potential aging mechanisms. Those applications where water contamination does

occur, such as the diesel generator combustion air intake filters, potential loss of

material due to general, pitting, and crevice corrosion was identified as requiring

management for the period of extended operation.

Based on the applicant’s response, the staff concluded that the applicant had appropriately

addressed the lubricating oil environment in its AMR. Those components that are susceptible to

such contamination are identified, and aging management for loss of material is specified.

On the basis of current industry research and operating experience, dry air on metal will not

result in aging that will be of concern during the period of extended operation. The external

environments being referred to are typical of ambient air (e.g., under a shelter, indoors, or
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air-conditioned enclosure or room). Significant corrosion of low-alloy steel requires an

electrolytic environment, and a simultaneous presence of oxygen and moisture. Without the

presence of an aggressive environment, these components will experience insignificant

amounts of corrosion, and no aging effects are applicable to this component/commodity group.

Wrought austenitic stainless steels are not susceptible to significant general corrosion that

would affect the intended function of components. Therefore, the staff concluded that there are

no applicable aging effects for these material and environment combinations.

In components made from cast iron, copper alloy, copper-zinc alloys, brass, ductile iron, and

bronze, selective leaching takes place when these components are exposed to raw water,

corrosion-inhibited treated water, oxygenated and de-oxygenated treated water, or are buried

underground. In LRA Table 3.1.2.4, the applicant identified the Selective Leaching of Materials

Program to manage loss of material due to selective leaching in copper-alloy components

associated with heat exchangers and tubing, valves, and pipe fittings exposed to raw water and

treated water. The applicant’s selective leaching program relies on visual inspections and

hardness measurements of selected components susceptible to selective leaching. On the

basis of industry operating experience with this material and environment, the staff found this

acceptable.

Cast iron/cast-iron alloy fittings exposed to air/gas, carbon/low-alloy steel piping/fittings and

valves exposed to air/gas, and stainless steel components of heat exchangers exposed to raw

water (potable) or treated water are susceptible to loss of material due to pitting, crevice and

general corrosion, biofouling, and MIC. In LRA Table 3.1.2.4 (rows 60, 63, 65, and 66), the

applicant credited the One-Time Inspection Program to manage loss of material in these

components. This aging effect is not in the GALL Report for this component, material, and

environment combination. The one-time inspection provides the opportunity to visually inspect

the internal surfaces of components during preventive and corrective maintenance activities.

During the onsite audit, the staff noted corrosion, biofouling, and MIC in stainless steel and

copper components in heat exchangers exposed to raw water or treated water that are

managed by One-Time Inspection Program. The staff asked if there were any other AMPs that

periodically inspect heat exchangers subject to these aging mechanisms. By letter dated

October 8, 2004, the applicant submitted its formal response to the staff as follows:

For Table 3.1.2.4, Reactor Recirculation System, the raw water is supplied from the Raw

Cooling Water System and should specify the Open-Cycle Cooling Water Program as

the appropriate aging management program.

For Table 3.1.2.4, Reactor Recirculation System, the treated water refers to a

self-contained cooling water system supplied with the Variable Frequency Drives. The

Chemistry Control Program and the One-Time Inspection Program are the appropriate

aging management programs for this cooling water system.

The staff concurred that the Open-Cycle Cooling Water Program for heat exchangers exposed

to raw water and the Chemistry Control Program/One-Time Inspection Program for heat

exchangers exposed to treated water are the appropriate AMPs. These programs are able to

manage the aging effects due to corrosion, biofouling, and MIC in these components. 
3-147

Cast iron/cast iron-alloy component external surfaces exposed to inside air are managed by the

Systems Monitoring Program against any loss of material due to general corrosion. The system

walkdown encompasses all or part of the total accessible system, such that the entire system is

covered over time. The walkdown is a detailed look at system parameters, material condition,

operation, configuration, degraded components, outstanding work activities, and design

changes. The material condition involves no missing, discolored-indicating-a-potential-leak, or

damaged insulation. The staff found that the Systems Monitoring Program would be able to

detect any corrosion on the external surfaces of these components.

In LRA Table 3.1.2.4, heat exchanger components made of carbon/low-alloy steel and exposed

to raw water are susceptible to loss of material due to biofouling, MIC, crevice, galvanic,

general, and pitting corrosion. The applicant credited the Open-Cycle Cooling Water System

Program to manage these aging effects. These AMP activities, in accordance with the

guidelines of GL 89-13, include managing aging effects by condition monitoring (system and

component testing, visual inspections, and NDE testing), and by preventive actions (biocide

treatment and filtering to prevent loss of material due to MIC, biofouling, flow blockage and

reduction of heat transfer due to biological and particulate fouling). The staff found this

acceptable.

In LRA Table 3.1.2.4, the applicant identified that the loss of material due to general, crevice,

pitting, and galvanic corrosion in both carbon/low-alloy steel and stainless steel piping and

fittings and crack initiation/growth due to SCC in stainless steel piping and fittings in treated

water are managed by the Chemistry Control Program and One-Time Inspection Program. The

Chemistry Control Program relies on monitoring and control of reactor water chemistry based

on BWRVIP-79 to prevent loss of material from general, pitting, crevice or galvanic corrosion.

However, high concentrations of impurities at crevices and locations of stagnant flow conditions

could cause corrosion. Therefore, verification of the effectiveness of the Chemistry Control

Program needs to be performed to ensure that corrosion is not occurring. The one-time

inspection of selected components at susceptible locations is an acceptable method for

ensuring that corrosion is not occurring and that the component’s intended function will be

maintained during the period of extended operation. 

In LRA Table 3.1.2.4, the applicant identified loss of bolting function due to wear as an AERM

for carbon, low-alloy, and stainless steel components that are exposed externally to the inside

air environment. The applicant's AMR for these components has categorized them as one of

the following: 1) Material not in the GALL Report item for this component (i.e., LRA

Table 3.1.2.4, Footnote F), or 2) Consistent with the GALL Report item for component, material,

environment, and aging effect. The AMP takes some exception to GALL (i.e., LRA

Table 3.1.2.4, Footnote B). The applicable bolting is the RCPB valve closure bolting (GALL

Report Item IV.C1.3-e) and reactor recirculation pump closure bolting (GALL Report Item

IV.C1.2-d). The applicant credits the Bolting Integrity Program in LRA Section B.2.1.16 with the

management of loss of bolting function due to wear of the aforementioned carbon and low-alloy

steel and stainless steel bolts.

In RAI 3.1.2.3-1(C), dated December 16, 2004, the staff stated that the LRA identified loss of

bolting function (loss of material) as an applicable aging effect due to wear. The bolting is

exposed externally to the inside air environment and the applicant credited its Bolting Integrity

Program with management of this aging effect. Therefore, the staff requested that the applicant

provide information as to how the plant-specific experience related to this aging effect impacts
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the attributes specified in the Bolting Integrity Program. In response to RAI 3.1.2.3-1(C), by

letter dated January 31, 2005, the applicant provided the following summary of its aging effect

evaluation for wear.

Bolting degradation due to wear could potentially occur at locations of repeated relative

motion of mechanical component bolted joints. Wear of bolted joint components is

generally not a concern; however, for license renewal purposes, wear is being assumed

as a potential mechanism for ‘critical bolting applications.’ ‘Critical bolting applications’

constitute reactor coolant pressure boundary components where closure bolting failure

could result in loss of reactor coolant and jeopardize safe operation of the plant. These

locations include bolted joints on the recirculation pumps and reactor coolant pressure

boundary valves. Therefore, wear of reactor coolant pressure boundary bolted joints

requires aging management for the period of extended operation.

The staff concurred with the applicant’s identification of loss of bolting function due to wear, in

carbon and low-alloy steel and stainless steel bolting associated with GALL Report Items

IV.C1.3-e and IV.C1.2-d.

In LRA Table 3.1.2.4, for those components that fall under GALL Report Item IV.C1.2-d, the

applicant indicated that the material listed in the GALL Report is different from the material used

at BFN (LRA Table 3.1.2.4, Footnote F). The applicant stated that the bolting used for

recirculation pump closure bolting is ASTM A540 Grade B23. Although the GALL Report lists

HSLA steel SA-193 Grade B7 for the applicable component, the staff concludes that

degradation due to wear of ASTM A540 Grade B23 bolting will be adequately managed by the

applicant’s Bolting Integrity Program and is, therefore, acceptable. 

In LRA Table 3.1.2.4, for those components that fall under GALL Report Item IV.C1.3-e, RCPB

valve closure bolting, the applicant stated that the bolting is consistent with the GALL Report

item for component, material, environment, and aging effect in which the applicant’s AMP takes

some exception to GALL Report Volume 2, (LRA Table 3.1.2.4, Footnote B). The staff found

acceptable the applicant’s use of the Bolting Integrity Program, with exceptions, to manage

wear of GALL Report Item IV.C1.3-e components.

In LRA Table 3.1.2.4, the applicant identified loss of preload as an applicable aging effect due

to stress relaxation. The bolting is exposed externally to the inside air environment and the

applicant credited its Bolting Integrity Program with management of this aging effect. The staff

concurs with the applicant that carbon and low-alloy steel and stainless steel bolting identified

above are susceptible to loss of preload due to stress relaxation when exposed externally to the

inside air environment. For those components that the applicant lists as being fabricated from a

material not listed for corresponding GALL Report, Volume 2, Item IV.C1.2-e, the applicant

indicates that ASTM A 540 Grade B23 bolting is used in lieu of ASME SA 193 Grade B7, which

is listed in GALL Report Item IV.C1.2-e. 

In RAI-3.1.2.4-1(A), dated December 1, 2004, the staff requested the applicant to provide

additional information on the previous plant-specific experience of loss of bolting function due to

this aging effect. In addition, the applicant was asked to provide information on the scope and

the techniques of the past inspections, the results obtained, applied mitigative methods, repairs,

frequency of its inspections and any other relevant information related to the identification of

this aging effect of the reactor recirculation systems and to provide information as to how the
3-149

plant-specific experience related to this aging effect impacts the attributes specified in the

Bolting Integrity Program. 

In its response, by letter dated January 31, 2005 the applicant stated: 

Stress relaxation was identified to be an aging effect that requires management for the

period of extended operation for the reactor water recirculation pump closure bolting in

LRA Table 3.1.2.4, line item 2. The reactor water recirculation pump closure bolting is

inspected in accordance with the requirements of ASME Section XI, Table IWB-2500-1,

Category B-G-1. Results of these inspections are provided below. [Table of Results is

listed in RAI response] 

Based on this review, no repairs have been performed on the reactor recirculation pump

closure bolting. As discussed in LRA Section B.2.1.16, EPRI NP-5769, and the additional

recommendations of NUREG-1339 to prevent or mitigate degradation and failure of SR bolting

have been implemented. The plant-specific experience related to reactor recirculation pump

closure bolting has no impact on the attributes specified in the Bolting Integrity Program.

The staff found the applicant's response to RAI 3.1.2.4-1(A) acceptable and concluded that the

applicant's use of the Bolting Integrity Program will adequately manage loss of preload due to

stress relaxation in recirculation pump closure bolting, GALL Report Item IV.C1.2-e. Therefore,

the staff’s concern described in RAI 3.1.2.4-1(A) is resolved.

In LRA Table 3.1.2.4, the applicant lists RCPB valve closure bolting, (GALL Report Item

IV.C1.3-f), as being susceptible to loss of bolting function due to stress relaxation. Revised LRA

Table 3.1.2.4 indicates that ASME SA 193 Grade B7 is used in some applications and the

Bolting Integrity Program is credited with managing this aging effect. The component, material,

environment, and aging effect are consistent with the GALL Report. The AMP takes some

exceptions to the GALL Report. The staff found this acceptable. 

The applicant also lists ASTM A 540 Grade B23 as being used for RCPB valve closure bolting

(GALL Report Item IV.C1.3-f). Although the material is different from that listed in the GALL

Report, it is very similar and would be susceptible to the same aging effects as ASME SA 193

Grade B7. It would also be adequately managed by the same AMP (Bolting Integrity Program).

Therefore, the staff finds the applicant's use of the Bolting Integrity Program as an acceptable

method to manage loss of preload as a result of stress relaxation during the period of extended

operation.

In LRA Table 3.1.2.4, the applicant identified loss of bolting function (cumulative fatigue

damage) due to fatigue as an applicable aging effects for carbon and low-alloy steel bolting

used on the recirculation pump and RCPB valve closure bolting. The applicant indicated that

ASTM A 540 Grade B23 as well as ASME SA 193 Grade B-7 are used. ASME SA 193 Grade

B-7 is the material referenced in the GALL Report for these components. These two materials

are similar and would both be potentially susceptible to fatigue. Therefore, the staff concurred

with the applicant that the referenced components are subject to cumulative fatigue damage

when exposed to inside air (external) environments. 

For the reactor recirculation pump closure bolting (GALL Report Item IV.C1.2-f), the applicant

listed fatigue as an applicable aging effect and indicated that fatigue is evaluated as a TLAA
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and referenced LRA Section 4.3. The applicant indicated that its TLAA is consistent with the

GALL Report. The staff found the applicant's use of the TLAA "Metal Fatigue" in LRA

Section 4.3, acceptable to manage loss of bolting function due to fatigue for the period of

extended operation. 

The applicant lists ASTM A 540 Grade B23 and ASME SA 193 Grade B7 as bolts used in the

RCPB as valve closure bolting (GALL Report Item IV.C1.3-g). The material listed in the GALL

Report for this item number is SA 193 Grade B7. GALL requires a TLAA, meeting the

requirements of 10 CFR 54.21(c), to be performed for the extended period of operation for

GALL Report Item IV.C1.3-g. ASTM A 540 Grade B23 is also potentially susceptible to fatigue

and the staff considers the GALL Report requirements for ASME SA 193 Grade B7 to also be

applicable to ASTM A540 Grade B23 bolting with regard to fatigue. The applicant indicated that

it has performed a TLAA that meets the requirements of 10 CFR 54.21(c) for ASTM A 540

Grade B23 and ASME SA 193 Grade B7 bolting used for RCPB valve closure bolting identified

as GALL Report Item IV.C1.3-g. Therefore, the staff found the applicant's AMR for these items

acceptable.

In LRA Table 3.1.2.4, the applicant identified biofouling and loss of material due to MIC, and

crevice and pitting corrosion as AERMs in copper-alloy heat exchanger components that are

exposed to raw water environments internally. The AMR for these components has categorized

them as the following: neither the component nor the material and environment combination is

evaluated in the GALL Report (i.e., LRA Table 3.1.2.4, Footnote J). The applicant credits the

Open-Cycle Cooling Water System Program to manage aging effects caused by biofouling and

applicable forms of corrosion. The Open-Cycle Cooling Water System Program is evaluated in

LRA Section 3.0.3.1. 

The applicant identified loss of material due to crevice and pitting corrosion in copper-alloy

piping in a treated water (internal) environment, GALL Report Item VII.C2.1-a. The applicant

indicated in the LRA that the One-Time Inspection Program is the credited AMP. The applicant

indicated that the material used is not consistent with the GALL Report and that the aging

effects identified for this material/environment combination are consistent with industry

guidance.

The staff concurred with the applicant’s determination that copper-alloy heat exchanger

components that are subjected to a raw water environment internally are susceptible to

biofouling and loss of material due to MIC, crevice and pitting corrosion. The staff also

concurred with the applicant’s identification of crevice and pitting corrosion in copper-alloy

piping in a treated-water environment. 

In RAI 3.1.2.4-3, dated November 4, 2004, the staff requested the applicant to provide

information regarding the heat exchangers, their function, and the selection of the credited AMP

(One-Time Inspection Program). In its response, by letter dated December 9, 2004, the

applicant stated that the heat exchangers identified in LRA Table 3.1.2.4, Reactor Recirculation

System, are the reactor recirculation pump motor generator raw water/lubrication oil heat

exchangers for Unit 1 and the reactor recirculation pump, variable frequency drive, raw water

heat exchangers for Units 2 and 3. The Unit 1 reactor recirculation pump motor generators will

be replaced by variable frequency drives prior to Unit 1 restart. The applicant also stated that

the raw water environment for the heat exchangers is supplied from the raw water cooling

system and the appropriate AMP is the Open-Cycle Cooling Water Program. The Open-Cycle
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Cooling Water System Program includes condition monitoring such as system and component

testing, visual inspection, and NDE testing. Preventive actions such as biocide treatment and

filtering are used to prevent loss of material due to MIC, biofouling, flow blockage, and

reduction of heat transfer due to biological and particle fouling. The applicant’s Open-Cycle

Cooling Water System Program is evaluated in SER Section 3.0.3.1 and consistent with the

GALL Report after enhancements. The AMP credited by the applicant provides reasonable

assurance that the aging effects caused by biofouling, MIC, and crevice and pitting corrosion

will be adequately managed. The staff’s concern described in RAI 3.1.2.4-3 is resolved.

For copper piping in a treated-water environment (internal), which the applicant identified as

being susceptible to loss of material due to crevice and pitting corrosion, the staff requested in

RAI 3.1.2.4-4, dated November 4, 2004, that the applicant provide more information regarding

the operating and inspection history of the components. In its response, by letter dated

December 9, 2004, the applicant stated that the copper-alloy piping is an integral part of the

reactor recirculation pump variable frequency drives, which are recent additions to Unit 2 in

2003 and Unit 3 in 2004. Reactor recirculation pump variable speed drives will be installed in

Unit 1 prior to start up. The vendor manual identifies the material as red brass. The applicant

stated that the appropriate AMP is the Chemistry Control Program and the One-Time Inspection

Program. Red brass could suffer loss of material in a treated-water environment if the chemistry

is not controlled properly. Given that the applicant will perform a one-time inspection to ensure

that degradation has not occurred and control the chemistry of the treated water, the potential

degradation of this piping due to crevice and pitting corrosion will be adequately managed

during the extended period of operation.

The staff reviewed the applicant’s AMR for evaluating biofouling and loss of material due to

MIC, crevice and pitting corrosion in heat exchanger copper-alloy components listed in LRA

Table 3.1.2.4 that are exposed to a raw water (internal) environment. The staff also reviewed

the applicant’s AMR for evaluating loss of material due to crevice and pitting corrosion in

copper-alloy piping (GALL Report Item VII.C2.1-a) in a treated-water environment. On the basis

of its review, the staff found that the applicant had demonstrated that the effects of aging for

these components will be adequately managed so that their intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3).

3.1.2.3.5 Components with No Aging Effects in Inside Air Environment Externally and

Components with No Aging Effects in Treated Water Environment Internally

In LRA Table 3.1.2.4, the applicant identified several components where the materials used are

not susceptible to aging effects identified in the GALL Report. The AMRs for these components

have categorized them as the following: material is not in the GALL Report item for this

component (i.e., LRA Table 3.1.2.4, Footnote F) and aging effect in the GALL Report item for

this component, material/environment combination is not applicable (i.e., LRA Table 3.1.2.4,

Footnote I). In evaluating the aging effect, the applicant stated that for GALL Report Items

V.E.2-b and VII.I.2-b, carbon and low-alloy steel bolting are identified as being susceptible to

crack initiation and growth due to cyclic loading and SCC. GALL specifies the use of a Bolting

Integrity Program in accordance with GALL AMP XI.M18. Under plant-specific notes, LRA

Table 3.1.2.4, Footnote 3, the applicant indicated that high yield-strength, heat-treated bolting is

not used and SCC and cracking due to cyclic loading are not concerns for BFN license renewal. 
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The applicant provided additional information along with its revised LRA Table 3.1.2.4 by letter

dated March 16, 2005. The applicant stated the following:

The aging management review determined that this bolting is not susceptible to SCC as

the yield strength of the ASME SA 193 Grade B7 bolting is less than 150 ksi. Crack

initiation and growth due to cyclic loading is not considered a license renewal concern

due to high cycle fatigue since it would be discovered during the current license period

and corrected. In addition, cyclic primary loads are evaluated against conservative

stress limits and are not a contributor to fatigue due to the few number of stress cycles

postulated (e.g., earthquake and fluid transient loads). The absence of crack growth due

to cyclic loading and stress corrosion cracking identified in current line items 6 and 8 is

now shown in line items 10 and 12. 

Typically, ASME SA193 Grade B7 bolting less than 150 ksi yield strength is not susceptible to

SCC and would not require an AMP to manage cracking due to stress corrosion. With regard to

cracking due to cyclic loading, the staff concurred with the applicant that cracking due to cyclic

loading would not be applicable. The staff found the applicant's conclusion, that no AMP is

required for these item numbers, acceptable. 

The applicant indicated, by letter dated March 16, 2005, that stainless steel non-RCPB bolting

in the reactor recirculation system boundary was evaluated for aging effects such as corrosion,

cracking due to cyclic loading, SCC, wear, stress relaxation, and fatigue. These

bolting/material/environment combinations are not addressed in the GALL Report. The

applicant stated that the bolting in question has a yield strength less than 150 ksi. The applicant

identified fatigue as being the only applicable aging effect for these bolts in an inside air

(external) environment. The applicant further stated that fatigue is addressed as a TLAA in LRA

Section 4.3. Based on a review of the applicant's March 16, 2005 letter, and considering the

environment, material and application, the staff concurred with the applicant's conclusion and

found its evaluation of the aforementioned bolts, in an inside air (external) environment,

acceptable.

In GALL Report Volume 2, Items V-E-2-b and VII.I.2-b list carbon or low-alloy steel bolting as

the applicable material and indicate that crack initiation and growth due to cyclic loading and

SCC are aging effects that require management during the extended period of operation.

Revised LRA Table 3.1.2.4 lists ASME SA 193 Grade B7, which is an HSLA material for these

GALL Report item numbers. The AMR categorizes these line items as aging effects in the

GALL Report item for this component/material/environment combination that are not applicable,

and high yield-strength, heat-treated bolting, greater than150 ksi, is not used in non-RCPB

bolting applications at BFN (as evidenced in LRA Table 3.1.2.4, Footnote I,3). The staff did not

consider ASME SA 193 Grade B7 bolting less than 150 KSI as being susceptible to SCC in an

inside air (external) environment as described in the applicant's LRA. Therefore, the staff

concurs with the applicant's conclusion that no AMP is required for these components due to

cracking as a result of cyclic or SCC in an inside air (external) environment. 

GALL Report Items VII.I.1-b and V.E.1-b are listed as being carbon or low-alloy components

that are susceptible to loss of material due to general corrosion in an inside air (external)

environment. LRA Table 3.1.2.4 lists copper alloy as the material used and does not list any

aging effects for material/environment as being applicable. The AMR categorizes this line item

as “material is not in the GALL Report item for this component” (LRA Table 3.1.2.4,
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Footnote F). The staff does not consider copper-alloy components to be susceptible to any

aging effects in an inside air (external) environment. Therefore, the staff concurred with the

applicant's conclusion that no AMP is required for these components.

In RAI 3.1.2.4-5, dated November 4, 2004, the staff stated that the GALL Report Item V.C.1-b

is listed as stainless steel valves; the material that is the same as used at BFN. The aging

effects listed in the GALL Report as requiring management are loss of material due to pitting,

crevice corrosion, MIC, and biofouling. The components are in a treated water (internal)

environment, which is the same as listed in the GALL Report. Therefore, the staff requested

that the applicant discuss the age, operating history, and inspection history of the valves. The

staff also requested that the applicant provide a detailed explanation of the attributes of the

system design that make degradation due to MIC and biofouling not applicable.

In its response, by letter dated December 9, 2004, the applicant stated that the water in this

cooling water subsystem is demineralized water that has no history of microbiologically

influenced corrosion activity. The staff found this acceptable because stainless steel in a

demineralized water environment would not be considered susceptible to loss of material due to

pitting, crevice corrosion, MIC, and biofouling. Therefore, the staff’s concern described in

RAI 3.1.2.4-5 is resolved.

In LRA Table 3.1.2.4, the applicant also identified several components in which the material

used is not susceptible to aging effects identified in the GALL Report. The AMR for these

components categorized them as the following: “material is not in GALL Report item for this

component” (LRA Table 3.1.2.4, Footnote F) and the aging effect in the GALL Report item for

this component/material/environmental combination is not applicable (i.e., LRA Table 3.1.2.4,

Footnote I).

GALL Report Items V.E.2-b and VII.I.2-b, carbon and low-alloy steel bolting, are identified as

being susceptible to crack initiation and growth due to cyclic loading and SCC. The GALL

Report specifies the use of a Bolting Integrity Program in accordance with GALL Report Volume

2, Chapter XI.M18. Under plant-specific notes, LRA Table 3.1.2.4, Footnote 3, the applicant

indicated that high yield-strength, heat-treated bolting is not used at BFN and SCC and

cracking due to cyclic loading are not concerns for license renewal. The staff followed up and

sought clarifications on the LRA Table 3.1.2.4 information.

The applicant provided additional information along with its revised LRA Table 3.1.2.4 by letter

dated March 16, 2005. The applicant stated the following:

The aging management review determined that this bolting is not susceptible to SCC as

the yield strength of the ASME SA 193 Grade B7 bolting is less than 150 ksi. Crack

initiation and growth due to cyclic loading is not considered a license renewal concern

due to high cycle fatigue since it would be discovered during the current license period

and corrected. In addition, cyclic primary loads are evaluated against conservative

stress limits and are not a contributor to fatigue due to the few number of stress cycles

postulated (e.g., earthquake and fluid transient loads). The absence of crack growth due

to cyclic loading and stress corrosion cracking identified in current line items 6 and 8 is

now shown in line items 10 and 12. 
3-154

Typically, ASME SA193 Grade B7 bolting, less than 150 ksi yield strength, is not susceptible to

stress corrosion cracking and would not require an AMP to manage cracking due to stress

corrosion. With regard to cracking due to cyclic loading, the staff concurs with the applicant that

cracking due to cyclic loading would not be applicable. The staff finds the applicant's

conclusion, that no AMP is required for these item numbers, acceptable. 

The applicant indicated, by letter dated March 16, 2005, that stainless steel non-RCPB bolting

in the reactor recirculation system boundary was evaluated for aging effects such as corrosion,

cracking due to cyclic loading and SCC, wear, stress relaxation, and fatigue. These

bolting/material/environment combinations are not addressed in the GALL Report. The

applicant stated that the bolting in question has a yield strength less than 150 ksi. The applicant

identified fatigue as being the only applicable aging effect for these bolts in an inside air

(external) environment. The applicant further stated that fatigue is addressed as a TLAA in LRA

Section 4.3. Based on a review of the applicant's March 16, 2005 letter, and considering the

environment, material and application, the staff concurred with the applicant's conclusion and

finds its evaluation of the aforementioned bolts, in an inside air (external) environment,

acceptable.

In GALL Report Volume 2, Items V-E-2-b and VII.I.2-b list carbon or low-alloy steel bolting as

the applicable material and indicates that crack initiation and growth due to cyclic loading/SCC

are aging effects that require management during the extended period of operation. Revised

LRA Table 3.1.2.4 lists ASME SA 193 Grade B7, which is an HSLA material for these GALL

Report item numbers. The AMR categorizes these line items as: “Aging effect in NUREG-1801

item for this component, material and environment combination is not applicable and high yield

strength heat-treated bolting, greater than150 ksi, is not used in non-RCPB bolting applications

at BFN” (LRA Table 3.1.2.4, Footnote I,3). The staff did not consider ASME SA 193 Grade B7

bolting less than 150 KSI as being susceptible to SCC in an inside air (external) environment as

described in the applicant's LRA. Therefore, the staff concurred with the applicant's conclusion

that no AMP is required for these components due to cracking as a result of cyclic or SCC in an

inside air (external) environment. 

GALL Report, Items VII.I.1-b and V.E.1-b are listed as being carbon or low-alloy components

that are susceptible to loss of material due to general corrosion in an inside air (external)

environment. LRA Table 3.1.2.4 lists copper alloy as the material used and does not list any

aging effects for the material/environment as being applicable. The AMR categorizes this line

item as “material is not in the GALL Report item for this component,” (LRA Table 3.1.2.4,

Footnote F). The staff does not consider copper-alloy components to be susceptible to any

aging effects in an inside air (external) environment. Therefore, the staff concurred with the

applicant's conclusion that no AMP is required for these components.

3.1.2.3.6 SCC in RV Flange Leak Detection Line and Jet Pump Sensing Line

SRP-LRA Section 3.1.3.2.4.2 states that the crack initiation and growth due to thermal and

mechanical loading or SCC, including IGSCC, could occur in the BWR RV flange detection line

and jet pump sensing line. The GALL Report recommends that a plant-specific AMP be

evaluated to mitigate or detect crack initiation and growth due to SCC of the vessel flange

detection line and jet pump sensing line.
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In LRA Section 3.1.2.2.4, the applicant addressed vessel flange leak detection lines that are

subjected to SCC. The applicant proposed to use the One-Time Inspection Program for

managing this aging effect. 

In RAI 3.1.1-1, dated December 1, 2004, the staff requested that the applicant provide

information on the plant-specific experience related to cracking due to SCC in the vessel flange

leak detection lines at the BFN units, and its method of implementation of the One-Time

Inspection Program. The staff also requested the applicant to provide justification for using

one-time inspection in detecting the cracking due to SCC in a timely manner. 

In its response, by letter dated January 31, 2005, the applicant indicated that, in addition to the

One-Time Inspection program, the ASME Code Section XI Subsections IWB, IWC, and IWD

Inservice Inspection Program will be implemented for the RV flange leak detection lines. The

applicant stated that it will revise the first paragraph in LRA Section 3.1.2.2.4 to include the ISI

program as an additional AMP for the RV flange leak detection lines. The applicant stated that

the AMR shown in LRA Table 3.1.2.1 will be revised to include the aging effects (cracking

growth from cyclic loading, loss of material due to crevice, pitting, and general corrosion), and

their associated AMPs (One-Time Inspection Program and ISI Program) for the carbon steel

and low-alloy steel RV heads, flanges, and shells. The staff found this response acceptable.

The proposed AMPs will provide adequate measures in managing the aging effects of the RV

flange leak detection lines. Therefore, the staff’s concern described in RAI 3.1.1-1 is resolved.

In LRA Section 3.1.2.2.4, the applicant addressed jet pump sensing lines that are subject to

SCC. The applicant proposed to use the Chemistry Control Program and One-Time Inspection

Program for managing this aging effect. 

In RAI 3.1.1-2, dated December 1, 2004, the staff requested that the applicant provide

information on the plant-specific experience related to cracking due to SCC in jet pump sensing

lines, and its method of implementing the One-Time Inspection Program. The staff also

requested that the applicant provide justification for using the One-Time Inspection Program to

detect cracking due to SCC in a timely manner. 

In its response to RAI 3.1.1-2, by letter dated January 31, 2005, the applicant stated that the jet

pump sensing lines have not previously experienced cracking due to SCC, IGSCC or cyclic

loading. The jet pump sensing lines inside the RV are not within the scope of the license

renewal process. According to Section 2.3.12.7 of the BWRVIP-41, “BWR Jet Pump Assembly

Inspection and Flaw Evaluation Guidelines,” inspection of the jet pump sensing lines is

continuously occurring during the plant operation. Therefore, if this line fails, plant technical

specifications require either a plant shutdown or a safety assessment to justify continued

operation. Therefore, the failure of the sensing lines inside the RV has no adverse safety

consequences and does not need to be included within the scope of license renewal. However,

the applicant agreed to revise the AMR by adding the AMPs (shown below) for the jet pump

sensing line penetrations and external lines that are listed in LRA Tables 3.1.2.1 and 3.1.2.4.

The applicant included the BWR Reactor Penetration Program for managing the aging effect

related to cracking due to SCC in the jet pump sensing lines penetrations at BFN. The applicant

stated that this AMP is consistent with GALL AMP XI.M8, “BWR Penetrations,” with no

exceptions. BWR Reactor Penetration Program includes the staff’s approved versions of

BWRVIP-27, “BWR Standby Liquid Control System/Core Plate delta P Inspection and Flaw
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Evaluation Guidelines,” and BWRVIP-49, “Instrumentation Penetration Inspection and Flaw

Evaluation Guidelines.” SER Section 3.0.3.2.6 presents the staff’s detailed review of this AMP.

The staff finds the applicant’s response to RAI 3.1.1-2 acceptable, and the staff’s concern

described in this RAI is resolved.

The applicant stated that the Chemistry Control Program will be used at BFN to manage SCC in

the jet pump sensing lines. The Chemistry Control Program is based on EPRI Report

TR-103515-R2, (the 2000 revision of "BWR Water Chemistry Guidelines”), which was approved

by the staff in February 2000. The staff found the EPRI TR-103515-R2 acceptable because the

program is based on updated industry experience and plant-specific and industry-wide

operating experience that confirms the effectiveness of the RCS chemistry program. The staff

found that implementation of the Chemistry Control Program would be consistent with the GALL

AMP XI.M2; therefore, it is acceptable. In addition, the proposed inspection AMPs would ensure

the identification of cracking due to SCC, IGSCC, and cyclic loading in a timely manner so that

the intended function of the jet pump sensing lines is not sacrificed. Therefore, the staff

concluded that by the implementation of the additional AMPs, the aforementioned aging effects

of the jet pump sensing lines would be managed effectively during the extended period of

operation. 

3.1.2.3.7 Stainless Steel Reactor Vessel Attachment Welds 

The AMPs recommended by the GALL Report for managing the cracking due to SCC, IGSCC,

and cyclic loading for the RV attachment welds are XI.M4, “BWR Vessel Inner Diameter (ID)

Attachment Welds,” and XI.M2, “Water Chemistry,” which references EPRI Report TR-103515. 

In LRA Table 3.1.2.1, the applicant identified IGSCC as an aging effect for the stainless steel

RV attachment welds. The applicant stated the Chemistry Control Program will be used at BFN

to manage this aging effect. The Chemistry Control Program is based on EPRI Report

TR-103515-R2, (the 2000 revision of "BWR Water Chemistry Guidelines”), which was approved

by the staff in February 2000. The staff found EPRI TR-103515-R2 acceptable because the

program is based on updated industry experience and plant-specific and industry-wide

operating experience that confirms the effectiveness of the RCS chemistry program. The

applicant indicated that the vessel attachment welds program is discussed in LRA

Section B.2.1.7, “BWR Vessel ID Attachment Welds.” LRA Section B.2.1.7 references LRA

Section B.2.1.4, “ASME Section XI Subsections IWB, IWC, and IWD Inservice Inspection

Program.” The applicant’s ISI Program is an established AMP. This program has appropriate

requirements for inspecting the vessel ID attachment welds. “BWR Vessel ID Attachment

Welds” also invokes the inspection and evaluation recommendations of BWRVIP-48, “Vessel ID

Attachment Weld Inspection and Evaluation Guidelines.” SER Section 3.0.3.2.3 presents the

staff’s detailed review of this AMP. 

In RAI 3.1.2.1-1, dated December 1, 2004, the staff requested that the applicant provide the

method of implementation of the type and frequency of inspections that are specified in

BWRVIP-48, “Vessel ID Attachment Welds Inspection and Flaw Evaluation Guidelines.” These

requirements apply to jet pump raiser brace attachments, core spray piping bracket

attachments, steam dryer support and hold-down brackets, feedwater spargers, guide rods,

and surveillance sample holders. According to BWRVIP-48 Section 2.2.3, furnace-sensitized
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stainless steel vessel ID attachment welds are highly susceptible to IGSCC. The staff requested

the applicant to identify whether there are any furnace-sensitized stainless steel attachment

welds at BFN, and to provide information regarding an augmented inspection program for any

existing furnace-sensitized stainless steel attachment welds. 

In its response to RAI 3.1.2.1-1, by letter dated January 31, 2005, the applicant stated that all

the ID RV attachment welds had been inspected in accordance with BWRVIP-48 and ASME

Code Section XI ISI requirements for type and frequency. The applicant indicated that all the ID

attachment welds are furnace-sensitized; therefore, an augmented inspection program in

accordance with the requirements of BWRVIP-48 will be implemented for all these welds. The

staff found that this type of inspection would ensure that the aforementioned aging effects are

properly managed for the extended period of operation. The staff found that the implementation

of the ASME Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program,

Chemistry Control Program, and BWR ID Attachment Welds Program would be consistent with

the GALL AMPs XI.M2 and XI.M4, and is acceptable. Therefore, the staff’s concern described

in RAI 3.1.2.1-1 is resolved. SER Sections 3.0.3.2.2 and 3.0.3.1.3 respectively, present the

staff's detailed review of these AMPs. SER Sections 3.0.3.2.2 and 3.0.3.1.3, respectively,

present the staff's detailed reviews of these AMPs.

3.1.2.3.8 Reactor Vessel Nozzles and Safe Ends

The AMPs recommended by the GALL Report for managing the cracking due to SCC, IGSCC

and cyclic loading for the RV nozzles and safe ends are XI.M7, “BWR Stress Corrosion

Cracking,” and XI.M2, “Water Chemistry,” which references EPRI Report TR-103515. 

In Table 3.1.2.1 of the LRA, the applicant indicated that stainless steel materials in the RV

nozzle and safe end components, when exposed to a treated-water environment, experience

cracking due to SCC. The applicant credited the BWR Stress Corrosion Cracking Program,

ASME Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program, which is an

established AMP. In addition, the applicant indicated that AMP B.2.1.5, “Chemistry Control

Program,” is based on EPRI Report TR-103515-R2, (the 2000 revision of "BWR Water

Chemistry Guidelines”), which was approved by the staff in February 2000. 

In RAI 3.1.2.1-4(C), the staff requested that the applicant identify whether the dissimilar metal

welds of reactor vessel nozzles and safe end components have previously experienced

cracking due to SCC, IGSCC, or cyclic loading, and the extent of cracking. In its response to

RAI 3.1.2.1-4(C), by letter dated January 31, 2005, the applicant stated that, for the dissimilar

metal welds in nozzles and safe end components and piping, the requirements of ASME Code

Section XI, Subsections IWB, IWC and IWD ISI Program inspections and frequencies in

accordance with ASME Code Section XI, Table IWB-2500-1, examination category B-F would

be met. The applicant’s BWR IGSCC program inspections and frequencies are in accordance

with the normal water chemistry guidelines contained in BWRVIP-75, “BWR Vessel and

Internals Project (BWRVIP), Technical Basis for Revisions to Generic Letter 88-01 Inspection

Schedule.” The applicant implemented alternative examination requirements for IGSCC

Category A (as defined in BWRVIP-75) dissimilar metal welds under a risk-informed ISI

program (previously approved by the staff) for Units 2 and 3. The applicant stated that it

performed liquid penetrant testing (PT) and UT of the dissimilar welds in recirculation inlet and

outlet nozzle-to-safe ends, the core spray nozzle-to-safe end, pipe-to-safe ends, and the CRD

nozzle-to-cap welds for Units 2 and 3; and the examination results were acceptable. The
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applicant stated that for Unit 1 it performed PT and UT examinations on CRD nozzle-to-cap

welds, and the examination results were acceptable. The applicant stated that for Unit 1 the

RCS water chemistry would be improved in accordance with the BWR SCC Program, and the

CRD nozzle-to-safe end welds would be replaced prior to the period of extended operation.

The applicant also stated that improvements in RCS water chemistry provide mitigative

measures to preclude IGSCC in the dissimilar welds in nozzle-to-safe end, pipe-to-safe end,

and nozzle-to-cap components. The staff accepts the proposed program for stainless steel safe

ends because it conforms to the recommendations in the BWRVIP-75; however, if the safe

ends contain nickel-alloy weld metals that are susceptible to SCC, BWRVIP-75 would require

more frequent examinations than those specified for BWRVIP-75 Category A welds. In order for

the staff to determine whether the applicant had adequately implemented BWRVIP-75, the staff

requested that the applicant identify (1) the weld metal that was used for the butter,

nozzle-to-safe end welds, pipe-to-safe end welds, and nozzle-to-cap welds; (2) the grade of

stainless steel that was used as a safe end; and (3) the examination requirements for butter,

nozzle-to-safe end welds, pipe-to-safe end welds, and nozzle-to-cap welds that are more

susceptible to SCC than the BWRVIP-75 Category A welds. 

The applicant, in its response dated May 25, 2005, indicated that stainless steel weld metal was

used for the butter on the nozzle-to-safe end welds and that it would implement the inspection

guidelines that are specified in the BWRVIP-75 report for the subject welds. Since the stainless

steel weld metal is less susceptible to IGSCC than nickel-alloy weld metal, the staff concludes

that inspection requirements as specified in the BWRVIP-75 guidelines will adequately identify

aging degradation in a timely manner. The applicant further stated that it used nuclear grade

(low carbon) stainless steel for the safe end material in recirculation and core spray systems

with the exception of non-nuclear grade (i.e., standard carbon content) stainless steel safe ends

in the recirculation outlet welds in Units 2 and 3. The applicant proposed to implement the

BWRVIP-75 inspection guidelines, which are acceptable to the staff because they provide

adequate assurance in identifying cracking due to IGSCC in a timely manner for nozzle-to-safe

end welds. Since the stainless steel weld metal and nuclear grade stainless steel safe end

materials (with exception noted above) are less susceptible to IGSCC, the staff concluded that

the applicant's proposed inspection guidelines will adequately manage aging effects in the

recirculation and core spray systems. With respect to the non-nuclear grade recirculation outlet

nozzles and their welds in Units 2 and 3, the applicant stated that it will use a mechanical stress

improvement (MSIP) method to mitigate IGSCC and will use Category C inspection guidelines

to monitor the aging effects in these welds. The staff found the response acceptable because

the applicant's proposed mitigation and inspection methods for the recirculation outlet nozzle

welds will comply with the staff-approved BWRVIP-75 inspection criteria and will enable the

applicant to identify IGSCC in a timely manner. Therefore, the staff’s concern described in

RAI 3.1.2.1-4(C) is resolved.

3.1.2.3.9 Feedwater Nozzle

GALL AMP XI.M5, “BWR Feedwater Nozzle,” recommends that inspection requirements

specified in GE-NE-523-A71-0594, “Alternate BWR Feedwater Nozzle Inspection

Requirements,” be implemented for the feedwater nozzles for managing cracking due to cyclic

loading for the feedwater nozzles. 
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The applicant included the BWR Feedwater Nozzle Program for managing the aging effect

related to cracking due to cyclic loading in the feedwater nozzles at BFN. The applicant stated

that the program is consistent with GALL AMP XI.M5, with no exceptions. The applicant also

invoked the ASME Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection

Program, which is an established AMP. This program has appropriate requirements for

inspecting the feedwater nozzle components. The applicant also stated that the program

enhances the ISI specified in ASME Code Section XI with the recommendations of

GE-NE-523-A71-0594. The applicant stated that it implemented the recommendations of

NUREG-0619, “BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking,”

to mitigate feedwater nozzle cracking. The applicant also stated that the feedwater nozzles had

been modified to mitigate cracking by removing the stainless steel cladding and machining the

safe end, nozzle bore, and inner bend radius to accept improved double-piston-ring

interference-fit spargers with a forged tee design and orificed elbow discharges. The applicant

indicated in the LRA that the reactor water cleanup system return lines were routed to both

feedwater headers (except Unit 2, which is only routed to one feedwater header). The applicant

stated that changes to plant operating procedures, such as improved feedwater control, to

decrease the magnitude and frequency of temperature fluctuations had been implemented at

Units 2 and 3. The applicant also indicated that similar improvements will be implemented at

Unit 1 prior to the period of extended operation. SER Section 3.0.3.2.4 presents the staff's

detailed review of the BWR Feedwater Nozzle Program.

In RAI 3.1.2.1-4(B), dated December 1, 2004, the staff requested that the applicant provide

information on the scope and the techniques of past inspections, the results obtained, applied

mitigative methods, repairs, frequency of the inspections, and any other relevant information

related to the identification of the aging effect in the feedwater nozzles at BFN. The staff further

requested that the applicant provide information as to how the plant-specific experience related

to this aging effect impacts the attributes specified in the BWR Feedwater Nozzle Program.

In its response, by letter dated January 31, 2005, the applicant stated that it complied with the

inspection requirements specified in the BWR Feedwater Nozzle Program. The applicant stated

that it had performed UT of the feedwater nozzles and the results were acceptable, and no

repairs were performed in this system. Therefore, the applicant concluded that the

plant-specific experience related to feedwater nozzles has no impact on the attributes specified

in the BWR Feedwater Nozzle Program. The staff reviewed the applicant’s response and found

it acceptable. The applicant demonstrated that the actions taken thus far have mitigated

cracking in feedwater nozzles. Therefore, the staff’s concern described in RAI 3.1.2.1-4(B) is

resolved.

In RAI B.2.1.8-1, the staff stated that the BWR Feedwater Nozzle Program references GE

report GE-NE-523-A71-0594, which is not the staff-approved version of the report. The staff

requested that the applicant replace references to GE-NE-523-A71-0594 in LRA Sections A.1.8

and B.2.1.8 with GE-NE-523-A71-0594-A, Revision 1 which is approved by the staff. In its

response to RAI B.2.1.8-1, by letter dated January 31, 2005, the applicant stated that it will

revise the LRA to indicate correct GE report. In its response, by letter May 25, 2005, the

applicant submitted a revised version of LRA Section A.1.8, and the BWR Feedwater Nozzle

Program, which includes GE-NE-523-A71-0594-A, Revision 1. 

The staff found that the implementation of ASME Code Section XI Subsections IWB, IWC, and

IWD Inservice Inspection Program and the BWR Feedwater Nozzle Program would be
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consistent with GALL AMP XI.M5 and, therefore, is acceptable. The staff’s concern described in

RAI B.2.1.8-1 is resolved. 

3.1.2.3.10 Control Rod Drive (CRD) Return Line Nozzle

GALL AMP XI.M6, “BWR Control Rod Drive Return Line Nozzle,” recommends that enhanced

inspection requirements specified in NUREG-0619, “BWR Feedwater Nozzle and Control Rod

Drive Return Line Nozzle Cracking,” should be implemented for the CRD return line nozzles for

managing the cracking due to cyclic loading for the CRD return line nozzle. 

In LRA Table 3.1.2.1, the applicant referenced BWR CRD Return Line Nozzle Program, for

managing the aging effect in the CRD return line. The applicant stated that the program is

consistent with GALL AMP XI.M6, with no exceptions. The applicant indicated that inspections

that are specified in NUREG-0619, and ASME Code Section XI Subsections IWB, IWC, and

IWD Inservice Inspection Program, which is an established AMP. This program has appropriate

requirements for inspecting the CRD return line nozzle components. 

In RAI B.2.1.9-1, dated December 1, 2004, the staff requested the applicant to provide

information on the augmented inspection requirements that are specified in the NUREG-0619.

The CRD return line nozzle has been capped; therefore, augmented inspection of the nozzle is

not needed per NUREG-0619. The guidance in NUREG-0619 provide actions to be taken to

address cracking in these nozzles; however, the aging effects for the cap and applicable weld

are not covered in NUREG-0619. Therefore, the staff requested that the applicant address the

following issues concerning the cap and weld that provide a pressure boundary function:

In RAI B.2.1.9-1(1) the applicant was requested to describe the configuration, location and

material of construction of the capped nozzle, including the existing base material for the

nozzle, piping (if piping remnants exist) and cap material, and any welds. In its response by

letter dated January 31, 2005, the applicant stated that the configuration consists of a stainless

steel cap welded to the original carbon steel nozzle with stainless steel weld material. The safe

end and corresponding piping had been removed from the nozzle. 

In RAI B.2.1.9-1(2) the applicant was requested to describe the application of the BWRVIP-75

inspection guidelines for this weld and cap. In its response to RAI B.2.1.9-1(2), by letter dated

January 31, 2005, the applicant stated that the requirements of BWRVIP-75 are implemented

by the BWR Stress Corrosion Cracking Program. The CRD return line nozzle welds are

currently categorized (BWRVIP-75) as Category D for Unit 2 and Category C for Unit 3. The

CRD return line nozzle welds are examined by the UT technique at the frequency specified by

BWRVIP-75, Table 3-1 for normal water chemistry conditions. The applicant stated that it will

implement the BWR Stress Corrosion Cracking Program for Unit 1 prior to the period of

extended operation. 

The staff reviewed the applicant’s response and found it acceptable provided the applicant

includes information in the LRA regarding the category (per BWRVIP-75) of the subject weld in

Unit 1. 

In RAI B.2.1.9-1(3) the applicant was requested to discuss the applicability of the event at

Pilgrim (leaking weld at a capped nozzle, September 30, 2003) to BFN. The staff issued

IN 2004-08, dated April 22, 2004, which states that the cracking occurred in an alloy 82/182
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weld that had previously been repaired at the Pilgrim unit. According to IN 2004-08, the Pilgrim

CRD return line nozzle is made of SA-508, Class 2 low-alloy steel, while the CRD return line

cap is made of Alloy 600. The subject weld is fabricated with Alloy 82/182 material, and the

nozzle side of the weld is buttered with Alloy 182 material. In addition, Pilgrim had initial weld

deficiencies (lack of fusion) that required weld repair. The staff also requested that the applicant

provide any plant experience with leakage at the capped nozzle, the past inspection techniques

used, results obtained, and mitigative strategies imposed. The staff requested that the applicant

provide information as to how the plant-specific experience related to this aging effect impacts

the attributes specified in the BWR CRD Return Line Nozzle Program.

In its response, by letter dated January 31, 2005, the applicant stated that the event at Pilgrim

was determined not to be applicable. The materials of construction of the nozzle-to-cap weld at

BFN is stainless steel. The welds were completed without recordable indications. Plant

experience for Units 2 and 3 indicates that there has been no leakage at the capped CRD

return line nozzles. Ultrasonic exams have been performed with no reportable indications. The

Unit 3 capped CRD return line nozzle weld had MSIP performed to mitigate IGSCC, which

changed the frequency of inspection. The examination information related to this item is

described in RAI B.2.1.9-1(2). The plant-specific experience related to the CRD return line

nozzle has no impact on the attributes specified in the BWR CRD Return Line Nozzle Program. 

The staff reviewed the applicant’s responses and found them acceptable, in part, because the

improved RCS water chemistry and MSIP (for Unit 3) should provide adequate mitigation to

preclude IGSCC. However, the staff found that, unlike weld metal Alloy 182, austenitic stainless

steel weld metal (with a minimum delta ferrite) is less susceptible to IGSCC. In addition, low

carbon austenitic stainless steel material (L grade) is less susceptible to IGSCC than non-L

grade austenitic stainless steel. 

In order for the staff to determine whether the applicant had adequately implemented

BWRVIP-75 for the Category A CRD return line nozzle welds, the staff requested that the

applicant identify (1) the delta ferrite in the weld metal, (2) the grade of stainless steel that was

used for the CRD return line cap, (3) the examination requirements for CRD return line welds

that meet BWRVIP-75, and (4) plans to implement MSIP in Units 1 and 2. 

In its response dated May 25, 2005, the applicant indicated that stainless steel weld metal with

a minimum of eight percent delta ferrite was used for the CRD return line nozzle-to-cap welds

and that it will implement inspection guidelines as specified in the BWRVIP-75 report for the

subject welds. The applicant proposed to implement BWRVIP-75 inspection guidelines, which

are acceptable to the staff because they provide adequate assurance in identifying cracking

due to IGSCC in a timely manner for nozzle-to-safe end welds. Since the stainless steel weld

metal with eight percent delta ferrite is less susceptible to IGSCC than nickel-alloy weld metal,

the staff concluded that inspection requirements as specified in the BWRVIP-75 guidelines will

adequately identify aging degradation in a timely manner. 

The applicant further stated that it used low carbon grade stainless steel for the CRD return line

cap materials. Since the stainless weld metal and low carbon grade stainless steel CRD return

line cap materials are less susceptible to IGSCC, the staff concluded that the applicant's

proposed inspection guidelines will adequately manage the aging effect in the CRD return line

nozzle-to-cap welds. Regarding the application of MSIP as a mitigative technique to improve

resistance to IGSCC, the applicant stated that it will use the following plan to implement MSIP
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for CRD return line nozzle-to-cap welds: (1) MSIP and BWRVIP-75 inspection guidelines will be

implemented for Unit 1 welds prior to restart; (2) no MSIP will be used for Unit 2 welds;

however, BWRVIP-75, Category D inspection guidelines will be implemented for these welds;

and, (3) MSIP was used in Unit 3 welds and the BWRVIP-75, Category C inspection guidelines

will be use for these welds. The staff found the response acceptable because the applicant's

proposed mitigation and inspection methods for the CRD return line nozzle-to-cap welds will

comply with the staff approved BWRVIP-75 inspection criteria, and will enable the applicant to

identify IGSCC cracking in a timely manner. Therefore, the staff’s concern described in

RAI B.2.1.9-1 is resolved.

The staff found that the implementation of the BWR CRD Return Line Nozzle Program and

ASME Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program for the

CRD return lines would be consistent with the GALL AMP XI.M6, and is, therefore, acceptable.

SER Section 3.0.3.1.5 presents the staff's detailed review of this AMP.

3.1.2.3.11 Reactor Vessel Penetrations

AMPs recommended by the GALL Report for managing cracking due to IGSCC for the RV

penetrations are XI.M8, “BWR Penetration,” and XI.M2, “Water Chemistry.” The GALL AMPs

for the RV penetrations include implementation of guidelines specified in BWRVIP-49,

“Instrumentation Penetration Inspection and Flaw Evaluation Guidelines,” and reactor coolant

water chemistry in accordance with the guidelines of BWRVIP-29, “BWR Water Chemistry

Guidelines,” (EPRI TR-103515). In addition to these requirements, the GALL program XI.M8,

“BWR Penetration,” recommends that inspection and flaw evaluation guidelines specified in

BWRVIP-27, “BWR Standby Liquid Control System/Core Plate delta P Inspection and Flaw

Evaluation Guidelines,” should be implemented for the RV penetrations.

In LRA Table 3.1.2.1, the applicant indicated that nickel-alloy and stainless steel materials in

the RV penetration components, when exposed to a treated-water environment, experience

cracking due to SCC. The applicant included the BWR Reactor Penetration Program for

managing the aging effect related to cracking due to SCC in the RV penetrations. The applicant

stated that this AMP is consistent with GALL AMP XI.M8 with no exceptions. The BWR Reactor

Penetration Program recommends the implementation of the staff’s approved versions of

BWRVIP-27, BWRVIP-49, and ASME Section XI Subsections IWB, IWC, and IWD Inservice

Inspection Program, which is an established AMP. This program has appropriate requirements

for inspecting the BWR RV penetrations (i.e., category B-E for pressure-retaining partial

penetration welds; category B-D for full penetration nozzle-to-vessel welds; category B-F for

pressure retaining dissimilar metal nozzle-to-safe end welds; and category B-J for similar metal

nozzle-to-safe end welds). The extent and schedule of inspection prescribed by the ASME

Code Section XI ISI Program is designed to maintain structural integrity and ensure that aging

effects will be discovered and repaired before the loss of intended function of the component.

These inspections can reveal crack initiation and growth and leakage of coolant due to SCC. In

addition, the applicant indicated that the Chemistry Control Program, which is based on EPRI

Report TR-103515-R2, (the 2000 revision of "BWR Water Chemistry Guidelines”), will be

applied. The staff found the EPRI TR-103515-R2 acceptable because the program is based on

updated industry experience, and plant-specific and industry-wide operating experience confirm

the effectiveness of the RCS chemistry program.
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In RAI 3.1.2.1-5(B), dated December 1, 2005, the staff requested that the applicant provide any

previous plant-specific experience regarding the cracking due to SCC and IGSCC in dissimilar

metal welds of RV penetrations, and the method and frequency of inspection for managing this

aging effect. In its response to RAI 3.1.2.1-5(B), by letter dated January 31, 2005, the applicant

stated that the following penetrations are inspected during the ASME Code Section XI,

IWB-2500, Code Category B-P system leakage test during each refuel outage: (1) CRD stub

tubes; (2) instrumentation nozzle/nozzle safe ends; (3) standby liquid control nozzles; (4) jet

pump instrumentation nozzles; (5) drain line nozzles; and (6) in-core monitor housing

penetrations.

The applicant also stated that no cracking of the dissimilar metal penetration welds have been

identified thus far at BFN. In addition, the applicant stated that the improvements in the RCS

Chemistry Control Program would mitigate the IGSCC of the RV penetration welds. The

applicant stated that the plant-specific experience related to the RV penetrations has no impact

on the attributes of the BWR Penetrations Program. 

The staff reviewed the response to the RAI 3.1.2.1-5(B) and found it acceptable.

Implementation of the improved water chemistry and ISI programs as specified in the BWR

Penetrations Program, would enable the applicant to manage the aging effect due to IGSCC

effectively during the extended period of operation, and would be consistent with GALL AMPs

XI.M8 and XI.M2. Therefore, the staff’s concern in RAI 3.2.1.2-5(B) is resolved. 

3.1.2.1.12 Reactor Head Closure Studs

GALL AMP XI.M3, “Reactor Head Closure Studs,” recommends that preventive actions

specified in RG 1.65, “Materials and Inspections for RV Closure Studs,” should be implemented

for managing the cracking due to SCC for the reactor head closure studs. SER

Section 3.0.3.1.4 present the staff's detailed review of this AMP.

In LRA Table 3.1.2.1, the applicant indicates that the Reactor Head Closure Studs Program,

which is consistent with GALL AMP XI.M3, will be implemented to monitor the aging effect due

to SCC of the reactor head closure studs. 

The applicant stated that the following requirements will be implemented for the Reactor Head

Closure Studs Program.

 • ISI in conformance with the requirements of the ASME Code Section XI, Subsection

IWB, Table IWB 2500-1.

 • Mitigation of cracking is achieved by complying with the requirements of Regulatory

Guide 1.65, “Materials and Inspections for RV Closure Studs.” The applicant stated that

approved lubricants will be used to minimize the potential for cracking of the

non-metal-plated reactor head closure studs.

The applicant stated that industry experience indicated that SCC occurred in metal-plated BWR

reactor head closure studs. The applicant stated that there are no metal-plated reactor head

closure studs in use, and approved lubricants are used to prevent seized studs or nuts. The

applicant claimed that with the lack of metal plating and preventive use of approved lubricants,
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Reactor Head Closure Studs Program has been effective in reducing the probability of SCC of

the reactor head closure studs. 

The applicant concluded in its LRA that the Reactor Head Closure Studs Program provides

reasonable assurance that aging effects due to cracking in the reactor head closure studs is

adequately managed so that their intended functions, consistent with the CLB, are maintained

during the period of extended operation.

The staff concluded that the reactor head closure studs are less likely to experience aging

effects related to SCC, because these closure studs are not metal plated and approved

lubricants are used for their maintenance. The staff found the implementation of Reactor Head

Closure Studs Program is acceptable. Presence of aging effects can be identified by frequent

inspections dictated by the Reactor Head Closure Studs Program. In addition, compliance with

RG 1.65 requirements provides adequate assurance in maintaining the integrity of the RV

studs. The staff concluded that implementation of the aforementioned requirements provides

assurance that the aging effect associated with SCC is adequately managed by the applicant.

3.1.2.3.13 Bolting for Reactor Vessel Vents and Drains

In RAI 3.1.2.3-1(A), dated December 1, 2004, the staff stated that GALL AMP XI.M18, “Bolting

Integrity Program,” is recommended for managing the aging effects for the bolting in the RV

vents and drains. In LRA Table 3.1.2.3, the applicant indicates that the Bolting Integrity

Program, which is consistent with GALL AMP XI.M18, will be implemented to monitor the aging

effects of the bolting in RV vents and drains. LRA Table 3.1.2.3 and the Bolting Integrity

Program do not identify SCC as an aging effect for these bolts. Therefore, the staff requested

that the applicant address the aging effect due to SCC in the bolts of the RV vents and drains.

In its response, by letter January 31, 2005, the applicant stated that SCC can occur in high 

yield strength (greater than 150 ksi) bolted closures in BWRs when they are exposed to a

corrosive environment, typically attributed to leakage of pressure boundary joints or exposure to

wetted ambient environments or due to the use of thread lubricant containing molybdenum

disulfide (MoS2). High yield strength, heat-treated alloy steel bolting materials are not specified

for flanged connections. High strength bolting in vendor-supplied equipment has not been

identified for mechanical components (such as pump casing studs or valve body/bonnet studs)

where the material specifications are available. The applicant stated that a review of the BFN

operating experience did not identify any instances where mechanical component failure was

attributable to SCC of high strength bolting. Therefore, loss of bolting function due to SCC of

bolted joints of mechanical equipment is not expected and no aging management is required for

the period of extended operation. Since there are no high-yield strength bolts in the RV vents

and drains at BFN, the staff concluded that no AMP is required to monitor the aging effect due

to SCC in bolting in reactor vents and drains. Therefore the staff’s concern described in

RAI 3.1.2.3-1(A) is resolved.

3.1.2.3.14 Loss of Materials in Low Alloy Steel or Carbon Steel Reactor Vessel Components

that are exposed Externally to Inside (Atmospheric) Environments

The applicant identified in Table 3.1.2.1 of the LRA no aging effects, but included references

related to the GALL Report Volume 2, Table IV. A1 for carbon and low-alloy steel materials of

the following RV components exposed externally to inside (atmospheric) environments.
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 • other external attachment welds to the reactor vessel

 • reactor vessel heads, flanges, and shell

 • reactor vessel nozzles

 • reactor vessel nozzles and safe ends

 • reactor vessel penetrations

 • reactor vessel internals CRD housing

 • bolting in reactor vessel vents, drains and the recirculation system

The staff reviewed the applicant's evaluation to determine whether it adequately addressed the

issue of uniform corrosion of the carbon and low-alloy steel RV components when they are

exposed externally to inside (atmospheric) environments. According to SRP-LR

Section 3.4.2.2.4, loss of material due to general corrosion can occur on the external surfaces

of carbon and low-alloy steel RV components exposed to operating temperature less than

212 °F. Since the operating temperature of the BWR vessel is greater than 212 °F, the loss of

material due to general corrosion is not likely to occur in carbon and low-alloy steel RV

components. In addition, the external surface of the carbon and low-alloy steel RV components

are exposed to inside (atmospheric) environment that does not contain any aggressive ions

resulting in loss of material due to corrosion. 

In RAIs 3.1.2-1, 3.1.2.1-4(A), and 3.1.2.1-5(A), dated December 1, 2004, the staff requested

that the applicant provide an explanation as to why the loss of material due to corrosion is not

considered as an aging effect for carbon and low-alloy steel vessel attachment welds; vessel

heads, flanges, and shells; vessel nozzles and safe ends; vessel penetrations; and bolting in

vessel vents, and drains for Unit 1.

In its response to RAIs 3.1.2-1, 3.1.2.1-4(A), and 3.1.2.1-5(A), by letter dated January 31, 2005,

the applicant indicated that for Unit 1 degradation due to corrosion of all the aforementioned RV

components would be verified under the Unit 1 restart program. The applicant also stated that it

will perform further inspection of the subject RV components followed by replacement (if

required) of the degraded components that are identified by this inspection. The staff found that

the applicant's implementation of inspection and replacement programs (when necessary)

provides reasonable assurance that the aging effect due to corrosion of carbon and low-alloy

steel penetrations for Unit 1 will be adequately managed so that the intended function(s) will be

maintained with the CLB for the period of extended operation. 

Therefore, the staff found that these components do not experience any of the aforementioned

aging effects when they are exposed externally to an inside (atmospheric) environment. The

staff concluded that the applicant's determination to exclude these aging effects in LRA

Table 3.1.2.1 for the aforementioned RV components is acceptable. Therefore the staff’s

concern described in RAIs 3.1.2-1, 3.1.2.1-4(A), and 3.1.2.1-5(A) is resolved.

3.1.2.3.15 Distortion/plastic deformation due to stress relaxation and loss of material due to

mechanical wear - Reactor head closure studs and nuts; bolting in RV vents, drains and the

recirculation system

In LRA Table 3.1.2.1, the applicant addressed distortion and plastic deformation due to stress

relaxation and loss of material due to mechanical wear as aging effects in reactor head closure

studs and nuts. The applicant proposed to use the Reactor Head Closure Stud Program, which,

in turn, invokes the requirements of GALL AMP XI.M3 to monitor this aging effect. The
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applicant reiterated that the aforementioned aging effect is adequately managed by the ASME

Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program. 

In RAI 3.1.2.1-2, dated December 1, 2004, the staff requested that the applicant identify any

plant-specific aging effects due to distortion/plastic deformation resulting from stress relaxation

and loss of material due to mechanical wear for the reactor closure studs and nuts. 

In its response to RAI 3.1.2.1-2, by letter dated January 31, 2005, the applicant stated that it

has not identified any RV closure stud or nut degradation resulting in distortion/plastic

deformation due to stress relaxation or loss of material due to mechanical wear. The applicant

also stated that no RV closure studs or nuts have been replaced for this reason. Two studs

were replaced in Unit 2 during the Unit 2 Cycle 4 refueling outage. These were replaced

because of physical thread damage. From discussions with plant personnel present at that

time, this damage was the result of impacts during handling and refueling operations, and not

the result of inservice stress or wear. Based on this, the applicant stated that there was no

impact on the attributes specified in the Reactor Head Closure Studs Program. The staff

concluded that the proposed ASME Code Section XI Subsections IWB, IWC, and IWD

Inservice Inspection Program and Reactor Head Closure Studs Program for the reactor closure

studs are consistent with GALL AMP XI.M3, and the subject aging effects are adequately

managed by the applicant for the period of extended operation. The staff finds this response

acceptable, and its concern related to RAI 3.1.2.1-2 is resolved.

In LRA Table 3.1.2.3, the applicant addressed loss of bolting function due to wear as an aging

effect in RV vents and drains and the recirculation system. The applicant proposed to use the

Bolting Integrity Program for monitoring this aging effect, which in turn, invokes the

requirements of GALL AMP XI.M18. GALL AMP XI.M18 requires application of ASME Code

Section XI Subsection IWB, Table IWB 2500-1 for the bolts that are included in the ASME Code

Section XI Program to monitor this aging effect. In addition, the aging effects for the SR bolting

are mitigated by NUREG-1339, "Resolution of Generic Safety Issue 29: Bolting Degradation

Failure in Nuclear Power Plants." For bolts that are not included in the ASME Section XI

program, the applicant proposed to use the Systems Monitoring Program. The staff concluded

that the implementation of the Bolting Integrity Program and Systems Monitoring Program, and

compliance with GALL AMP XI.18 will provide reasonable assurance that loss of bolting

function due to wear in RV vents and drains and the recirculation system is adequately

managed so that their intended functions, consistent with the CLB, are maintained during the

period of extended operation. 

In RAI 3.1.2.3-1(B), dated December 1, 2004, the staff requested that the applicant provide

information on the previous plant-specific experience of loss of bolting function due to wear in

the RV vents and drains system. The staff also requested that the applicant provide information

on the scope and the techniques of the past inspections, the results obtained, applied mitigative

methods, repairs, frequency of the inspections and any other relevant information related to the

identification of this aging effect of the bolts in RV vents and drains. In addition, the staff

requested that the applicant provide information as to how the plant-specific experience related

to this aging effect impacts the attributes specified in the Bolting Integrity Program. 

In its response to RAI 3.1.2.3-1(B), by letter dated January 31, 2005, the applicant stated that

aging effect due to wear was conservatively identified to be an aging effect that requires

management for the period of extended operation for pressure boundary bolting in RV vents
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and drains. The applicant also stated that these bolts are inspected in accordance with ASME

Code Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program inspection

requirements, and the Systems Monitoring Program. The Systems Monitoring Program

performs an entire system inspection once per fuel cycle and includes visual inspections for

evidence of material condition and bolting torque relaxation. The Systems Monitoring Program

documents failures in either the maintenance work order or plant corrective action program, as

appropriate. The applicant indicated that so far, no instances of RV vents and drains bolting

failure due to wear have been identified. The staff finds this response acceptable, and its

concern related to RAI 3.1.2.3-1(B) is resolved. 

In RAI 3.1.2.4-1(A), dated December 1, 2004, the staff requested that the applicant provide

information on the previous plant-specific experience of loss of bolting function due to stress

relaxation in the RV recirculation system. The staff also requested that the applicant provide

information on the scope and the techniques of the past inspections, the results obtained,

applied mitigative methods, repairs, frequency of the inspections, and any other relevant

information related to the identification of this aging effect of the RV recirculation system bolts.

In addition, the staff requested that the applicant provide information as to how the

plant-specific experience related to this aging effect impacts the attributes specified in the

Bolting Integrity Program. 

In its response to RAI 3.1.2.4-1(A), by letter dated January 31, 2005, the applicant stated that it

inspected the reactor water recirculation pump closure bolting in accordance with the

requirements of ASME Section XI, Table IWB-2500-1, Category B-G-1. The inspection

methods included visual examination and UT, and the results were acceptable. Therefore, the

applicant did not perform any repair on the reactor recirculation pump closure bolting. The

applicant stated that implementation of AMP B.2.1.16, and compliance with the

recommendations of NUREG-1339 and EPRI NP-5769 provide adequate assurance that the

aging effect due to stress relaxation in the bolting of the RV recirculation system is effectively

managed for the extended period of operation. 

The staff reviewed the applicant's responses to the above RAIs, and concluded that the

implementation of ASME Code Section XI Subsections IWB, IWC, and IWD Inservice

Inspection Program, Bolting Integrity Program, and Systems Monitoring Program is consistent

with GALL AMP XI.M18 and the subject aging effects for bolting in RV vents, drains and the

recirculation system are adequately managed at BFN. Therefore, the staff’s concerns described

in the above RAIs are resolved.

3.1.2.3.16 Crack Initiation and Growth Due to Stress Corrosion Cracking, Fatigue and Cyclic

Loading

The staff's evaluation of the aging effect due to cyclic loading and fatigue is discussed in SER

Section 3.1.2.2.4.

AMPs recommended by the GALL Report for managing cracking due to IGSCC for the RV

internal components are XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC,

and IWD," XI.M2, "Water Chemistry," and XI.M9, "BWR Vessel Internals." AMP XI.M9 includes

implementation of guidelines specified in the staff-approved BWRVIP documents for a given

component.
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In LRA Table 3.1.2.2, the applicant identified SCC as an aging effect in (1) RVIs core shroud

and core plate, (2) RVIs core spray and feedwater spargers, (3) RVIs control rod housing and

dry tubes and guide tubes, (4) RVIs jet pump assemblies, and (5) RVIs top guide.

In LRA Table 3.1.2.2, the applicant stated that the aging effect due to SCC in the

aforementioned components is managed by (1) Boiling Water Reactor Vessel Internals

Program, (2) ASME Code Section XI Subsections IWB, IWC, and IWD ISI Program, and (3) the

Chemistry Control Program. The applicant stated that continued implementation of these AMPs

provides reasonable assurance that the aging effects due to SCC, fatigue, and cyclic loading

will be managed so that the systems and components within the scope of this program will

continue to perform their intended functions consistent with the CLB for the period of extended

operation. 

In RAI 3.1.2.1-6(A), dated December 1, 2004, the staff requested that the applicant provide

information on the scope and the techniques of the past inspections, the results obtained,

applied mitigative methods, repairs, and frequency of the inspections of the AHCs. In response

to RAI 3.1.2.1-6(A), by letter dated January 31, 2005, the applicant stated that the Unit 1 core

shroud AHCs currently have indications of cracking and will be replaced with a bolted design in

lieu of a welded design prior to Unit 1 restart. Units 2 and 3 AHCs have no reportable

indications. In addition, the applicant stated that the improvements in the RCS Chemistry

Control Program would enable the mitigation of IGSCC of the AHCs. 

In RAI B.2.1.12-1(C), dated December 1, 2004, the staff requested the applicant to provide

information regarding any prior augmented UT for the AHCs as required by GALL Report

Section IV-B1.1.4. In its response, by letter January 31, 2005, the applicant stated that the

AHCs are examined in accordance with GE SIL No. 462, Revision 1. The GE SIL allows for

inspection of the AHCs either by UT or top-surface visual (VT-1) inspection. The applicant has

always used the UT technique, as this methodology provides superior flaw detection and allows

for a longer reinspection interval. Due to tooling constraints, a top-surface enhanced VT-1

(EVT-1), which is superior to the visual examination guidelines of GE SIL No. 462, was

performed for Unit 3 AHCs. The applicant stated that prior to the period of extended operation,

it will implement visual inspection of the AHCs and inspection of the AHC welds by UT, unless

tooling constraints prohibit performance of a UT. In the event tooling constraints prohibit

inspection by UT, the inspection will be performed by EVT-1. The applicant proposed to inspect

the AHCs utilizing the BWR Vessel Internals Program rather than the ASME Code Section XI

ISI Program currently specified in the GALL Report. SER Section 3.0.3.2.7 presents the staff's

detailed review of this AMP.

Since the GALL Report Section IV-B1.1.4 requires UT of AHC welds, the staff requested that

the applicant revise BWR Vessel Internals Program and LRA Section A.1.12 to include UT for

Units 2 and 3 AHC welds to the maximum extent possible. The staff requested that the

applicant identify its previous experience on the extent to which UT was performed on the AHC

welds.

The applicant, in its response dated May 25, 2005, stated that Unit 1 welded AHCs will be

replaced by a bolted design thereby eliminating the need for UT. However, Units 2 and 3 will

still have welded AHCs and they require UT examination. The applicant stated that UT

examinations had been performed on the AHC welds in Units 2 and 3, and thus far no

indications had been identified. The applicant stated that it will perform UT on AHC welds at
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Units 2 and 3 unless tooling constrains prohibit inspections by UT, in which case it will perform

EVT-1 examinations. The applicant stated that it will obtain prior approval from the staff if

EVT-1 is substituted for UT examination of the welded AHCs at Units 2 and 3. The staff found

this response acceptable, because previous UT examinations of AHC welds at Units 2 and 3

indicated no evidence of cracks and as such there is no evidence of active degradation in the

AHC welds at Units 2 and 3. Additionally, the applicant stated that it will perform UT

examinations on accessible AHC welds and EVT-1 examinations in inaccessible AHC welds,

and these examinations will adequately identify the cracks in AHC welds at Units 2 and 3. The

staff accepts the applicant's response as a commitment and concludes that it should be

included in the commitment tables in lieu of LRA Section A.1.12. Based on its review, the staff’s

concerns described in RAIs 3.1.2.1-.6(A), and B-2.1.12-1(C) are resolved. 

In RAI 3.1.2.1-6(B), dated December 1, 2004, the staff requested that the applicant provide an

explanation for excluding the aging effect due to IASCC for the core shroud and core plate. In

its response to RAI 3.1.2.1-6(B), by letter dated January 31, 2005, the applicant stated that it

will include the aging effect due to IASCC in LRA Table 3.1.2.2, and this aging effect is

managed by implementing the ASME Code Section XI Subsections IWB, IWC, and IWD and

Chemistry Control Programs. The BWR Vessel Internals Program invokes inspection

requirements specified in BWRVIP-76, "Boiling Water Reactor Core Shroud Inspection and

Flaw Evaluation Guidelines," which is currently being reviewed by the staff. In the BWR Vessel

Internals Program, the applicant stated that it will comply with all the requirements that will be

specified in the staff's SER on the BWRVIP-76 report, and will complete all the license renewal

applicant action items of this SER when it is issued. The staff reviewed the response and found

it acceptable because the implementation of the inspections as mandated by the ASME Code

Section XI Subsections IWB, IWC, and IWD Program and BWRVIP-76 (pending staff's

approval) should identify any cracking due to IASCC in a timely manner so that the intended

function of the subject component is maintained during the extended period of operation.

In RAI 3.1.2.1-6(C), dated December 1, 2004, the staff requested the applicant to provide

information regarding the plant-specific experience related to IGSCC cracking of the stainless

steel and nickel-alloy components in the core shroud and AHCs, and the effective AMP that will

be implemented on these systems. In its response to RAI 3.1.2.1-6(C), by letter dated

January 31, 2005, the applicant stated that indications have been reported in Unit 1 core shroud

welds H-1, H-2, H-3, H-4, and H-5. Core shroud welds H-6 and H-7 have not been examined

due to interference from vibration sensing lines. These welds will be UT examined prior to

Unit 1 restart. Indications have been reported in Unit 2 core shroud welds H-1, H-2, H-3, H-5,

H-6, and H-7. Indications have been reported in Unit 3 core shroud welds H-1, H-2, H-3, H-4,

H-5, and H-7. The applicant stated that the aging effect due to IGSCC is managed by AMPs

BWR Vessel Internals, ASME Code Section XI Subsections IWB, IWC, and IWD, and

Chemistry Control Programs. The staff finds this response acceptable, and its concern related

to RAI 3.1.2.1-6(C) is resolved.

In RAI 3.1.2.1-6(D), dated December 1, 2004, the staff requested the applicant to address the

plant-specific experience regarding sudden increases in RCS water conductivity due to a leak in

condensate and/or reactor water clean up systems, and the impact of these sudden

conductivity excursions on the IGSCC of core shroud welds. In its response to RAI 3.1.2.1-6(D),

by letter dated January 31, 2005, the applicant stated that there had been no increase in

conductivity in RCS water due to leaks in condensate and/or reactor water clean up systems in

the previous five years. The staff found that in the absence of any increase in RCS water
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conductivity, and with the addition of hydrogen/noble metal to the RCS water, the growth of

existing IGSCC in the core shroud welds will be mitigated. The staff finds this response

acceptable, and its concern related to RAI 3.1.2.1-6(D) is resolved

In RAI 3.1.2.1-6(E), dated December 1, 2004, the staff requested the applicant to provide

information on verification methods to monitor the effectiveness of the HWC/NMCA program,

the methodology of ensuring hydrogen availability in the core shroud region, monitoring of its

availability with ECP probes, and the validity of using secondary parameters (e.g., main

steam/feedwater oxygen levels) to assess the hydrogen availability at core shroud welds. In its

response to RAI 3.1.2.1-6 (E), by letter dated January 31, 2005, the applicant stated that an

NMCA with a conservative hydrogen/oxygen (H2/O2) molar ratio is maintained to ensure

hydrogen availability in the core shroud region. The applicant stated that it would not utilize ECP

probes; therefore, alternate means are used to monitor ECP. The applicant proposed to use

reactor water H2/O2 molar ratio of greater than four for power operation. The staff reviewed the

response and found it acceptable because, in the absence of ECP measurements, maintaining

a H2/O2 molar ratio of greater than four would be effective in mitigating IGSCC in core shroud

welds. 

The staff found that the implementation of the improved water chemistry and ISI programs in

conjunction with the inspection guidelines specified in the BWRVIP-76 report (pending staff's

approval) would enable the applicant to manage the aging effect due to IGSCC effectively

during the extended period of operation, and would be consistent with GALL AMPs XI.M1,

XI.M2 and XI.M9. 

In RAI 3.1.2.2-7(A), dated December 1, 2004, the staff requested the applicant to provide an

explanation for excluding the aging effect due to IASCC for the core spray spargers and piping

in LRA Table 3.1.2.2. According to GALL Report Section IV B1.3-a, an AMP is required for

monitoring IASCC in core spray spargers and piping. In its response, by letter dated

January 31, 2005, the applicant stated that it will include aging effect due to IASCC in LRA

Table 3.1.2.2, and this aging effect is managed by implementing the ASME Code Section XI

Subsections IWB, IWC, and IWD, BWR Vessel Internals, and Chemistry Control Programs. 

In RAI 3.1.2.2-7(B), dated December 1, 2004, the staff requested the applicant to provide

information on the type and extent of inspections to identify IGSCC and the mitigation

techniques for core spray piping and spargers at Units 2 and 3. In its response, by letter dated

January 31, 2005, the applicant stated that the inspections (the type and extent) were

performed in accordance with the requirements of BWRVIP-18, "BWR Core Spray Internals

Inspection and Flaw Evaluation Guidelines," and ASME Code Section XI Subsections IWB,

IWC, and IWD, BWR Vessel Internals. The applicant stated that thus far no cracking was

identified in the core spray system with the following exceptions. The applicant stated that it

identified cracking in the elbow-to-shroud pipe and collar-to-shroud welds in downcomer "C" in

Unit 3, which was subsequently replaced with a bolted piping assembly as a corrective action.

The applicant identified cracking in Unit 3 core spray sparger adjacent to the T-boxes, which

was repaired by welded brackets at both T-boxes. The applicant indicated that mitigation of

IGSCC in core spray piping and spargers would be achieved by the implementation of

HWC/NMCA. 

The staff, after reviewing BWRVIP-18, concluded that core spray piping and spargers are not

adequately protected by the HWC/NMCA. However, implementation of the inspection
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guidelines as required by BWRVIP-18 and ASME Code Section XI Subsections IWB, IWC, and

IWD, will inadequately identify cracking in a timely manner. Therefore, the staff concluded that

the type and extent of inspections mandated by BWRVIP-18 and the ISI Program should

adequately identify cracking (without taking any credit for HWC/NMCA) in core spray piping and

spargers in a timely manner so that their intended function is maintained during the period of

extended operation. Since the applicant is implementing the ASME Code Section XI

Subsections IWB, IWC, and IWD, BWR Vessel Internals Program and Chemistry Control

Program, which are consistent with the GALL AMP XI.M9, the staff found that the applicant had

demonstrated that the effects of aging in core spray piping and spargers will be adequately

managed for the period of extended operation.

In RAI 3.1.2.2-8(A), dated December 1, 2004, the staff requested the applicant to provide an

explanation for excluding the aging effect due to IASCC for the CRD housing dry tubes and

guide tubes in Table 3.1.2.2 of the LRA. In its response, by letter dated January 31, 2005, the

applicant stated that it will include aging effect due to IASCC in LRA Table 3.1.2.2, and that this

aging effect is managed by implementing ASME Code Section XI Subsections IWB, IWC, and

IWD, BWR Vessel Internals Program and Chemistry Control Program. BWR Vessel Internals

Program in turn invokes inspection requirements specified in BWRVIP-47, "Boiling Water

Reactor Lower Plenum Inspection and Flaw Evaluation Guidelines." The staff reviewed the

response and found it acceptable because the implementation of the inspections as mandated

by the ASME Code Section XI Subsections IWB, IWC, and IWD Program and BWRVIP-47

should identify any cracking due to IASCC in a timely manner so that the intended function of

the subject component is maintained during the period of extended operation. Therefore, the

staff’s concern described in RAI 3.1.2.2-8(A) is resolved.

In RAI 3.1.2.2-8(B), dated December 1, 2004, the staff requested the applicant to provide

information regarding the past plant-specific experience related to IGSCC in the nickel-alloy

housing guide tubes and dry tubes and their subsequent replacement with crack-resistant

materials at Units 2 and 3. The staff also requested that the applicant provide its plan for the

replacement of Unit 1 dry tubes and guide tubes. In its response, by letter dated January 31,

2005, the applicant stated that all 12 Unit 2 and 3 radiation monitor dry tubes had been

replaced with a crevice-free design in the plunger area. Additionally, the material in the plunger

area had been changed from 304 stainless steel to 304L stainless steel, making the new dry

tubes less susceptible to IGSCC. 

The applicant in its response dated May 25, 2005, stated that it will replace Unit 1 dry tubes

prior to restart. However, the applicant must commit to replace all Unit 1 dry tubes prior to

restart. This commitment would be contained in a tracking process either for Unit 1 restart or

license renewal.

Based on its assessment of Unit 2 Cycle 7 refueling outage and Unit 3 prior to its restart in

1995 (see RAI response dated December 1, 2004), the applicant found that the plant-specific

experience related to the dry tubes has no impact on the attributes specified in the BWR Vessel

Internals Program and BWRVIP-47. The staff reviewed the applicant's response and concluded

that the replacement of the dry tubes material that is more IGSCC resistant combined with new

crevice-free design provides adequate assurance that the aging effect due to IGSCC in these

components is adequately managed for the period of extended operation. The staff found this

response acceptable, and its concern related to RAI 3.1.2.2-8(B) is resolved.
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In RAI 3.1.2.2-8(C), dated December 1, 2004, the staff requested that the applicant provide

information regarding the plant-specific experience related to IGSCC in furnace-sensitized

stainless steel stub tubes (if any) at BFN, and the method and frequency of inspections to

identify this aging effect. In its response to RAI 3.1.2.2-8(C), by letter dated January 31, 2005,

the applicant stated that BFN does not have furnace-sensitized stainless steel stub tubes and

the stub tubes are manufactured from a nickel alloy. The applicant also stated that there have

been no repairs associated with the CRD stub tubes, and improvements in the BWR Chemistry

Control Program help mitigate aging and degradation of the lower plenum components. Based

on this assessment, the applicant stated that the plant-specific experience related to the stub

tubes has no impact on the attributes specified in the BWR Vessel Internals Program and

BWRVIP-47 as no degradation has been identified. The staff concurred with the applicant's

response and found it acceptable. Therefore, the staff’s concern described in RAI 3.1.2.2-8(C)

is resolved.

In RAI 3.1.2.2-8(D), dated December 1, 2004, the staff requested that the applicant provide

information regarding the plant-specific experience related to IGSCC cracking in nickel-alloy

weld metals that were used for the CRD stub tubes, and the method and frequency of

inspections to identify this aging effect. In its response, by letter dated January 31, 2005, the

applicant identified the following locations associated with the lower plenum that have

nickel-alloy weld metal.

 • CRD housing-to-stub tube weld

 • CRD stub tube-to-RV weld

 • In-core housing-to-RV lower head penetration weld

 • In-core guide tube-to-in-core housing weld

The applicant stated that its AMR does not identify an inspection of the listed welds, and no

cracking has been identified at BFN for the listed nickel-alloy welds. The applicant also stated

that the improvements in the BWR Chemistry Control Program help mitigate aging and

degradation of the lower plenum components. Therefore, the applicant claimed that the

plant-specific experience related to the lower plenum nickel-alloy welds has no impact on the

attributes specified in the BWR Vessel Internals Program and BWRVIP-47 as no degradation

has been identified. The staff found the applicant's response acceptable.

The staff concluded that the implementation of the inspection requirements as mandated by the

ISI program and the staff's approved BWRVIP-47 report will provide reasonable assurance that

IGSCC in the lower plenum welds can be identified in a timely manner, so that the intended

function of the subject component is maintained during the period of extended operation. 

In RAI 3.1.2.2-10, dated December 1, 2004, the staff requested the applicant to provide an

explanation for excluding the aging effect due to IASCC for the top guide. The applicant in its

response indicated that it will include IASCC as an aging effect for the top guide in LRA

Table 3.1.2.2. SER Section 4.7.6 on TLAA discusses the impact of IASCC and multiple failures

of the top guide grid beams at BFN.

The staff requested that the applicant in its LRA provide the AMR for the jet pump thermal

sleeve welds in order to comply with the requirement specified in BWRVIP-41, Appendix A,

paragraph A.2, "BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines," report.

In its response dated May 25, 2005, the applicant stated that it implemented the Chemistry
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Control Program and the BWR Vessel Internals Program to monitor the aging effects in jet

pump thermal sleeve welds. The applicant stated that the inspection requirements of the

BWRVIP-41 report are included in the BWR Vessel Internals Program; and that they will

adequately manage aging degradation due to fatigue in jet pump thermal sleeve welds. The

applicant further stated that the jet pump thermal sleeve welds are not inspectible with existing

techniques; however, it will implement an inspection technique that is currently being developed

by the BWRVIP, when available. The staff found this response acceptable because the

applicant has committed to implement BWRVIP-41 and the BWRVIP is currently developing an

inspection technique that will enable the applicant to adequately identify cracking due to fatigue

or IGSCC. Therefore, the staff’s concern described in RAI 3.1.2.2-10 is resolved.

3.1.2.3.17 Change in Material Properties and Reduction in Fracture Toughness Due to

Thermal Aging and Neutron Irradiation Embrittlement

The AMP recommended by the GALL Report for managing the susceptibility of CASS

components to thermal aging embrittlement and neutron irradiation embrittlement is AMP

XI.M13, “Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless

Steel (CASS).”

In LRA Table 3.1.2.2, the applicant stated that the aging effects due to change in material

properties as a result of thermal and neutron embrittlement of the CASS RVIs jet pump

assemblies will be managed by the Thermal Aging and Neutron Irradiation Embrittlement of

Cast Austenitic Stainless Steel Program, ASME Code Section XI Subsections IWB, IWC, and

IWD Inservice Inspection Program, Boiling Water Reactor Vessel Internals Program, and the

inspection guidelines that are provided in the BWRVIP-41, "BWR Jet Pump Assembly

Inspection and Flaw evaluation guidelines," which have been approved by the staff. The

implementation of these programs is consistent with the GALL AMP XI.M13, and the applicant

did not take any exception to the requirements of the GALL Report. The applicant incorporated

a screening criterion that establishes susceptibility of CASS components to thermal aging

based on casting method, molybdenum content, and ferrite percentage. 

In RAI 3.1.2.2-9, dated December 1, 2004, the staff requested the applicant to provide

information on the existing (if any) CASS jet pump components, the type of casting,

composition of the CASS (i.e., molybdenum content and delta ferrite values), previous

plant-specific experience regarding the cracked components with subsequent inspection of any

cracked CASS jet pump components due to neutron and thermal embrittlement, and any

technical specification changes related to jet pump components.

In its response, by letter dated January 31, 2005, the applicant indicated that the CASS jet

pump components were manufactured to ASTM A351, grade CF8. These castings are low

molybdenum and the maximum calculated delta ferrite percentage is below 20 percent.

According to Table 2, CASS Thermal Aging Susceptibility Screening Criteria, contained in the

May 19, 2000, NRC letter from Christopher Grimes to Douglas J. Walters, materials that have a

low molybdenum content and less than 20 percent delta ferrite are not susceptible to thermal

aging for statically or centrifugally cast components. The NRC letter from Christopher Grimes to

Carl Terry, dated June 5, 2001, states, "It is important to note that thermal and/or neutron

embrittlement of CASS components becomes a concern only if cracks are present in the

components, and that cracking has not been observed in CASS jet pump assembly

components." Section 2.4 of the same letter states, "Further, the BWRVIP and the NRC's
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Office of Nuclear Regulatory Research (RES) is engaged in a joint confirmatory research

program to determine the effects of high levels of neutron fluence on BWR internals." The

applicant has stated in its LRA that for open issues between the BWRVIP and NRC, the

applicant will work as part of the BWRVIP to resolve these issues generically. When resolved,

the applicant will follow the BWRVIP recommendations resulting from that resolution. The BWR

RVIs program requires inspections of several jet pump assembly welds which are more

susceptible to cracking than the CASS components and will serve as an indication of the

potential need for more extensive inspections later in life. 

Similar to the CASS jet pump components, the orificed fuel supports (OFS) are also

manufactured to ASTM A351, grade CF8. These castings are low molybdenum and the

maximum calculated delta ferrite percentage is below 20 percent. For reasons similar to those

as discussed for the jet pump CASS components, the applicant concluded that no program is

needed to manage the effects of thermal/neutron embrittlement of the CASS OFS. 

The staff concurred with the applicant's response regarding the implementation of the

industry-recommended monitoring program of the effects of high levels of neutron fluence on

the CASS components. The staff concluded that the applicant's justification for excluding the

CASS jet pumps and OFS components from the AMR for the extended period of operation is

acceptable provided that ASME Code Section XI Subsections IWB, IWC, and IWD Program

and the BWR Vessel Internals Program and inspection requirements of BWRVIP-41 are fully

implemented for these components. The staff concurred with the applicant's statement that

continued implementation of these AMPs and the technical guidelines of the BWRVIP-41 report

provide reasonable assurance that the aging effects are adequately managed in the RV CASS

jet pumps and OFS components. The staff found this response acceptable, and its concern

related to RAI 3.1.2.2-9 is resolved.

3.1.2.3.18 Loss of Material Due to Galvanic, General, Crevice, and Pitting Corrosion

In LRA Table 3.1.2.2, the applicant addressed loss of material due to galvanic, general, crevice,

and pitting corrosion in (1) RVIs core shroud and core plate, (2) RVIs core spray piping and

spargers, (3) RVIs control rod housing and dry tubes and guide tubes, (4) RVIs jet pump

assemblies, and (5) RVIs top guide.

The applicant also identified the implementation of relevant AMPs to manage the aging effects

due to galvanic, general, crevice, and pitting corrosion of stainless steel and nickel-alloy

materials when these materials are exposed to the BWR treated-water environment. In LRA

Table 3.1.2.2, the applicant included AMP requirements that are specified in GALL Report,

Volume 2, Table IV.B1 for each of the aforementioned components. However, GALL Report,

Volume 2, Table IV.B1, does not identify loss of material due to crevice, general, and pitting

corrosion as aging effects in stainless steel and nickel-alloy materials that are used in the

aforementioned RV components when these components are exposed to the BWR

treated-water environment. The staff's evaluation of the AMR related to these aging effects is

discussed below.

In LRA Table 3.1.2.2, the applicant stated that the aging effects due to galvanic, general,

crevice, and pitting corrosion of stainless steel and nickel-alloy materials in the RVIs will be

managed by the Boiling Water Reactor Vessel Internals Program, Chemistry Control Program,
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and the inspection guidelines that are provided in the following BWRVIP reports for the

applicable internal components: 

BWRVIP-18 - "Boiling Water Reactor Core Spray Internal Inspection and Flaw

Evaluation Guidelines." 

BWRVIP-25 - "Boiling Water Reactor Core Plate Inspection and Flaw Evaluation

Guidelines."

BWRVIP-26 - "Boiling Water Reactor Top Guide Inspection and Flaw Evaluation

Guidelines." 

BWRVIP-41 - "Boiling Water Reactor Jet Pump Assembly Inspection and Flaw

Evaluation Guidelines."

BWRVIP–47 - "Boiling Water Reactor Lower Plenum Inspection and Flaw Evaluation

Guidelines."

BWRVIP-76 - "Boiling Water Reactor Core Shroud Inspection and Flaw Evaluation

Guidelines" – Staff review is not complete.

The implementation of these additional guidelines and AMPs is consistent with GALL

AMP XI.M9. The applicant stated that continued implementation of these AMPs provides

reasonable assurance that the aforementioned aging effects are adequately managed in the

RVIs. The staff concluded that the implementation of the Chemistry Control Program will

provide adequate controls on BWR reactor water chemistry, which in turn controls general,

pitting and crevice corrosion in RVIs. Furthermore, inspection guidelines that are specified in

the aforementioned staff-approved (with the exception of BWRVIP-76) BWRVIP reports will

provide adequate guidance in performing the necessary inspections so that these aging effects

in RVIs are properly identified in a timely manner.

In LRA Table 3.1.2.1, the applicant addressed loss of material due to galvanic, general, crevice,

and pitting corrosion in (1) reactor head closure studs, (2) RV attachment welds, (3) RV heads,

flanges and shells, (4) RV nozzles, (5) RV nozzles and safe ends, (6) RV penetrations, and (7)

bolting in RV vents, drains, and the recirculation system.

The applicant also identified the implementation of relevant AMPs to manage the aging effects

due to galvanic, general, crevice, and pitting corrosion of carbon and low-alloy steels, stainless

steel and nickel-alloy materials when these materials are exposed to the BWR treated-water

environment. In LRA Table 3.1.2.1, the applicant identified these aging effects and the relevant

AMPs that are associated with each of the aforementioned components. In LRA Table 3.1.2.1,

the applicant also included references related to GALL Report, Volume 2, Table IV.A1 for each

of the aforementioned components.

GALL Report, Volume 2, Table IV.A1, does not identify loss of material due to crevice, general,

and pitting corrosion as aging effects in carbon and low-alloy steel, stainless steel and

nickel-alloy materials that are used in the aforementioned RV components when these

components are exposed to the BWR treated-water environment. General, pitting, and crevice

corrosion may occur in stainless steel or nickel-alloy components under exposure to
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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 stated that the Chemistry Control Program will be used at BFN. The Chemistry

Control Program is based on EPRI Report TR-103515-R2 (the 2000 revision of "BWR Water

Chemistry Guidelines"). The staff found EPRI TR-103515-R2 acceptable because the program

is based on updated industry experience and plant-specific and industry-wide operating

experience confirms the effectiveness of the Chemistry Control Program. In addition, this

program provides an acceptable basis for minimizing the dissolved oxygen and ionic impurity

concentrations that could otherwise, if left present in high concentrations, lead to an aggressive

oxidizing RCS coolant environment, which can enhance corrosion of the RV components. Since

the applicant has conservatively assumed that loss of material due to general corrosion, pitting

corrosion, or crevice corrosion is an applicable aging effect for these RV components, the staff

concludes that the Chemistry Control Program provides a sufficient mitigative strategy for

managing this aging effect relative to the recommendations of the GALL Report. The applicant

stated that it will invoke ASME Code Section XI Subsections IWB, IWC, and IWD Inservice

Inspection Program, which is an established AMP. This program has appropriate requirements

for inspecting the aforementioned vessel components. 

The staff concluded that by implementing the ASME Code Section XI Subsections IWB, IWC,

and IWD Inservice Inspection Program and Chemistry Control Program, the applicant

demonstrated that the effects of aging due to general, pitting, and crevice corrosion 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 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 during the

period of extended operation, as required by 10 CFR 54.21(a)(3).

Conclusion. On the basis of its review, the staff found that the applicant appropriately evaluated

AMR results involving MEAP combinations that are not evaluated in the GALL Report. The staff

found that the applicant 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

The staff concluded that the applicant provided sufficient information to demonstrate that the

effects of aging of the reactor vessel internals and reactor coolant system components that are

within the scope of license renewal and subject to an AMR, will be adequately managed so that

the intended function(s) will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21(a)(3).

The staff also reviewed the applicable UFSAR supplement program summaries and concluded

that they adequately describe the AMPs credited for managing aging of the reactor vessel,

internals, and reactor coolant system, as required by 10 CFR 54.21(d).
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3.2 Aging Management of Engineered Safety Features

This section of the SER documents the staff’s review of the applicant’s AMR results for the ESF

systems components and component groups associated with the following systems:

 • containment

 • standby gas treatment

 • high pressure coolant injection

 • residual heat removal

 • core spray

 • containment inerting

 • containment atmosphere dilution

3.2.1 Summary of Technical Information in the Application

In LRA Section 3.2, the applicant provided AMR results for components. In LRA Table 3.2.1,

“Summary of Aging Management Evaluations for Engineered Safety Features Evaluated in

Chapter V of NUREG-1801,” the applicant provided a summary comparison of its AMRs with

the AMRs evaluated in the GALL Report for the ESF systems components and component

groups.

The applicant’s AMRs incorporated applicable operating experience in the determination of

AERMs. These reviews included evaluation of plant-specific and industry operating experience.

The plant-specific evaluation included reviews of condition reports and discussions with

appropriate site personnel to identify AERMs. The applicant’s review of industry operating

experience included a review of the GALL Report and operating experience issues identified

since the issuance of the GALL Report.

3.2.2 Staff Evaluation

The staff reviewed LRA Section 3.2 to determine whether the applicant had provided sufficient

information to demonstrate that the effects of aging for the ESF systems components that are

within the scope of license renewal and subject to an AMR will be adequately managed so that

the intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21(a)(3).

The staff performed an onsite audit, during the weeks of June 21 and July 2, 2004, 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. Detail of the staff’s audit evaluation are documented in the BFN audit and

review report and are summarized in SER Section 3.2.2.1.

In the onsite audit, the staff also 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 are consistent with the acceptance criteria in SRP-LR Section 3.2.2.2, dated
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July 2001. The staff’s audit evaluations are documented in the BFN audit and review report and

are summarized in SER Section 3.2.2.2.

In the onsite audit, the staff also conducted a technical review of the remaining AMRs that are

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 evaluating

whether the aging effects listed were appropriate for the combination of materials and

environments specified. The staff’s audit evaluations are documented in the BFN audit and

review report and are summarized in SER Section 3.2.2.3. The staff’s evaluation of its technical

review is also documented in Section SER 3.2.2.3.

Finally, the staff reviewed the AMP summary descriptions in the UFSAR supplement to ensure

that they provided an adequate description of the programs credited with managing or

monitoring aging for the ESF systems components.

Table 3.2-1, below, provides a summary of the staff’s evaluation of components, aging

effects/mechanisms, and AMPs listed in LRA Section 3.2 that are addressed in the GALL

Report.

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

GALL Report

Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

Piping, fittings and

valves in

emergency core

cooling system

(Item Number

3.2.1.1)

Cumulative fatigue

damage

TLAA, evaluated in

accordance with

10 CFR 54.21(c)

TLAA This TLAA is

evaluated in

Section 4.3, Metal

Fatigue

Piping, fittings,

pumps and valves

in emergency core

cooling system

(Item Number

3.2.1.2)

Loss of material

due to general

corrosion

Water Chemistry

Program; One-Time

Inspection Program

Chemistry Control

Program; One-Time

Inspection Program

Consistent with

GALL which

recommends further

evaluation (See

Section 3.2.2.2.2)

Components in

containment spray

(PWR only),

standby gas

treatment system

(BWR only),

containment

isolation, and

emergency core

cooling systems

(Item Number

3.2.1.3)

Loss of material

due to general

corrosion

Plant-specific One-Time

Inspection Program;

Chemistry Control

Program; Systems

Monitoring Program

See Section

3.2.2.2.2
Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

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Containment

isolation valves and

associated piping

(Item Number

3.2.1.6)

Loss of material

due to

microbiologically

influenced corrosion

(MIC)

Plant-specific Open-Cycle Cooling

Water Program

See Section

3.2.2.2.4

Seals in standby

gas treatment

system

(Item Number

3.2.1.7)

Changes in

properties due to

elastomer

degradation

Plant-specific N/A See Section

3.2.2.2.5

Drywell and

suppression

chamber spray

system nozzles and

flow orifices

(Item Number

3.2.1.9)

Plugging of nozzles

and flow orifices by

general corrosion

products

Plant-specific N/A See Section

3.2.2.2.7

External surface of

carbon steel

components

(Item Number

3.2.1.10)

Loss of material

due to general

corrosion

Plant-specific One-Time

Inspection Program;

Chemistry Control

Program; Systems

Monitoring Program

See Section

3.2.2.2.2

Piping and fittings

of CASS in

emergency core

cooling systems

(Item Number

3.2.1.11)

Loss of fracture

toughness due to

thermal aging

embrittlement

Thermal Aging

Embrittlement of

CASS Program

N/A Not Applicable

BFN does not

require a thermal

aging embrittlement

of CASS AMP

Components

serviced by

open-cycle cooling

system

(Item Number

3.2.1.12)

Loss of material

due to general,

pitting, and crevice

corrosion, MIC, and

biofouling; buildup

of deposit due to

biofouling

Open-Cycle Cooling

Water System

Program

Open-Cycle Cooling

Water System

Program

Consistent with

GALL which

recommends no

further evaluation

(See Section 

3.2.2.1)

Components

serviced by

closed-cycle cooling

system

(Item Number

3.2.1.13)

Loss of material

due to general,

pitting, and crevice

corrosion

Closed-Cycle

Cooling Water

System Program

Closed-Cycle

Cooling Water

System Program

Consistent with

GALL which

recommends no

further evaluation

(See Section 

3.2.2.1)
Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

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Emergency core

cooling system

valves and lines to

and from high

pressure coolant

injection and

reactor core

isolation cooling

pump turbines

(Item Number

3.2.1.14)

Wall-thinning due to

flow-accelerated

corrosion 

Flow Accelerated

Corrosion Program

Flow Accelerated

Corrosion Program

Consistent with

GALL which

recommends no

further evaluation

(See Section

3.2.2.1)

Pumps, valves,

piping and fittings in

emergency core

cooling system

(Item Number

3.2.1.16)

Crack initiation and

growth due to SCC

and IGSCC

Water Chemistry

Program; BWR

Stress Corrosion

Cracking Program

Chemistry Control

Program; BWR

Stress Corrosion

Cracking Program

Consistent with

GALL, with

exceptions, which

recommends no

further evaluation

(See Section

3.2.2.1))

Closure bolting in

high-pressure or

high-temperature

systems

(Item Number

3.2.1.18)

Loss of material

due to general

corrosion; crack

initiation and growth

due to cyclic

loading and/or SCC

Bolting Integrity

Program

Bolting Integrity

Program

Consistent with

GALL, with

exceptions, which

recommends no

further evaluation

(See Section

3.2.2.1)

The staff’s review of the BFN component groups 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 systems 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

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 3.2.2.3, involves the

staff’s review of the AMR results for components in the ESF systems that the applicant

indicated are not consistent with, or not addressed in, the GALL Report. The staff’s review of

AMPs that are credited to manage or monitor aging effects of the ESF systems components is

documented in SER Section 3.0.3.

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 Application. In LRA Section 3.2.2.1, the applicant

identified the materials, environments, and AERMs. The applicant identified the following

programs that manage the aging effects related to the ESF systems components:

 • Bolting Integrity Program

 • Buried Piping and Tanks Inspection Program

 • Chemistry Control Program

 • One-Time Inspection Program
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 • Open-Cycle Cooling Water System Program

 • Selective Leaching of Materials Program

 • Systems Monitoring Program

 • ASME Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program

 • BWR Stress Corrosion Cracking Program

 • Flow-Accelerated Corrosion Program

Staff Evaluation. In LRA Tables 3.2.2-1 through 3.2.2-7, the applicant provided a summary of

AMRs for the ESF systems components, and identified which AMRs it considered to be

consistent with the GALL Report.

For component groups evaluated in the GALL Report which the applicant stated are consistent

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 audited those AMRs with

Notes A through E, which 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 is different from, but consistent with,

the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent

with the AMP identified by the GALL Report. This note indicates that the applicant 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 is different from, but consistent with,

the GALL Report for material, environment, and aging effect. In addition, the AMP takes some

exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify

consistency with the GALL Report. The staff verified whether the AMR line item of the different

component was applicable to the component under review. The staff verified whether the
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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 that 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 BFN 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 AMRs. The staff’s

evaluation is discussed below.

For aging management evaluations that the applicant stated are consistent with the GALL

Report and for which further evaluation is not recommended, the staff conducted its audit to

determine if the applicant’s reference to the GALL Report in the LRA is acceptable.

The staff reviewed the LRA to confirm that the applicant (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 system components that are subject to an AMR.

The staff identified that LRA Table 3.2.2.5 is not consistent with the GALL Report

Item IVC1.3-c. The staff asked the applicant to explain this inconsistency. By letter dated

October 8, 2004, the applicant submitted its formal response to the staff, stating that the correct

AMPs for LRA Table 3.2.2.5 are the Chemistry Control Program and the BWR Stress Corrosion

Cracking Program (instead of the One-Time Inspection Program). The staff found this

acceptable because it is consistent with the GALL Report.

On the basis of its audit, 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 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 concluded that the AMR results, which the applicant claimed to be consistent with the

GALL Report, are consistent with the AMRs in the GALL Report. Therefore, the staff concluded

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 CFR54.21(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 the

ESF systems. The applicant provided information concerning how it will manage the following

aging effects:

 • cumulative fatigue damage

 • loss of material due to general corrosion

 • local loss of material due to pitting and crevice corrosion

 • local loss of material due to microbiologically influenced corrosion (MIC)

 • changes in properties due to elastomer degradation

 • local loss of material due to erosion

 • buildup of deposits due to corrosion

 • quality assurance for aging management of NSR components

Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant

claimed consistency with the GALL Report, and for which the GALL Report recommends further

evaluation, the staff audited and reviewed the applicant’s evaluation to determine whether it had

adequately addressed the issues that had been further evaluated. In addition, the staff reviewed

the applicant’s further evaluations against the criteria contained in SRP-LR Section 3.2.2.2.

Details of the staff’s audit are documented in the staff’s audit and review report. The staff’s

evaluation of the aging effects is discussed in the following sections.

For some line items in LRA Tables 3.2.2.1 through 3.2.2.7 that are identified to be consistent

with the GALL Report, the applicant cross-referenced specific line items in LRA Tables 3.1.1

and 3.2.1, for which the GALL Report recommends further evaluation. Where the GALL Report

recommends further evaluation, the staff reviewed the applicable further evaluations provided in

LRA Sections 3.1.2.2 and 3.2.2.2 against the criteria provided in SRP-LR Sections 3.1.2.2 and

3.2.2.2, respectively.

The following subsections provide the staff's assessment of the applicant's further evaluations

in LRA Section 3.2.2.2 against the criteria provided in SRP-LR Section 3.2.2.2. 

The staff's assessment of the applicant's further evaluations in LRA Section 3.1.2.2 is provided

in SER Section 3.1.2. Where credited, the assessment also considered applicability to aging

management of the ESF systems.

3.2.2.2.1 Cumulative Fatigue Damage

Consistent with the SRP-LR, the applicant references LRA Section 4.3.3. Cumulative fatigue

damage is a TLAA, and is evaluated in SER Section 4.

3.2.2.2.2 Loss of Material Due to General Corrosion (LRA Section 3.2.2.2.2)

The applicant references LRA Table 3.2.1, items 3.2.1.3 and 3.2.1.10, to address loss of

material due to general corrosion for ESF components in containment isolation, standby gas
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treatment, residual heat removal and containment inerting systems and also for RCS

components. These Table 1 items reference LRA Section 3.2.2.2.2 for further evaluation. 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 of

the portions of ESF systems piping filled with treated water or air/gas, and the external surfaces

of carbon steel components.

SRP-LR Section 3.2.2.2.2 states that the management of loss of material due to general

corrosion of pumps, valves, piping, and fittings associated with some of the BWR emergency

core cooling systems [high pressure coolant injection, reactor core isolation cooling, high

pressure core spray, low pressure core spray, low pressure coolant injection (residual heat

removal)] and with lines to the suppression chamber and to the drywell and suppression

chamber spray system should be further evaluated. The existing AMP relies on monitoring and

control of primary water chemistry to mitigate degradation; however, control of primary water

chemistry does not preclude loss of material due to general corrosion at locations of stagnant

flow conditions. Therefore, verification of the effectiveness of the Chemistry Control Program

should be performed to ensure that corrosion is not occurring. The GALL Report recommends

further evaluation of programs to manage loss of material due to general corrosion to verify the

effectiveness of the 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 such that the component's intended

function will be maintained during the period of extended operation. Also, the GALL Report

recommends further evaluation on a plant-specific basis to ensure that the aging effect on the

external surfaces of BWR carbon steel components is adequately managed.

In the LRA Section 3.2.2.2.2, the applicant stated that loss of material due to general corrosion

of the portions of ESF systems filled with treated water is managed by the Chemistry Control

Program and the One-Time Inspection Program. The One-Time Inspection Program is used to

verify the effectiveness of the Chemistry Control Program for managing the loss of material due

to general corrosion. Loss of material due to general corrosion of the air/gas portions of these

systems is managed by the One-Time Inspection Program for internal surfaces. 

General corrosion of all external surfaces of carbon steel components is managed by the

plant-specific Systems Monitoring Program. The staff reviewed the BFN procedure (NEDP-20,

rev. 3, "Conduct of the Engineering Organization," September 9, 2002) for conducting system

monitoring during system walkdowns. The walkdown encompasses all or part of the total

accessible system, such that the entire system is covered over time. The walkdown is a detailed

look at system parameters, material condition, operation, configuration, degraded components,

outstanding work activities, and design changes. The material condition involves no missing,

discolored-indicating-a-potential-leak, or damaged insulation. The staff found that the Systems

Monitoring Program would be able to detect any corrosion on the external surfaces of carbon

steel components.

On the basis of its review of the Chemistry Control Program, One-Time Inspection Program,

and the Systems Monitoring Program, the staff found that the applicant had conducted an

acceptable AMR for management of loss of material due to general corrosion, consistent with

the recommendations in the GALL Report. 
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3.2.2.2.3 Local Loss of Material due to Pitting and Crevice Corrosion

The applicant references LRA Table 3.2.1, item 3.2.1.5, to address loss of material due to

pitting and crevice corrosion for ESF components in containment and containment inerting

systems and also for RCS components. The applicant's further evaluation is in LRA

Section 3.2.2.2.3. The staff reviewed LRA Section 3.2.2.2.3 against the criteria in SRP-LR

Section 3.2.2.2.3.

In the LRA Section 3.2.2.2.3, the applicant addressed local loss of material from pitting and

crevice corrosion that could occur in the ESF systems and associated piping filled with treated

water or air/gas.

SRP-LR Section 3.2.2.2.3 states that the management of local loss of material due to pitting

and crevice corrosion of pumps, valves, piping, and fittings associated with some of the BWR

emergency core cooling system piping and fittings [high pressure coolant injection, reactor core

isolation cooling, high pressure core spray, low pressure core spray, low pressure coolant

injection (residual heat removal)] and with lines to the suppression chamber and to the drywell

and suppression chamber spray system should be evaluated further. The existing AMP relies

on monitoring and control of primary water chemistry 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 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 verify the effectiveness of the 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 the LRA Section 3.2.2.2.3, the applicant stated that loss of material due to pitting and crevice

corrosion of the portions of ESF systems filled with treated water is managed by the Chemistry

Control Program and the One-Time Inspection Program. The One-Time Inspection Program is

used to verify the effectiveness of the Chemistry Control Program for managing the loss of

material due to pitting and crevice corrosion. Loss of material due to pitting and crevice

corrosion of the air/gas portions of these systems is managed by the One-Time Inspection

Program for internal surfaces.

On the basis of its review of the Chemistry Control Program and One-Time Inspection Program,

the staff found that the applicant had conducted an acceptable AMR for management of loss of

material due to pitting and crevice corrosion, consistent with the recommendations in the GALL

Report.

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.

The applicant references LRA Table 3.2.1, item 3.2.1.6, to address loss of material due to MIC

for ESF components in containment and containment inerting systems.
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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.

LRA Section 3.2.2.2.4 states that the applicant considers MIC to be an aging mechanism for

systems in a raw water environment. BFN has no systems containing raw water that penetrate

primary containment. Several raw water systems penetrate secondary containment. BFN

utilizes the Open-Cycle Cooling Water Program to manage the aging effects that could be

caused by MIC in these systems.

On the basis of its review of the Open-Cycle Cooling Water Program, the staff found that the

applicant had conducted an acceptable AMR for management of loss of material due to MIC,

consistent with the recommendations in the GALL Report.

3.2.2.2.5 Changes in 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 described its AMR for change in material properties due to

elastomer degradation, for seals in ductwork and filters associated with the standby gas

treatment (SGT) system. The applicant stated that the normal operating temperature of the

SGT system is less than the defined limits for hardening and loss of strength of installed

elastomers. This statement is not consistent with the criteria in SRP-LR Section 3.2.2.2.5.

LRA Table 3.2.2.2, which includes the AMR results for elastomer seals in the SGT system,

does not reference LRA Table 1, Item 3.2.1.7. Instead, the applicant identified the AMR for

these components to be not consistent with the GALL Report, and concluded that aging

management is not required. The staff evaluation of the applicant’s AMR results for elastomers

in the SGT system was not conducted during the onsite audit.

3.2.2.2.6 Local Loss of Material due to Erosion

Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not

applicable to BFN.

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 addressed the plugging of components due to general

corrosion that could occur in the spray nozzles and flow orifices of the drywell and suppression

chamber spray system. The applicant stated that spray nozzles are brass and are not

susceptible to general corrosion, and that there are no orifices susceptible to general corrosion

that are occasionally wetted in the ESF systems. 

The applicant does not reference LRA Table 1, Item 3.2.1.9 in any of the AMR tables for the

ESF systems. The applicant concluded that, since the spray nozzles and orifices are not

susceptible to general corrosion that may cause plugging, aging management is not required.

The staff found the applicant’s AMR results to be acceptable, on the basis that the subject

components are not susceptible to general corrosion. 
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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 QA 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 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 3.2.2.7, 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 that are not addressed

in the GALL Report.

In LRA Tables 3.2.2.1 through 3.2.2.7, the applicant indicated, via Notes F through J, that the

combination of component type, material, environment, and AERM does not correspond to a

line item in the GALL Report, and provided information concerning how the aging effect will be

managed. Specifically, Note F indicated that the material for the AMR line item component is

not evaluated in the GALL Report. Note G indicated that the environment for the AMR line item

component and material is not evaluated in the GALL Report. Note H indicated that the aging

effect for the AMR line item component, material, and environment combination is not evaluated

in the GALL Report. Note I indicated that the aging effect identified in the GALL Report for the

line item component, material, and environment combination is not applicable. Note J indicated

that neither the component nor the material and environment combination for the line item is

evaluated in the GALL Report.

Staff Evaluation. For component type, material, and environment combinations that are not

evaluated in the GALL Report, the staff reviewed the applicant’s evaluation to determine

whether the applicant 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.

The staff requested the applicant to provide additional information on the issues described in

the following general RAIs. These RAIs, the applicant's responses, and the staff's evaluation of

the responses are described below.

In RAI 3.2-1, dated November 18, 2004, the staff stated that in LRA Tables 3.2.2.1 through

3.2.2.7, carbon and low-alloy steel bolting in an inside air (external) or outside air (external)

environment is not identified with any AERMs. The applicant indicated that this is because BFN

does not use high yield strength bolting. Therefore, the staff requested that the applicant

discuss the specific material grade used for the bolting in each of the associated systems, and
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justify the basis for concluding that crack initiation/growth due to SCC is not a concern for the

bolting during the period of extended operation. 

In its letter dated December 16, 2004, the applicant responded as follows:

The identified aging management program is the Bolting Integrity Program. As noted, a

cracking aging effect is not identified because high yield bolting materials (yield strength

above 150 ksi) were not identified and plant operating experience does not indicate an

adverse history of bolt cracking. Stress corrosion cracking (SCC) of bolted closures and

fasteners is a condition of high yield strength bolting material where a fastener that is

statically loaded well below its yield strength can experience sudden failure. SCC occurs

through the combination of high stress (both applied and residual tensile stresses), a

corrosive environment, and a susceptible material. SCC of high yield strength bolted

closures in BWRs requires a corrosive environment typically attributed to leakage of

pressure boundary joints or exposure to wetted ambient environments (indoor, outdoor,

buried and submerged) and the use of thread lubricant containing MoS2 (molybdenum

disulfide). 

The use of MoS2 thread lubricant is not allowed by site and engineering procedures.

Therefore, any maintenance on this mechanical equipment would result in the use of

non-MoS2 thread lubricant. Loss of bolting function due to SCC of bolted joints of

vendor-supplied mechanical equipment is not expected and no aging management is

required for the period of extended operation.

The staff concluded that loss of bolting function due to SCC of bolted joints of vendor-supplied

mechanical equipment is not expected and that aging management is not required for these

components for the period of extended operation. On the basis of the applicant’s response, the

staff’s concern described in RAI 3.2-1 is resolved.

In RAI 3.2-2, dated November 18, 2004, the staff stated that in LRA Tables 3.2.2.1 through

3.2.2.4, 3.2.2.6, and 3.2.2.7, nickel-alloy bolting in inside air (external) environments were not

identified with any AERMs. The applicant invoked industry guidance/experience to support the

analysis. Therefore, the staff requested the applicant to provide a detailed discussion of the air

environment involved, and to justify the basis for concluding that there are no AERMs under

such material/environment combinations. The staff also requested information on the stated

industry guidance.

In its letter dated December 16, 2004, the applicant responded as follows:

The nickel-alloy bolting in the Containment Isolation System was evaluated for wear and

no applicable wear mechanism was identified for non-RCPB components. Therefore,

wear is not an aging mechanism that requires management for the period of extended

operation for the Containment Isolation System. Nickel-alloy bolting, similar to stainless

steel bolting, is subject to cracking under severe environmental conditions such as high

temperature and being buried or submerged (potentially, depending on type of external

water). Nickel-alloy bolting in the Containment Isolation System is not subject to this

severe environment; therefore, cracking was not identified.
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The copper-alloy components exposed to an inside air (external) environment were

evaluated individually to determine where condensation or periodic wetting could occur.

The identified aging effects were then determined based on the particular copper alloy

present and whether condensation or periodic wetting could occur. Based on this

evaluation, there were no instances where copper alloys components with > 15% Zn

were subjected to an aggressive environment or condensation/periodic wetting.

Therefore, no aging effects that require management during the period of extended

operation were identified for the copper alloy components in the subject tables. A

summary description of the industry guidance (i.e., when industry guidance is

referenced was provided in the EPRI Technical Report 1003056, “Non-Class 1

Mechanical Implementation Guideline and Mechanical Tools”) for copper alloys. 

The applicant response dated December 16, 2004, contains detailed information for copper

alloys. On the basis of the applicant's response, the staff’s concern described in RAI 3.2-2 is

resolved.

In RAI 3.2-3, dated November 18, 2004, the staff stated that in LRA Table 3.2.2.1, material

carbon and low-alloy steel, component type valves in a treated water (internal) environment are

not identified with any AERMs. The staff noted that the component, material and environment

combination for this component is similar to that identified in the GALL Report, Item V.C.1-a,

which recommends a plant-specific AMP to be evaluated for the identified aging effects.

Therefore, the staff requested that the applicant explain why the aging effects identified in the

GALL Report, such as loss of material due to general, pitting, and crevice corrosion, are not

applicable to these components.

In its response, by letter dated December 16, 2004, the applicant stated that the reason for the

line entries that indicate no aging effects is an attempt to ensure completeness of GALL Report

comparison. For carbon and low-alloy steel valves in a treated water environment, rows 78, 79,

and 80 of LRA Table 3.2.2.1 address the applicable aging mechanisms. The applicable GALL

Volume 2 line item was determined to be V.C.1-a. which lists five aging effects: general, pitting,

crevice, MIC, and biofouling. For a treated water environment, the BFN AMR determined that

microbiologically influenced corrosion and biofouling did not require management for the period

of extended operation. However, the BFN AMR determined that in addition to the aging

mechanisms identified in the GALL Report, galvanic corrosion was also applicable. This was

documented in the AMR as:

Galvanic corrosion – Yes, with notes H and 3

General corrosion – Yes, consistent with GALL

Pitting corrosion – Yes, consistent with GALL

Crevice corrosion – Yes, consistent with GALL

Microbiologically influenced corrosion – No, see below

Biofouling – No, see below

The first aging mechanism is documented in row 78 with notes H and 3. The next three aging

mechanisms, which are consistent with the GALL Report, form the basis for row 80 of LRA

Table 3.2.2.1. The last two aging mechanisms are documented in row 79 of LRA Table 3.2.2.1

with a note 5 was incorrect which should be 4. Note 4, stated that based on system design and

operating history, MIC and biofouling were determined to be not applicable to the treated water

portions of this system. 
3-190

The staff found the above applicant's response to have adequately clarified the fact that loss of

material due to general, pitting, and crevice (in addition to galvanic) corrosion has indeed been

identified in its AMR. Therefore, the staff’s concern described in RAI 3.2-3 is resolved.

In RAI 3.2-3, dated November 18, 2004, the staff stated that in LRA Table 3.2.2.3, the applicant

did not identify elastomer flexible connectors in an air/gas (internal) environment with any

AERMs. The applicant stated that there are no applicable aging effects for this

material/environment combination and believes that this is consistent with industry guidance.

Therefore, the staff requested additional information to justify the basis for concluding that there

are no AERMs under such material/environment combinations, including an insight into the

industry guidance.

In its response, by letter dated December 16, 2004, the applicant stated that the issue involved

aging effects due to material property changes and cracking of the rubber fabric reinforced

(elastomer) flexible connectors upstream and downstream of the gland seal condenser blower

(gland exhauster) in an air/gas environment. These effects are caused by exposure to

ultraviolet radiation, oxygen, ozone, heat, and radiation. The applicant stated that the elastomer

degradation due to these aging mechanisms are not significant because the ultraviolet radiation

and ozone effects to the internal surfaces of the components are negligible. The LRA does

identify elastomer degradation due to ultraviolet radiation and ozone for the external surfaces of

these components. 

The applicant further stated that maximum temperature rating for rubber is 130 °F per industry

guidance. During normal operation, the temperature of the flexible connectors is significantly

less than 130 °F; therefore, degradation from thermal exposure is not identified as an aging

mechanism requiring management for the period of extended operation. The applicant further

stated that the dose threshold for radiation degradation of rubber is 107 rads. The ionizing

radiation the flexible connectors will receive is negligible (much less than 107 rads); therefore,

degradation from ionizing radiation is not identified as an aging mechanism requiring

management for the period of extended operation.

The staff found the applicant's basis for not identifying any aging effects for the elastomer

flexible connectors to be acceptable. Therefore, the staff’s concern described in RAI 3.2-4 is

resolved.

In RAI 3.2-5, dated November 18, 2004, the staff stated that in LRA Table 3.2.2.5, the applicant

stated that aluminum-alloy fittings in a treated water (internal) environment are identified as

being susceptible to crack initiation/growth due to SCC and loss of material due to crevice and

pitting corrosion. Therefore, the staff requested additional information to explain why loss of

material due to general and galvanic corrosion is not identified as a potential AERM during the

period of extended operation. The applicant was also requested to explain how the Chemistry

Control Program, in association with the One-Time Inspection Program, is used to manage the

identified aging effects. 

In its response, by letter dated December 16, 2004, the applicant stated that, per industry

guidance, aluminum and aluminum-based alloys in a treated water environment are not

susceptible to loss of material due to general corrosion. In addition, the applicant stated that the

aluminum fittings in Table 3.2.2.5 are the flanges off the 24-inch diameter condensate supply

header within the core spray system. An electrically insulating rubber gasket is used to
3-191

electrically separate the aluminum flanges from more cathodic materials, such as copper or

stainless or carbon steels. Based on that, the staff concurred with the applicant's conclusion

that galvanic corrosion is not a concern for this configuration for aluminum fittings in a treated

water environment for the core spray system. 

The applicant also stated that the main objective of the Chemistry Control Program is to

minimize loss of material due to general, crevice, and pitting corrosion and crack initiation and

growth caused by SCC. Corrosion and cracking of aluminum alloys in treated water is managed

by maintaining oxygen, chlorides, and sulfates within the limits of the Chemistry Control

Program. The specific chemistry limits are the same as the limits used to manage aging of

carbon/low-alloy and stainless steel components in a treated water environment. The applicant

stated that the use of the Chemistry Control Program is consistent with industry practice as

identified in its past precedence review. The staff accepted the Chemistry Control Program for

primary systems program and its evaluation of this program is documented in SER

Section 3.0.3.2.2. GALL AMP XI.M32, “One-Time Inspection,” is used to verify the Chemistry

Control Program's effectiveness, as recommended by the GALL Report. The staff considered

that the applicant had adequately addressed its concerns stated in the RAI; therefore, RAI 3.2-5

is resolved. 

In RAI 3.2-6, dated November 18, 2004, the staff stated that in LRA Table 3.2.2.5 polymer

tubing in an air/gas (internal) or inside air (external) environment is not identified with any

AERMs. Therefore, the staff requested the applicant to provide a discussion of the air

environment involved, and justify the basis for concluding that there are no AERMs under such

material/environment combinations. 

In its response, by letter dated December 16, 2004, the applicant stated that polymer tubing in

the core spray system is the Tygon (polyvinyl chloride) tube off the closed drain valve

downstream of the drain dirt separator (trap) used in the keep fill system (shown on drawing

2-47E814-1). Under normal operating conditions, the internal and external environment is

atmospheric air. The applicant stated that unlike metals, thermoplastics do not display corrosion

rates. Rather than depending on an oxide layer for protection, they depend on chemical

resistance to the environment to which they are exposed. Therefore, acceptability for the use of

thermoplastics in an air/gas environment is a design driven criterion. Once the appropriate

material is chosen, the system will have no aging effects.

The applicant stated that the temperature and radiation damage threshold limits are 200 °F and

2 x 107 rads, respectively. Neither of these limits is challenged in the LRA where Tygon is

utilized; however, Tygon may be degraded when exposed to air and ultraviolet radiation;

therefore, the applicant stated that for the external surface of the Tygon tubing, degradation

should have been identified in the LRA by revising the line item to include "Hardening and loss

of strength due to polymer degradation (ultraviolet radiation)" as an aging effect and an aging

mechanism. The Systems Monitoring Program will be used to manage the aging effect. 

Based on the above, the staff considered that the applicant had adequately addressed its

concerns; therefore, RAI 3.2-6 is resolved. 
3-192

3.2.2.3.1 Containment System – Summary of Aging Management Evaluation – Table 3.2.2.1

The staff reviewed LRA Table 3.2.2.1, which summarizes the results of AMR evaluations for the

containment system component groups.

In LRA Table 3.2.2.1, the applicant identified no aging effects in containment system

component groups made of aluminum alloys exposed to inside/outside air in the ductwork and

heat exchangers or carrying air/gas in the ductwork; carbon and low-alloy steel piping/fittings

embedded or encased in concrete; copper-alloy piping carrying air/gas; glass (fittings) exposed

to air/gas, treated water, or inside air; and nickel-alloy fittings, stainless steel fittings, and 

zinc-alloy ductwork exposed to air/gas. These environment’s conditions are not identified in the

GALL Report for these components and materials. On the basis of current industry research

and operating experience, dry air on metal will not result in aging that will be of concern during

the period of extended operation. The external environments being referred to are typical of

ambient air (e.g., under a shelter, indoors, or air-conditioned enclosure or room). Significant

corrosion of low-alloy steel requires an electrolytic environment, and a simultaneous presence

of oxygen and moisture. Without the presence of an aggressive environment, these

components experience insignificant amounts of corrosion, and no aging effects are applicable

to this component/commodity group. Therefore, the staff concluded that there are no applicable

aging effects for these material and environment combinations.

In LRA Table 3.2.2.1, the applicant identified that the loss of material due to general, crevice,

pitting and galvanic corrosion in carbon/low-alloy steel, nickel alloys and stainless steel piping

and fittings in treated water are managed by the Chemistry Control Program and One-Time

Inspection Program. The Chemistry Control Program relies on monitoring and control of reactor

water chemistry based on BWRVIP-79 to prevent loss of material from general, pitting, crevice

or galvanic corrosion. However, high concentrations of impurities at crevices and locations of

stagnant flow conditions could cause corrosion. Therefore, verification of the effectiveness of

the Chemistry Control Program needs to be performed to ensure that corrosion is not occurring.

The one-time inspection of selected components at susceptible locations is an acceptable

method for ensuring that corrosion is not occurring and that the component’s intended function

will be maintained during the period of extended operation. 

In LRA Table 3.2.2.1, heat exchanger components made of carbon/low-alloy steel and exposed

to raw water are susceptible to loss of material due to biofouling, MIC, crevice, galvanic,

general, and pitting corrosion; and heat exchanger components made of copper alloys and

exposed to raw water are susceptible to fouling due to biological particulate build-up and loss of

material due to selective leaching, biofouling, MIC, crevice and pitting corrosion. The applicant

credited the Selective Leaching of Materials Program and Open-Cycle Cooling Water System

Program to manage these aging effects. The latter AMP, in accordance with the guidelines of

GL 89-13, includes managing aging effects by condition monitoring (system and component

testing, visual inspections, and NDE testing), and by preventive actions (biocide treatment and

filtering to prevent loss of material due to MIC and biofouling and flow blockage and reduction

of heat transfer due to biological and particulate fouling). The staff found this acceptable.

Aluminum-alloy heat exchangers carrying air/gas; carbon/low-alloy steel piping/fittings and heat

exchangers exposed to air/gas; and copper-alloy components of heat exchangers exposed to

air/gas are susceptible to loss of material due to general pitting, crevice corrosion, and fouling

due to particulate build-up. In LRA Table 3.2.2.1, the applicant credited the One-Time
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Inspection Program to manage these aging effects. This aging effect is not in the GALL Report

for this component, material, and environment combination. The one-time inspection provides

the opportunity to visually inspect the internal surfaces of components during preventive and

corrective maintenance activities. The staff found the One-Time Inspection Program acceptable

for managing the aging effect of loss of material.

In LRA Table 3.2.2.1, piping and fittings made of carbon/low-alloy steel buried in soil are

susceptible to loss of material due to MIC, crevice, general, and pitting corrosion. The applicant

credited the Buried Piping and Tanks Inspection Program to manage this aging effect. This

AMP involves preventive measures to mitigate corrosion (external coatings and wrappings have

been applied in accordance with standard industry practices) and condition monitoring to

manage the effects of corrosion. Buried piping is inspected when excavated for any reason,

typically for maintenance. The inspections are performed as part of the 10 CFR 50.65,

“Maintenance Rule Program.” The inspections provide for determination of degradation due to

the loss of, or damage to, the protective coatings and wraps used for corrosion control on

buried pipe external surfaces. The inspections also include connections and joints for signs of

separation, signs of environmental degradation, signs of leakage, and appreciable settlement

between piping segments. The staff found this inspection program acceptable for managing the

aging effect of loss of material.

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 during the

period of extended operation, as required by 10 CFR 54.21(a)(3).

3.2.2.3.2 Standby Gas Treatment System – Summary of Aging Management Evaluation –

Table 3.2.2.2

The staff reviewed LRA Table 3.2.2.2, which summarizes the results of AMR evaluations for the

standby gas treatment system component groups.

In LRA Table 3.2.2.2, the applicant identified no aging effects in standby gas treatment system

component groups made of aluminum-alloy ductwork, copper-alloy tubing, stainless steel

fittings, and zinc-alloy ductwork. All of these components carry air/gas and their external

surface is exposed to inside air. These environment conditions are not identified in the GALL

Report for these components and materials. On the basis of current industry research and

operating experience, dry air on metal will not result in aging that will be of concern during the

period of extended operation. The external environments being referred to are typical of

ambient air (e.g., under a shelter, indoors, or air-conditioned enclosure or room). Significant

corrosion of low-alloy steel requires an electrolytic environment, and a simultaneous presence

of oxygen and moisture. Without the presence of an aggressive environment, these

components experience insignificant amounts of corrosion, and no aging effects are applicable

to this component/commodity group. Therefore, the staff concluded that there are no applicable

aging effects for these material and environment combinations.

In LRA Table 3.2.2.2, piping and fittings made of carbon/low-alloy steel buried in soil are

susceptible to loss of material due to MIC, crevice, general, and pitting corrosion. The applicant

credited the Buried Piping and Tanks Inspection Program to manage this aging effect. This

AMP involves preventive measures to mitigate corrosion (external coatings and wrappings have

been applied in accordance with standard industry practices) and condition monitoring to
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manage the effects of corrosion. Buried piping is inspected when excavated for any reason,

typically for maintenance. The inspections are performed as part of the 10 CFR 50.65,

“Maintenance Rule Program.” The inspections provide for determination of degradation due to

the loss of, or damage to, the protective coatings and wraps used for corrosion control on

buried pipe external surfaces. The inspections also include connections and joints for signs of

separation, signs of environmental degradation, signs of leakage, and appreciable settlement

between piping segments. The staff found this inspection program acceptable for managing the

aging effect of loss of material.

Carbon and low-alloy steel and cast iron/cast iron alloy piping, fittings, and valves exposed to

air/gas are susceptible to loss of material due to general corrosion. In LRA Table 3.2.2.2, the

applicant credited the One-Time Inspection Program to manage loss of material in these

components. This aging effect is not in the GALL Report for this component, material, and

environment combination. The one-time inspection provides the opportunity to visually inspect

the internal surfaces of components during preventive and corrective maintenance activities.

The staff found the One-Time Inspection Program acceptable for managing the aging effect of

loss of material.

Carbon and low-alloy steel and cast iron/cast iron alloy piping, fittings, and valves external

surfaces exposed to inside air are managed by the Systems Monitoring Program against any

loss of material due to general corrosion. The system walkdown encompasses all or part of the

total accessible system, such that the entire system is covered over time. The walkdown is a

detailed look at system parameters, material condition, operation, configuration, degraded

components, outstanding work activities, and design changes. The material condition involves

no missing, discolored-indicating-a-potential-leak, or damaged insulation. The staff found that

the Systems Monitoring Program would be able to detect any corrosion on the external surfaces

of these components.

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 during the

period of extended operation, as required by 10 CFR 54.21(a)(3).

3.2.2.3.3 High Pressure Coolant Injection System – Summary of Aging Management

Evaluation – Table 3.2.2.3

The staff reviewed LRA Table 3.2.2.3, which summarizes the results of AMR evaluations for the

high pressure coolant injection (HPCI) system component groups.

In LRA Table 3.2.2.3, the applicant identified no aging effects in HPCI system component

groups made (1) out of carbon and low-alloy steel piping and fittings exposed to inside air

(external surface) and carrying lube oil, cast iron alloy pumps and valves carrying lube oil; (2) 

copper-alloy tubing/fittings carrying air/gas and lube oil; (3) glass (fittings) exposed to air/gas

and lube oil; and (4) nickel-alloy flexible connectors and stainless steel fittings exposed to inside

air (external). These environment conditions are not identified in the GALL Report for these

components and materials. On the basis of current industry research and operating experience,

dry air on metal will not result in aging that will be of concern during the period of extended

operation. The external environments being referred to are typical of ambient air (e.g., under a

shelter, indoors, or air-conditioned enclosure or room). Significant corrosion requires an

electrolytic environment, and a simultaneous presence of oxygen and moisture. Without the
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presence of an aggressive environment, these components experience insignificant amounts of

corrosion, and no aging effects are applicable to this component/commodity group. Therefore,

the staff concluded that there are no applicable aging effects for these material and

environment combinations.

In LRA Table 3.2.2.3, the applicant identified that the loss of material due to general, crevice,

pitting and galvanic corrosion in carbon/low-alloy steel piping, fittings, and various components,

cast iron and cast iron alloy pumps, copper-alloy condensers and heat exchangers, nickel-alloy

flexible connectors, and stainless steel piping, fittings, tubing, and valves in treated water are

managed by the Chemistry Control Program and One-Time Inspection Program. The Chemistry

Control Program relies on monitoring and control of reactor water chemistry based on

BWRVIP-79 to prevent loss of material from general, pitting, crevice or galvanic corrosion.

However, high concentrations of impurities at crevices and locations of stagnant flow conditions

could cause corrosion. Therefore, verification of the effectiveness of the Chemistry Control

Program needs to be performed to ensure that corrosion is not occurring. The one-time

inspection of selected components at susceptible locations is an acceptable method for

ensuring that corrosion is not occurring and the component’s intended function will be

maintained during the period of extended operation. 

In components made from cast iron and cast iron alloys and copper alloy, selective leaching

takes place when these components are exposed to corrosion-inhibited treated water,

oxygenated and de-oxygenated treated water. In LRA Table 3.2.2.3, the applicant identified

Selective Leaching of Materials Program to manage loss of material due to selective leaching in

cast iron pumps and copper-alloy condensers exposed to treated water. The applicant’s

selective leaching program relies on visual inspections and hardness measurements on

selected components susceptible to selective leaching. On the basis of industry operating

experience with this material and environment, the staff found this acceptable.

Cast iron/cast iron alloy fittings and carbon and low-alloy steel external surfaces exposed to

inside air are managed by the Systems Monitoring Program against any loss of material due to

general corrosion. Elastomer flexible connections exposed to inside air are subject to elastomer

degradation due to ultraviolet radiation, which is also managed by the Systems Monitoring

Program. The system walkdown encompasses all or part of the total accessible system, such

that the entire system is covered over time. The walkdown is a detailed look at system

parameters, material condition, operation, configuration, degraded components, outstanding

work activities, and design changes. The material condition involves no missing,

discolored-indicating-a-potential-leak, or damaged insulation. The staff found that the Systems

Monitoring Program would be able to detect any corrosion on the external surfaces of these

components.

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 during the

period of extended operation, as required by 10 CFR 54.21(a)(3).

3.2.2.3.4 Residual Heat Removal System – Summary of Aging Management Evaluation –

Table 3.2.2.4

The staff reviewed LRA Table 3.2.2.4, which summarizes the results of AMR evaluations for the

residual heat removal (RHR) system component groups.
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In LRA Table 3.2.2.4, the applicant identified no aging effects in RHR system component

groups made of aluminum exposed to inside air (external), carbon and low-alloy steel

piping/fittings exposed to inside air (external), and copper-alloy and stainless steel fittings

carrying air/gas. These environment conditions are not identified in the GALL Report for these

components and materials. On the basis of current industry research and operating experience,

dry air on metal will not result in aging that will be of concern during the period of extended

operation. The external environments being referred to are typical of ambient air (e.g., under a

shelter, indoors, or air-conditioned enclosure or room). Significant corrosion requires an

electrolytic environment, and a simultaneous presence of oxygen and moisture. Without the

presence of an aggressive environment, these components experience insignificant amounts of

corrosion, and no aging effects are applicable to this component/commodity group. Therefore,

the staff concluded that there are no applicable aging effects for these material and

environment combinations.

In LRA Table 3.2.2.4, the applicant identified that the loss of material due to general, crevice,

pitting and galvanic corrosion in carbon/low-alloy steel heat exchangers, piping, fittings, and

other components, cast iron alloy pumps, copper-alloy, and aluminum alloy fitting, and stainless

steel piping, fittings, and other components in treated water are managed by the Chemistry

Control Program and One-Time Inspection Program. The Chemistry Control Program relies on

monitoring and control of reactor water chemistry based on BWRVIP-79 to prevent loss of

material from general, pitting, crevice or galvanic corrosion. However, high concentrations of

impurities at crevices and locations of stagnant flow conditions could cause corrosion.

Therefore, verification of the effectiveness of the Chemistry Control Program needs to be

performed to ensure that corrosion is not occurring. The one-time inspection of selected

components at susceptible locations is an acceptable method for ensuring that corrosion is not

occurring and the component’s intended function will be maintained during the period of

extended operation. 

In components made from cast iron and copper alloy, selective leaching takes place when

these components are exposed to raw water, corrosion-inhibited treated water, oxygenated and

de-oxygenated treated water, or are buried underground. In LRA Table 3.2.2.4, the applicant

identified the Selective Leaching of Materials Program to manage loss of material due to

selective leaching in cast iron heat exchangers and pumps and copper-alloy fittings exposed to

raw water or treated water. The applicant’s selective leaching program relies on visual

inspections and hardness measurements on selected components susceptible to selective

leaching. On the basis of industry operating experience with this material and environment, the

staff found this acceptable.

Carbon and low-alloy steel components and cast iron/cast iron alloy heat exchangers and

pumps’ external surfaces exposed to inside air are managed by the Systems Monitoring

Program against any loss of material due to general corrosion. The system walkdown

encompasses all or part of the total accessible system such that the entire system is covered

over time. The walkdown is a detailed look at system parameters, material condition, operation,

configuration, degraded components, outstanding work activities, and design changes. The

material condition involves no missing, discolored-indicating-a-potential-leak, or damaged

insulation. The staff found that the Systems Monitoring Program would be able to detect any

corrosion on the external surfaces of these components.
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In LRA Table 3.2.2.4, heat exchanger components made of carbon/low-alloy steel, cast iron

alloys and stainless steel exposed to raw water are susceptible to loss of material due to

biofouling, MIC, crevice, galvanic, general, and pitting corrosion as well as fouling product

buildup due to biological. The applicant credited the Open-Cycle Cooling Water System

Program to manage this aging effect. This AMP, in accordance with the guidelines of GL 89-13,

includes managing aging effects by condition monitoring (system and component testing, visual

inspections, and NDE testing), and by preventive actions (biocide treatment and filtering to

prevent loss of material due to MIC, biofouling, flow blockage and reduction of heat transfer due

to biological and particulate fouling). The staff found this acceptable.

Carbon and low-alloy steel and cast iron/cast iron alloy fittings exposed to air/gas are

susceptible to loss of material due to general corrosion. In LRA Table 3.2.2.4, the applicant

credited the One-Time Inspection Program to manage loss of material in these components.

This aging effect is not in the GALL Report for this component, material, and environment

combination. The one-time inspection provides the opportunity to visually inspect the internal

surfaces of components during preventive and corrective maintenance activities. The staff

found the One-Time Inspection Program acceptable for managing the aging effect of loss of

material.

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 during the

period of extended operation, as required by 10 CFR 54.21(a)(3).

3.2.2.3.5 Core Spray System – Summary of Aging Management Evaluation – Table 3.2.2.5

The staff reviewed LRA Table 3.2.2.5, which summarizes the results of AMR evaluations for the

core spray system component groups.

In LRA Table 3.2.2.5, the applicant identified no aging effects in core spray system component

groups made of aluminum exposed to inside air (external); carbon and low-alloy steel

piping/fittings exposed to inside air (external); and stainless steel fittings carrying air/gas or

exposed to inside air. These environment conditions are not identified in the GALL Report for

these components and materials. On the basis of current industry research and operating

experience, dry air on metal will not result in aging that will be of concern during the period of

extended operation. The external environments being referred to are typical of ambient air (e.g.,

under a shelter, indoors, or air-conditioned enclosure or room). Significant corrosion requires an

electrolytic environment, and a simultaneous presence of oxygen and moisture. Without the

presence of an aggressive environment, these components experience insignificant amounts of

corrosion, and no aging effects are applicable to this component/commodity group. Therefore,

the staff concluded that there are no applicable aging effects for these material and

environment combinations.

In LRA Table 3.2.2.5, the applicant identified that the loss of material due to general, crevice,

pitting and galvanic corrosion in carbon/low-alloy steel heat exchangers, piping, fittings, and

various other components, cast iron alloy pumps, and stainless steel piping, fittings, and valves

in treated water are managed by the Chemistry Control Program and One-Time Inspection

Program. The Chemistry Control Program relies on monitoring and control of reactor water

chemistry based on BWRVIP-79 to prevent loss of material from general, pitting, crevice or

galvanic corrosion. However, high concentrations of impurities at crevices and locations of
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stagnant flow conditions could cause corrosion; therefore, verification of the effectiveness of the

Chemistry Control Program needs to be performed to ensure that corrosion is not occurring.

The one-time inspection of selected components at susceptible locations is an acceptable

method for ensuring that corrosion is not occurring and the component’s intended function will

be maintained during the period of extended operation. 

In components made from cast iron alloys, selective leaching takes place when these

components are exposed to corrosion-inhibited treated water, oxygenated and de-oxygenated

treated water. In LRA Table 3.2.2.5, the applicant identified Selective Leaching of Materials

Program to manage loss of material due to selective leaching in cast iron heat exchangers and

pumps exposed to treated water. The applicant’s selective leaching program relies on visual

inspections and hardness measurements on selected components susceptible to selective

leaching. On the basis of industry operating experience with this material and environment, the

staff found this acceptable.

Carbon/low-alloy steel components and cast iron/cast iron alloy pumps external surfaces

exposed to inside air are managed by the Systems Monitoring Program against any loss of

material due to general corrosion. The system walkdown encompasses all or part of the total

accessible system, such that the entire system is covered over time. The walkdown is a detailed

look at system parameters, material condition, operation, configuration, degraded components,

outstanding work activities, and design changes. The material condition involves no missing,

discolored-indicating-a-potential-leak, or damaged insulation. The staff found that the Systems

Monitoring Program would be able to detect any corrosion on the external surfaces of these

components.

Carbon/low-alloy steel and cast iron/cast iron alloy components exposed to air/gas are

susceptible to loss of material due to general corrosion. In LRA Table 3.2.2.5, the applicant

credited the One-Time Inspection Program to manage loss of material in these components.

This aging effect is not in the GALL Report for this component, material, and environment

combination. The one-time inspection provides the opportunity to visually inspect the internal

surfaces of components during preventive and corrective maintenance activities. The staff

found the One-Time Inspection Program acceptable for managing the aging effect of loss of

material.

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 during the

period of extended operation, as required by 10 CFR 54.21(a)(3).

3.2.2.3.6 Containment Inerting System – Summary of Aging Management Evaluation –

Table 3.2.2.6

The staff reviewed LRA Table 3.2.2.6, which summarizes the results of AMR evaluations for the

containment inerting system component groups.

In LRA Table 3.2.2.6, the applicant identified no aging effects in containment inerting system

component groups made of aluminum, carbon and low-alloy steel, copper alloys, nickel alloys,

and stainless steel carrying air/gas or exposed to inside air. These environment conditions are

not identified in the GALL Report for these components and materials. On the basis of current

industry research and operating experience, dry air on metal will not result in aging that will be
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of concern during the period of extended operation. The external environments being referred

to are typical of ambient air (e.g., under a shelter, indoors, or air-conditioned enclosure or

room). Significant corrosion requires an electrolytic environment, and a simultaneous presence

of oxygen and moisture. Without the presence of an aggressive environment, these

components experience insignificant amounts of corrosion, and no aging effects are applicable

to this component/commodity group; therefore, the staff concluded that there are no applicable

aging effects for these material and environment combinations.

Carbon/low-alloy steel and cast iron/cast iron alloy components exposed to air/gas are

susceptible to loss of material due to general corrosion. In LRA Table 3.2.2.6, the applicant

credited the One-Time Inspection Program to manage loss of material in these components.

This aging effect is not in the GALL Repot for this component, material, and environment

combination. The one-time inspection provides the opportunity to visually inspect the internal

surfaces of components during preventive and corrective maintenance activities. The staff

found the One-Time Inspection Program acceptable for managing the aging effect of loss of

material.

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 during the

period of extended operation, as required by 10 CFR 54.21(a)(3).

3.2.2.3.7 Containment Atmosphere Dilution System – Summary of Aging Management

Evaluation – Table 3.2.2.7

The staff reviewed LRA Table 3.2.2.7, which summarizes the results of AMR evaluations for the

containment atmosphere dilution system component groups.

In LRA Table 3.2.2.7, the applicant identified no aging effects in containment inerting system

component groups made of aluminum, cast iron alloys, copper alloys, and stainless steel

carrying air/gas or exposed to inside air. These environment conditions are not identified in the

GALL Report for these components and materials. On the basis of current industry research

and operating experience, dry air on metal will not result in aging that will be of concern during

the period of extended operation. The external environments being referred to are typical of

ambient air (e.g., under a shelter, indoors, or air-conditioned enclosure or room). Significant

corrosion requires an electrolytic environment, and a simultaneous presence of oxygen and

moisture. Without the presence of an aggressive environment, these components experience

insignificant amounts of corrosion, and no aging effects are applicable to this

component/commodity group; therefore, the staff concluded that there are no applicable aging

effects for these material and environment combinations.

Carbon/low-alloy steel and cast iron alloy components exposed to air/gas are susceptible to

loss of material due to general corrosion. In LRA Table 3.2.2.7, the applicant credited the

One-Time Inspection Program to manage loss of material in these components. This aging

effect is not in the GALL Report for this component, material, and environment combination.

The one-time inspection provides the opportunity to visually inspect the internal surfaces of

components during preventive and corrective maintenance activities. The staff found the

One-Time Inspection Program acceptable for managing the aging effect of loss of material.
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Carbon/low-alloy steel and cast iron alloy components’ external surfaces exposed to inside air

are managed by the Systems Monitoring Program against any loss of material due to general

corrosion. The system walkdown encompasses all or part of the total accessible system such

that the entire system is covered over time. The walkdown is a detailed look at system

parameters, material condition, operation, configuration, degraded components, outstanding

work activities, and design changes. The material condition involves no missing,

discolored-indicating-a-potential-leak, or damaged insulation. The staff found that the Systems

Monitoring Program would be able to detect any corrosion on the external surfaces of these

components.

In LRA Table 3.2.2.7, piping and fittings made of stainless steel buried in soil are susceptible to

loss of material due to MIC, crevice, general, and pitting corrosion as well as cracking due to

SCC. The applicant credited the Buried Piping and Tanks Inspection Program to manage this

aging effect. During the GALL consistency audit the staff requested the applicant to describe

how this AMP would detect cracking in buried piping, if this is an applicable aging effect. By

letter dated October 8, 2004, the applicant submitted its formal response to the staff’s audit

question, stating that, in Table 3.2.2.7, line items 12 and 22 identify cracking for buried stainless

steel piping and fittings and should be deleted. This line’s temperature is less than 140 °F and,

therefore, is not subject to stress corrosion cracking. This is the only place in the LRA where

the buried tank and piping inspection program was credited for detecting cracking. Therefore,

the buried tank and piping inspection program does not detect cracking. The staff found the

above explanation acceptable.

The buried tank and piping inspection AMP involves preventive measures to mitigate corrosion

(external coatings and wrappings applied in accordance with standard industry practices) and

condition monitoring to manage the effects of corrosion. Buried piping is inspected when

excavated for any reason, typically for maintenance. The inspections are performed as part of

the 10 CFR 50.65, “Maintenance Rule Program.” The inspections provide for determination of

degradation due to the loss of, or damage to, the protective coatings and wraps used for

corrosion control on buried pipe external surfaces. The inspections also include connections

and joints for signs of separation, environmental degradation, leakage, and for appreciable

settlement between piping segments. The staff found this inspection program acceptable for

managing the aging effect of loss of material.

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 during the

period of extended operation, as required by 10 CFR 54.21(a)(3).

Conclusion. On the basis of its review, the staff found that the applicant had appropriately

evaluated AMR results involving MEAP combinations that are not evaluated in the GALL

Report. The staff found that the applicant 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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3.2.3 Conclusion

The staff concluded that the applicant had provided sufficient information to demonstrate that

the effects of aging for the of the ESF systems components that are within the scope of license

renewal and subject to an AMR will be adequately managed so that the intended function(s) will

be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3). The staff also reviewed the applicable UFSAR supplement program

summaries and concluded that they adequately describe the AMPs credited for managing aging

of the ESF systems, as required by 10 CFR 54.21(d).
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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:

 • auxiliary boiler

 • fuel oil

 • residual heat removal service water

 • raw cooling water

 • raw service water

 • high pressure fire protection

 • potable water

 • ventilation

 • heating, ventilation, and air conditioning (HVAC)

 • control air

 • service air

 • CO2

 • station drainage

 • sampling and water quality

 • building heat

 • raw water chemical treatment

 • demineralizer backwash air

 • standby liquid control

 • off-gas

 • emergency equipment cooling water

 • reactor water cleanup

 • reactor building closed cooling water

 • reactor core isolation cooling

 • auxiliary decay heat removal

 • radioactive waste treatment

 • fuel pool cooling and cleanup

 • fuel handling and storage

 • diesel generator

 • control rod drive (CRD)

 • diesel generator starting air

 • radiation monitoring

 • neutron monitoring

 • traversing in-core probe

 • cranes

3.3.1 Summary of Technical Information in the Application

In LRA Section 3.3, the applicant provided AMR results for components. In LRA Table 3.3.1,

“Summary of Aging Management Evaluations for Auxiliary Systems Evaluated in Chapter VII of

NUREG-1801,” 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.
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The applicant’s AMRs incorporated applicable operating experience in the determination of

AERMs. These reviews included evaluation of plant-specific and industry operating experience.

The plant-specific evaluation included reviews of condition reports and discussions with

appropriate site personnel to identify AERMs. The applicant’s review of industry operating

experience included a review of the GALL Report and operating experience issues identified

since the issuance of the GALL Report.

3.3.2 Staff Evaluation

The staff reviewed LRA Section 3.3 to determine if the applicant had provided sufficient

information to demonstrate that the effects of aging for the auxiliary systems components that

are within the scope of license renewal and subject to an AMR will be adequately managed so

that the intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21(a)(3).

The staff performed an onsite audit, during the weeks of June 21 and July 26, 2004, 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. Detail of the staff’s audit evaluation are documented in the audit and review

report and are summarized in SER Section 3.3.2.1.

In the onsite audit, the staff also included 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 are consistent with the acceptance criteria in SRP-LR

Section 3.3.2.2. The staff’s audit evaluations are documented in the audit and review report and

are summarized in SER Section 3.3.2.2.

During the staff’s onsite audit, the staff also conducted a technical review of the remaining

AMRs that are 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 audit and review

report and are 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 UFSAR supplement to ensure

that they provided an adequate description of the programs credited with managing or

monitoring aging for the auxiliary systems components.

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

Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

Components in

spent fuel pool

cooling and cleanup

(Item Number

3.3.1.1)

Loss of material

due to general,

pitting, and crevice

corrosion

Chemistry Control

Program; One-Time

Inspection Program

Chemistry Control

Program; One-Time

Inspection Program

Consistent with

GALL, which

recommends further

evaluation (See

Section 3.3.2.2.1)

Linings in spent fuel

pool cooling and

cleanup system;

seals and collars in

ventilation systems

(Item Number

3.3.1.2)

Hardening, cracking

and loss of strength

due to elastomer

degradation; loss of

material due to

wear

Plant-specific Systems Monitoring

Program

(See Section

3.3.2.2.2)

Components in load

handling, chemical

and volume control

system (PWR), and

reactor water

cleanup and

shutdown cooling

systems (older

BWR)

(Item Number

3.3.1.3)

Cumulative fatigue

damage

TLAA, evaluated in

accordance with

10 CFR 54.21(c)

TLAA This TLAA is

evaluated in

Section 4.7, Other

Plant-Specific

Analyses, and in

Section 4.3, Metal

Fatigue

BFN does not have

a chemical and

volume control

system or a

shutdown cooling

system

Heat exchangers in

reactor water

cleanup system

(BWR); high

pressure pumps in

chemical and

volume control

system (PWR)

(Item Number

3.3.1.4)

Crack initiation and

growth due to SCC

or cracking

Plant-specific Chemistry Control

Program; One-Time

Inspection Program

(See Section

3.3.2.2.4)

Components in

ventilation systems,

diesel fuel oil

system, and

emergency diesel

generator systems;

external surfaces of

carbon steel

components

(Item Number

3.3.1.5)

Loss of material

due to general,

pitting, and crevice

corrosion; MIC

Plant-specific Chemistry Control

Program; One-Time

Inspection Program

(See Section

3.3.2.2.4)
Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

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Components in

reactor coolant

pump oil collect

system of fire

protection

(Item Number

3.3.1.6)

Loss of material

due to galvanic,

general, pitting, and

crevice corrosion

One-Time

Inspection

N/A Not applicable

BFN does not have

an oil collection

system for its

reactor recirculation

pumps

Diesel fuel oil tanks

in diesel fuel oil

system and

emergency diesel

generator system

(Item Number

3.3.1.7)

Loss of material

due to general,

pitting, and crevice

corrosion, MIC, and

biofouling

Fuel Oil Chemistry

Program; One-Time

Inspection Program

Fuel Oil Chemistry

Program; One-Time

Inspection Program

Consistent with

GALL, which

recommends further

evaluation (See

Section 3.3.2.2.7)

Piping, pump

casing, and valve

body and bonnets in

shutdown cooling

system (older BWR)

(Item Number

3.3.1.8)

Loss of material

due to pitting and

crevice corrosion

Chemistry Control

Program; One-Time

Inspection Program

Chemistry Control

Program; One-Time

Inspection Program

Not applicable

BFN is not an older

BWR with a

shutdown cooling

system

The shutdown

cooling system is

performed by the

RHR system (See

Section 3.3.2.3.3)

Neutron absorbing

sheets in spent fuel

storage racks

(Item Number

3.3.1.10)

Reduction of

neutron absorbing

capacity and loss of

material due to

general corrosion

(Boral, boron steel)

Plant-specific Chemistry Control

Program

(See Section

3.3.2.2.10)

New fuel rack

assembly (Item

Number 3.3.1.11)

Loss of material

due to general,

pitting, and crevice

corrosion

Structures

Monitoring Program

Structures

Monitoring Program

Consistent with

GALL, which

recommend no

further evaluation

(See Section

3.3.2.1)

Neutron absorbing

sheets in spent fuel

storage racks

(Item Number

3.3.1.12)

Reduction of

neutron absorbing

capacity due to

Boraflex

degradation

Boraflex Monitoring

Program

N/A Not applicable

BFN uses Boral as

the spent fuel

storage rack

neutron absorber

Spent fuel storage

racks and valves in

spent fuel pool

cooling and cleanup

(Item Number

3.3.1.13)

Crack initiation and

growth due to stress

corrosion cracking

Chemistry Control

Program

Chemistry Control

Program

Consistent with

GALL, which

recommends no

further evaluation

(See Section 

3.3.2.1)
Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

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Components in or

serviced by

closed-cycle cooling

water system

(Item Number

3.3.1.15)

Loss of material

due to general,

pitting, and crevice

corrosion; MIC

Closed-Cycle

Cooling Water

System

Closed-Cycle

Cooling Water

System

Consistent with

GALL, which

recommends no

further evaluation

(See Section

3.3.2.1)

Cranes including

bridge and trolleys

and rail system in

load handling

system

(Item Number

3.3.1.16)

Loss of material

due to general

corrosion and wear

Overhead Heavy

Load and Light

Load Handling

Systems

Overhead Heavy

Load and Light

Load Handling

Systems

Consistent with

GALL, which

recommends no

further evaluation

(See Section

3.3.2.1)

Components in or

serviced by

open-cycle cooling

water systems

(Item Number

3.3.1.17)

Loss of material

due to general,

pitting, crevice, and

galvanic corrosion,

MIC, and biofouling;

buildup of deposit

due to biofouling

Open-Cycle Cooling

Water System

Open-Cycle Cooling

Water System

Consistent with

GALL, which

recommends no

further evaluation

(See Section

3.3.2.1)

Buried piping and

fittings

(Item Number

3.3.1.18)

Loss of material

due to general,

pitting, and crevice

corrosion; MIC

Buried Piping and

Tanks Surveillance

Program; Buried

Piping and Tanks

Inspection Program

Buried Piping and

Tanks Inspection

Program

(See Section

3.3.2.2.11)

Components in

compressed air

system

(Item Number

3.3.1.19)

Loss of material

due to general and

pitting corrosion

Compressed Air

Monitoring Program

Compressed Air

Monitoring Program

Consistent with

GALL, which

recommends no

further evaluation

(See Section

3.3.2.1)

Components (doors

and barrier

penetration seals)

and concrete

structures in fire

protections

(Item Number

3.3.1.20)

Loss of material

due to wear;

hardening and

shrinkage due to

weathering

Fire Protection

Program

Fire Protection

Program

Consistent with

GALL, with

exceptions, which

recommends no

further evaluation

(See Section

3.3.2.1)

Components in

water-based fire

protection

(Item Number

3.3.1.21)

Loss of material

due to general,

pitting, crevice, and

galvanic corrosion,

MIC, and biofouling

Fire Water System Fire Water System Consistent with

GALL, which

recommends no

further evalation

(See Section

3.3.2.1)
Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

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Components in

diesel fire system

(Item Number

3.3.1.22)

Loss of material

due to galvanic,

general, pitting, and

crevice corrosion

Fire Protection

Program; Fuel Oil

Chemistry Program

Fire Protection

Program; Fuel Oil

Chemistry Program

Consistent with

GALL, with

exceptions, which

recommends no

further evaluation

(See Section

3.3.2.1)

Tanks in diesel fuel

oil system 

(Item Number

3.3.1.23)

Loss of material

due to general,

pitting, and crevice

corrosion

Above Ground

Carbon Steel Tanks

Program

Above Ground

Carbon Steel Tanks

Program

Consistent with

GALL, with

exceptions, which

recommends no

further evaluation

(See Section

3.3.2.1)

Closure bolting

(Item Number

3.3.1.24)

Loss of material

due to general

corrosion; crack

initiation and growth

due to cyclic

loading and SCC

Bolting Integrity

Program

Bolting Integrity

Program

Consistent with

GALL, with

exceptions, which

recommends no

further evaluation

(See Section

3.3.2.1)

Components in

contact with sodium

pentaborate

solution in standby

liquid control

system (BWR)

(Item Number

3.3.1.25)

Crack initiation and

growth due to SCC

Chemistry Control

Program

Chemistry Control

Program

Consistent with

GALL, with

exceptions, which

recommend no

further evaluation

(See Section

3.3.2.1)

Components in

reactor water

cleanup system

(Item Number

3.3.1.26)

Crack initiation and

growth due to SCC

and IGSCC

Reactor Water

Cleanup System

Inspection Program

BWR Reactor

Water Cleanup

System Program

The NUREG-1801

XI.M25 Reactor

Water Cleanup

system AMP

provides criteria for

which inspections

are not

recommended.

Since BFN meets

these criteria,

inspections will not

be conducted (See

Section 3.0.3.2.15)
Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

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Components in

shutdown cooling

system (older BWR)

(Item Number

3.3.1.27)

Crack initiation and

growth due to SCC

BWR Stress

Corrosion Cracking

Program; Chemistry

Control Program

N/A Not applicable

BFN is not an older

BWR with a

shutdown cooling

system. The

shutdown cooling

function is

performed by the

RHR system (See

Section 3.3.2.3.3)

Components in

shutdown cooling

system (older BWR)

(Item Number

3.3.1.28)

Loss of material

due to pitting and

crevice corrosion,

and MIC

Closed-Cycle

Cooling Water

System

N/A Not applicable

BFN is not an older

BWR with a

shutdown cooling

system. The

shutdown cooling

function is

performed by the

RHR system (See

Section 3.3.2.3.3)

Components

(aluminum, bronze,

brass, cast iron,

cast steel) in

open-cycle and

closed-cycle cooling

water systems, and

ultimate heat sink

Loss of material

due to selective

leaching

Selective Leaching

of Materials

Program

Selective Leaching

of Materials

Program

Consistent with

GALL, which

recommend no

further evaluation

(See Section

3.3.2.1)

Fire barriers, walls,

ceilings, and floors

in fire protection

Concrete cracking

and spalling due to

freeze-thaw,

aggressive

chemical attack,

and reaction with

aggregates; loss of

material due to

corrosion of

embedded steel

Fire Protection

System; Structures

Monitoring System

Fire Protection

System; Structures

Monitoring System

Consistent with

GALL, with

exceptions, which

recommends no

further evaluation

(See Section

3.3.2.1)

The staff’s review of the BFN component groups 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, or not addressed in, the GALL Report. The staff’s review of
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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 Application. 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:

 • Bolting Integrity Program (B.2.1.16)

 • One-Time Inspection Program (B.2.1.29)

 • Selective Leaching of Materials Program (B.2.1.30)

 • Systems Monitoring Program (B.2.1.39)

 • Buried Piping and Tanks Inspection Program (B.2.1.25)

 • Fuel Oil Chemistry Program (B.2.1.27)

 • Chemistry Control Program (B.2.1.5)

 • Open-Cycle Cooling Water System Program (B.2.1.17)

 • Closed-Cycle Cooling Water System Program (B.2.1.18)

 • Fire Water System Program (B.2.1.24)

 • Fire Protection Program (B.2.1.23)

 • Compressed Air Monitoring Program (B.2.1.21)

 • ASME Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program

(B.2.1.4)

 • BWR Stress Corrosion Cracking Program (B.2.1.10)

 • BWR Reactor Water Cleanup System Program (B.2.1.22)

 • Flow-accelerated Corrosion Program (B.2.1.15)

 • Inspection of Overhead Heavy Load and Light Load Handling Systems Program

(B.2.1.20)

 • Diesel Starting Air Program (B.2.1.41)

Staff Evaluation. In LRA Tables 3.3.2-1 through 3.3.2-34, the applicant provided a summary of

AMRs for the auxiliary systems components, and identified which AMRs it considered to be

consistent with the GALL Report.

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 audited those AMRs with

Notes A through E, which indicated that 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
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identified in the GALL Report. The staff audited these line items to verify consistency with the

GALL Report and the validity of the AMR for the site-specific conditions.

Note B 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 is different from but consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent

with the AMP identified by the GALL Report. This note indicates that the applicant 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 is different from but consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP takes some

exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify

consistency with the GALL Report. The staff 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 the BFN 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.

The staff conducted an audit and review of the information provided in the LRA, as documented

in the BFN 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
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effects were reviewed and 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, 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 concluded that the AMR results that the applicant claimed to be consistent with the GALL

Report are, in fact, consistent with the AMRs in the GALL Report. Therefore, the staff

concluded 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 CFR54.21(a)(3).

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

Evaluation is Recommended

Summary of Technical Information in the Application. In LRA Section 3.3.2.2, the applicant

provided further evaluation of aging management as recommended by the GALL Report for the

auxiliary systems. The applicant provided information concerning how it will manage the

following aging effects:

 • loss of material due to general, pitting, and crevice corrosion

 • hardening and cracking or loss of strength due to elastomer degradation or loss of

material due to wear

 • cumulative fatigue damage

 • crack initiation and growth due to cracking or stress corrosion cracking

 • loss of material due to general, microbiologically influenced, pitting, and crevice

corrosion

 • loss of material due to general, galvanic, pitting, and crevice corrosion

 • loss of material due to general, pitting, crevice, and microbiologically influenced

corrosion and biofouling

 • quality assurance for aging management of non-safety-related components

 • cracking 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 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
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applicant’s further evaluations against the criteria in SRP-LR Section 3.3.2.2. Details of the

staff’s audit are documented in the staff’s BFN audit and review report. The staff’s evaluation of

the aging effects is discussed in the following sections.

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 the further evaluation of programs to manage

loss of material in components of the spent fuel pool cooling and cleanup 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 tubesheets of the heat

exchanger in the spent fuel pool cooling and cleanup system. The Chemistry Control Program

relies on monitoring and control of reactor water chemistry based on EPRI guidelines of

TR-105714 for primary water chemistry and TR-102134 for secondary water chemistry to

manage the effects of loss of material from general, pitting or crevice corrosion. However, high

concentrations of impurities at crevices and locations of stagnant flow conditions could cause

general, pitting, or crevice corrosion. Therefore, verification of the effectiveness of the

chemistry control program should be performed to ensure that corrosion is not occurring. The

GALL Report recommends further evaluation of programs to manage loss of material from

general, pitting, and crevice corrosion to verify the effectiveness of the Chemistry Control

Program. A one-time inspection of select components at susceptible locations is an acceptable

method for ensuring that corrosion is not occurring and that the component's intended function

will be maintained during the period of extended operation. No loss of material aging effects are

observed for stainless steel components exposed to air.

Further, SRP-LR Section 3.3.2.2.1 states that loss of material due to pitting and crevice

corrosion could occur in the filter housing, valve bodies, and nozzles of the ion exchanger in the

spent fuel pool cooling and cleanup system. The Chemistry Control Program relies on

monitoring and control of reactor water chemistry based on EPRI guidelines of TR-105714 for

primary water chemistry and TR-102134 for secondary water chemistry to manage the effects

of loss of material from pitting or crevice corrosion. However, high concentrations of impurities

at crevices and locations of stagnant flow conditions could cause pitting, or crevice corrosion.

Therefore, verification of the effectiveness of the Chemistry Control Program should be

performed to ensure that corrosion is not occurring. The GALL Report recommends further

evaluation of programs to manage loss of material from pitting and crevice corrosion to verify

the effectiveness of the Chemistry Control Program. A one-time inspection of select

components at susceptible locations is an acceptable method to ensure that corrosion is not

occurring and that the component's intended function will be maintained during the period of

extended operation.

The applicant stated that the portion of the fuel pool cooling and cleanup (FPC) system that

contains components requiring an AMR includes the water filled piping within the reactor

building, and the applicant credited the Chemistry Control Program and One-Time Inspection

Program to manage loss of material. The Chemistry Control Program is credited with managing

loss of material for stainless steel components in this portion of the spent fuel pool cooling and

cleanup system that are exposed to treated water. The One-Time Inspection Program, which

addresses the verification program recommendation in the GALL Report, provides for the
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inspection of systems to verify that AMPs are effective and that aging effects are not occurring.

This is consistent with the GALL Report and acceptable to the staff.

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 3.3.2.2.2.

In LRA Section 3.3.2.2.2, the applicant addressed the further evaluation of programs to manage

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 and in

the collars and seals of the duct in the diesel generator building ventilation system. Loss of

material due to wear could occur in the collars and seals of the duct in the ventilation systems.

The GALL Report recommends further evaluation to ensure that these aging effects are

adequately managed.

In LRA Section 3.3.2.2.2, the applicant stated that elastomers are not used in components

subject to an AMR in the spent fuel cooling and cleanup system. The applicant also stated that

for the ventilation systems, hardening and loss of strength due to elastomer degradation is

dependent on environmental conditions. The applicant also stated that loss of material due to

wear of elastomer components is managed by the systems monitoring program if the

environmental threshold is exceeded. The staff found this acceptable. 

The staff noted that LRA Table 3.3.2.28 identifies elastomer degradation due to thermal

exposure as an AERM for flexible connectors in the diesel generator ventilation system having

an internal environment of air/gas. The applicant credited the One-Time Inspection Program to

manage this aging effect and claimed consistency with GALL Report, Item VII.F4.1-b,

referencing Table 3.2.1, Item 3.3.1.2. However, Table 3.2.1, Item 3.3.1.2 refers to the further

evaluation in LRA Section 3.3.2.2.2, which states that the Systems Monitoring Program will be

used to manage hardening and loss of strength of elastomers in ventilation systems. The staff

during the onsite audit requested the applicant to explain why the One-Time Inspection

Program was credited for managing elastomer aging for flexible connectors in the diesel

generator ventilation system. In its formal response, by letter dated October 8, 2004, the

applicant stated that the One-Time Inspection Program is credited for the inspection of

elastomers where the degradation mechanism may be internal. The Systems Monitoring

Program is credited for the inspection of elastomers where the degradation mechanism may be

external. The applicant stated that LRA Section 3.3.2.2.2 should include a discussion of the

One-Time Inspection Program for internal surfaces of elastomers. If degradation is found to be

present, additional inspections and corrective actions may be required by the One-Time

Inspection Program. The staff found this acceptable. 
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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 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 3.3.2.2.4.

In LRA Section 3.3.2.2.4, the applicant addressed the further evaluation of programs to manage

the potential for cracking in the regenerative and non-regenerative heat exchanger components

in the reactor water cleanup system.

SRP-LR Section 3.3.2.2.4 addresses crack initiation and growth due to SCC in the regenerative

and non-regenerative heat exchanger components in the reactor water cleanup system. The

GALL Report recommends further evaluation to ensure that these aging effects are managed

adequately.

The applicant stated that it uses the Chemistry Control Program and the One-Time Inspection

Program to manage cracking and SCC of these stainless steel components. In the ESF section

of the GALL Report, Volume 2, Item V.D2.1-c, the management of stainless steel components

performing a pressure boundary function is addressed by using the Chemistry Control Program.

Therefore, the applicant’s use of the Chemistry Control Program to manage crack initiation and

growth due to SCC is consistent with the GALL Report and, therefore, is acceptable to the staff.

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 3.3.2.2.5.

In LRA Section 3.3.2.2.5, the applicant addressed the further evaluation of programs to manage

the loss of material from corrosion that could occur on internal and external surfaces of

components exposed to air and the associated range of atmospheric conditions.

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; the

piping of the diesel generator building ventilation system; 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 EDG 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 materials due to pitting and crevice

corrosion could occur in the heating/cooling coils of the air handler heating/cooling. Loss of

material due to general corrosion could occur on the external surfaces of all carbon steel SCs,

including bolting exposed to operating temperatures less than 212 °F in the ventilation systems.

The GALL Report recommends further evaluation to ensure that these aging effects are

adequately managed.
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The applicant credited the One-Time Inspection Program for managing loss of material due to

corrosion of carbon and low-alloy steel, cast iron/cast iron alloy, and copper alloy components

in the off-gas, heating, ventilation, and air conditioning, diesel generator, reactor core isolation

cooling, raw cooling water, diesel generator starting air, ventilation, standby liquid control, and

demineralizer backwash air systems with internal surfaces exposed to air/gas. The staff found

this acceptable.

The applicant credited the Systems Monitoring Program for managing loss of material due to

corrosion of carbon and low-alloy steel components in the auxiliary boiler, fuel oil, RHRSW, raw

cooling water, raw service water, high pressure fire protection, potable water ventilation, HVAC,

control air, service air, CO2, station drainage, sampling and water quality, building heat, raw

water chemical treatment, demineralizer backwash air, standby liquid control, off-gas,

emergency equipment cooling water, reactor water cleanup, reactor building closed cooling

water, reactor core isolation cooling, radioactive waste treatment, fuel pool cooling and cleanup,

diesel generator, CRD, diesel generator starting air, and radiation monitoring systems with

external surfaces exposed to air. The staff found this acceptable.

The applicant credited the Diesel Starting Air Program for managing loss of material due to

corrosion of carbon and low-alloy steel components in the diesel generator starting air system

with internal surfaces exposed to air/gas. The staff found this acceptable.

The staff noted that LRA Table 3.3.2.28 identifies loss of material due to crevice, general, and

pitting corrosion as an AERM for carbon and low-alloy steel components in a treated water

environment. LRA Table 3.2.1, Item 3.3.1.5 is referenced and consistency with the GALL

Report is noted. The Closed-Cycle Cooling Water Program is credited for managing this aging

effect. However, LRA Table 3.2.1, Item 3.3.1.5 references the further evaluation in 3.3.2.2.5,

which pertains to components in an air environment, and does not include the Closed-Cycle

Cooling Water Program as one of the programs to manage aging. The staff inquired as to why

LRA Table 3.2.1, Item 3.3.1.5 was referenced for these components. By letter dated October 8,

2004, the applicant submitted its formal response to the staff, stating that LRA Table 3.3.2.28

for the diesel generator system has six line items with a treated water environment that match

the GALL Report. The correct GALL Report, Volume 1, Table 1 reference for the items that

match the GALL Report is Item 3.3.1.15. Five of the LRA Table 3.3.2.28 treated water line

items correctly reference 3.3.1.15; one incorrectly references 3.3.1.5. The reference to 3.3.1.5

should be 3.3.1.15. The staff reviewed this response and concluded that it is acceptable.

3.3.2.2.6 Loss of Material due to General, Galvanic, Pitting, and Crevice Corrosion

In LRA Section 3.3.2.2, the applicant addressed the further evaluation of programs to manage

loss of material in the reactor coolant pump oil collection system to verify the effectiveness of

the Fire Protection Program. The applicant stated that this aging effect is not applicable to BFN

since the BFN design does not include a recirculation pump oil collection system. The staff

concluded that this is acceptable since the BFN design does not include a reactor coolant pump

oil collection system.
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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 3.3.2.2.7.

In LRA Section 3.3.2.2.7, the applicant addressed the further evaluation of programs to manage

loss of material in the diesel fuel oil system to verify the effectiveness of the diesel fuel

monitoring program.

SRP-LR Section 3.3.2.2.7 states that loss of material due to general, pitting, and crevice

corrosion, MIC, and biofouling could occur in the internal surface of tanks in the diesel fuel oil

system and due to general, pitting, and crevice corrosion and MIC in the tanks of the diesel fuel

oil system in the EDG system. The existing AMP relies on the Fuel Oil Chemistry Program for

monitoring and control of fuel oil contamination in accordance with the guidelines of ASTM

Standards D4057, D1796, D2709 and D2276 to manage loss of material due to corrosion or

biofouling. Corrosion or biofouling may occur at locations where contaminants accumulate.

Verification of the effectiveness of the chemistry control program should be performed to

ensure that corrosion is not occurring. The GALL Report recommends further evaluation of

programs to manage corrosion/biofouling to verify 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.

In LRA Section 3.3.2.2.7, the applicant stated that it uses the Fuel Oil Chemistry Program to

manage loss of material for the diesel fuel oil system. In addition, the applicant will use the

One-Time Inspection Program to verify the effectiveness of the fuel oil chemistry program. The

inspection will ensure that corrosion is not occurring at locations where contaminants

accumulate. The One-Time Inspection Program addresses the one-time inspection

recommendation in the GALL Report.

The staff reviewed the Fuel Oil Chemistry Program and found that the program will adequately

manage the effects of aging so that the intended functions will be maintained. The staff also

reviewed the One-Time Inspection Program, which will be used to verify the effectiveness of the

Fuel Oil Chemistry Program.

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 Cracking Initiation and Growth due to Stress Corrosion Cracking and Cyclic Loading

Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not

applicable to BFN.
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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 3.3.2.2.10.

In LRA Section 3.3.2.2.10, the applicant addressed the further evaluation of programs to

manage reduction of neutron-absorbing capacity and loss of material due to general corrosion,

which could occur in the neutron absorbing sheets of the spent fuel storage rack in the spent

fuel storage.

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. The GALL Report recommends further evaluation to

ensure that these aging effects are adequately managed.

The applicant stated that boral is used as a neutron absorbing material in the spent fuel pools.

Reduction of neutron absorbing capacity and loss of material due to general corrosion could

occur in the boral neutron absorbing material in spent fuel storage racks. The Chemistry

Control Program manages general corrosion. An inspection of boral coupon test specimens

was performed that confirmed no significant aging degradation had occurred and the neutron

absorbing capability of the boral had not been reduced. Reduction of neutron absorbing

capacity and loss of material due to general corrosion will be managed by the Chemistry

Control Program. 

The staff reviewed the Chemistry Control Program and found that the program will adequately

manage the effects of aging so that the intended functions will be maintained. 

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 3.3.2.2.11.

In LRA Section 3.3.2.2.11, the applicant addressed the further evaluation of programs to

manage the potential for loss of material in buried piping of the service water and diesel fuel oil

systems.

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 OCCW 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 applicant credited the Buried Piping and Tanks Inspection Program for managing loss of

material for buried components of the service water and diesel fuel oil systems. This is

consistent with GALL AMP XI.M34, “Buried Piping Inspection.” The staff reviewed the

applicant's operating history and found that the frequency of pipe excavation was sufficient to
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manage the effects of loss of material. The staff reviewed the Buried Piping Inspection Program

and concluded that it is acceptable.

3.3.2.2.12 Evaluation of Auxiliary Systems AMRs That Reference Further Evaluations Not

Included Under Auxiliary Sysyems

In the AMR for components in the auxiliary systems, the applicant referenced several further

evaluations that are included under systems other than the auxiliary systems. These further

evaluations were referenced based on applicability to the material, environment, and aging

effect identified for components in the auxiliary systems. The staff reviewed these further

evaluations for applicability to the auxiliary systems; the assessment is documented in the

following subsections.

Crack Initiation and Growth due to SCC, IGSCC, and Thermal and Mechanical Loading. In LRA

Section 3.1.2.2.4, the applicant addressed the further evaluation of programs to manage crack

initiation and growth due to thermal and mechanical loading or stress corrosion cracking of

components in the reactor coolant system. This aging effect is referenced in LRA Table 3.2.1,

Item 3.1.1.7, which the applicant referenced in the auxiliary systems AMRs for components in

the sampling and water quality, standby liquid control, reactor water cleanup, reactor core

isolation cooling, and neutron monitoring systems. 

The staff noted that the LRA identifies crack initiation/growth due to cyclic loading as an AERM

for various mechanical components in the sampling and water quality, standby liquid control,

reactor water cleanup, reactor core isolation cooling, and neutron monitoring systems. The

ASME ISI Program and One-Time Inspection Program are credited to manage this aging effect.

The staff noted similar entries in the AMRs for the ESF systems and the reactor coolant

system. The staff inquired as to why the Chemistry Control Program had been not included to

manage this aging effect for these components since the Chemistry Control Program is

included in the further evaluation in LRA Section 3.1.2.2.4. The applicant's response and the

staff's evaluation are addressed in SER Section 3.1.2.2.4.

Loss of Material due to General Corrosion. In LRA Section 3.2.2.2.2, the applicant addressed

the further evaluation of programs to manage loss of material due to general corrosion for

components in the ESF systems. This aging effect is referenced in LRA Table 3.2.1, Items

3.2.1.2, 3.2.1.3, and 3.2.1.10, which the applicant referenced in the auxiliary systems AMRs for

components in the auxiliary boiler, raw service water, potable water, service air, station

drainage, sampling and water quality, building heat, demineralizer backwash air, off-gas,

reactor core isolation cooling, radioactive waste treatment, CRD, and radiation monitoring

systems. The staff reviewed the applicant's further evaluation for this aging effect in SER

Section 3.2.2.2.

The staff noted that the LRA identifies loss of material due to general, crevice, and pitting

corrosion as an AERM for mechanical components in a treated water environment in the

radioactive waste treatment system (LRA Table 3.3.2.25). LRA Table 3.2.1, Items 3.2.1.3 and

3.2.1.5 are referenced and consistency with the GALL Report is noted. The One-Time

Inspection Program is credited for managing this aging effect; however, the further evaluation in

the LRA Section 3.2.2.2.2 identifies the Chemistry Control Program for managing the effects of

corrosion for components in a treated water environment. During the onsite audit, the staff

inquired as to the technical basis for using the One-Time Inspection Program alone to manage
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aging due to corrosion for components in a treated water environment, instead of the Chemistry

Control program. By letter dated October 8, 2004, the applicant submitted its formal response

to the staff, stating that the treated water in the radioactive waste treatment system is waste

that was generated from systems that contain chemistry control treated water; however, once

this water becomes a waste steam, the chemistry can no longer be controlled. Since the

portions of the system exposed to treated water have their water source from chemistry control

systems, the potential for corrosion is low. The One-Time Inspection Program will verify this by

performing a sampling inspection. If corrosion is found to be present, additional inspections and

corrective actions may be required by the One-Time Inspection Program. 

The staff reviewed the applicant's response and concluded that it is acceptable since the water

in the radioactive waste treatment system is waste that was generated from systems that

contain chemistry control treated water. Once the treated water becomes a waste stream the

chemistry can no longer be controlled, which is why the Chemistry Control Program is not

credited for this aging effect. The potential for corrosion is low for these components and the

One-Time Inspection Program will be performed to verify that corrosion is not occurring. 

The staff noted that LRA Tables 3.3.2.3, 3.3.2.5, 3.3.2.14, 3.3.2.21, and 3.3.2.25 identify loss of

material due to biofouling, MIC, crevice corrosion, general corrosion, and pitting corrosion as an

AERM for stainless steel components in a raw water environment. LRA Table 3.2.1, Items

3.2.1.3, 3.2.1.5, and 3.2.1.6 are referenced and consistency with the GALL Report is noted.

LRA Table 3.2.1, Items 3.2.1.3, 3.2.1.5 and 3.2.1.6 reference further evaluations in LRA

Sections 3.2.2.2.2. 3.2.2.2.3, and 3.2.2.2.4, respectively. However, LRA Sections 3.2.2.2.2 and

3.2.2.2.3 pertain to components in treated water, for which the Chemistry Control and

One-Time Inspection Programs are identified to manage this aging effect. Only LRA

Section 3.2.2.2.4 pertains to components in raw water. The staff asked why LRA Table 3.2.1,

Items 3.2.1.3 and 3.2.1.5 are referenced for these components. The staff also inquired as to

the technical basis for using the One-Time Inspection Program to manage aging due to MIC for

the components in Table 3.3.2.25 instead of the Open-Cycle Cooling Water Program. By letter

dated October 8, 2004, the applicant submitted its formal response to the staff, stating that LRA

Sections 3.2.2.2.2 and 3.2.2.2.3 only address treated water environments and should include a

discussion of the Open-Cycle Cooling Water Program for raw water systems. 

The staff found this acceptable, because the applicant indicated that LRA Sections 3.2.2.2.2

and 3.2.2.2.3 should also include raw water environments and credited the Open-Cycle Cooling

Water Program for raw water systems. With these additions, the applicant's AMR results will be

consistent with the GALL Report. 

Loss of Material due to Pitting and Crevice Corrosion. In LRA Section 3.2.2.2.3, the applicant

addressed the further evaluation of programs to manage the loss of material due to pitting and

crevice corrosion for components in the engineered safety feature systems. This aging effect is

referenced in LRA Table 3.2.1, Items 3.2.1.4 and 3.2.1.5, which the applicant referenced in the

auxiliary systems AMRs for components in the raw service water, sampling and water quality,

building heat, reactor core isolation cooling, auxiliary decay heat removal, radioactive waste

treatment, CRD, and radiation monitoring systems. The staff reviewed the applicant's further

evaluation for this aging effect in SER Section 3.2.2.3.
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The staff noted that the LRA identified loss of material due to crevice and pitting corrosion as an

AERM for mechanical components in a treated water environment in the radiation monitoring

system (LRA Table 3.3.2.31). The applicant referenced LRA Table 3.2.1, Item 3.2.1.5 and

consistency with the GALL Report is noted. The Closed-Cycle Cooling Water Program is

credited for managing this aging effect. However, the further evaluation in LRA

Section 3.2.2.2.3 identifies the Chemistry Control Program and One-Time Inspection Program

for managing the effects of corrosion for components in a treated water environment. The staff

inquired as to the technical basis for using the Closed-Cycle Cooling Water Program alone to

manage aging due to corrosion for components in a treated water environment instead of the

Chemistry Control Program and One-Time Inspection Program. By letter dated October 8,

2004, the applicant submitted its formal response to the staff, stating that the Closed-Cycle

Cooling Water Program is consistent with the related GALL Report Closed-Cycle Cooling Water

Program (XI.M21). The Closed-Cycle Cooling Water Program provides for prevention and

detection of aging effects in plant closed cycle cooling water systems. LRA Section 3.2.2.2.3

only addresses treated water environments and should include a discussion of the

Closed-Cycle Cooling Water Program for treated water in closed cooling loops.

The staff found this acceptable because the applicant indicated that LRA Section 3.2.2.2.3

should also include treated water in closed cooling loops and credit the Closed-Cycle Cooling

Water Program. 

Local Loss of Material due to Microbiologically Influenced Corrosion. In LRA Section 3.2.2.2.4,

the applicant addressed the further evaluation of programs to manage the local loss of material

due to MIC for components in the engineered safety feature systems. This aging effect is

referenced in LRA Table 3.2.1, Item 3.2.1.6, which the applicant referenced in the auxiliary

systems AMRs for components in the raw service water, sampling and water quality, radioactive

waste treatment, and radiation monitoring systems. The staff reviewed the applicant's further

evaluation for this aging effect in SER Section 3.2.2.2.4.

The staff noted that LRA Table 3.3.2.25 identifies loss of material due to MIC as an AERM for

components in a raw water environment in the radioactive waste treatment system. LRA

Table 3.2.1, Items 3.2.1.3, 3.2.1.5, and 3.2.1.6, are referenced, and consistency with the GALL

Report is noted. The One-Time Inspection Program is credited to manage this aging effect.

However, Section 3.2.1.6 references the further evaluation in LRA Section 3.2.2.2.4, which

identifies the Open-Cycle Cooling Water Program for managing MIC. The staff inquired as to

the technical basis for crediting the One-Time Inspection Program for managing aging due to

MIC for these components. By letter dated October 8, 2004, the applicant submitted its formal

response to the staff, stating that the raw water environment identified in the radioactive waste

treatment system is waste that was generated from floor and equipment drain sumps and may

contain dirty or contaminated water. This waste stream is not subject to the Chemistry Control

Program or the Open-Cycle Cooling Water Program. The potential for corrosion in this system

would be lower than actual "raw water" systems because a portion of the waste stream would

be treated water from chemistry control systems. The applicant determined that inspection in

accordance with the One-Time Inspection Program will verify integrity of this system during the

period of extended operation. If corrosion is found to be present, additional inspections and

corrective actions may be required by the One-Time Inspection Program. 
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The staff reviewed the applicant's response and concluded that it is acceptable since the raw

water environment identified in the radioactive waste treatment system is waste that was

generated from floor and equipment drain sumps and may contain dirty or contaminated water.

The potential for corrosion in this system would be lower than actual raw water systems

because a portion of the waste stream would be treated water from chemistry control systems.

The One-Time Inspection Program will verify integrity of this system during the period of

extended operation.

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 Application. In LRA Tables 3.3.2.1 through 3.3.2.34,

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 that are not

addressed in the GALL Report.

In LRA Tables 3.3.2.1 through 3.3.2.34, the applicant indicated, via Notes F through J, that the

combination of component type, material, environment, and AERM does not correspond to a

line item in the GALL Report, and provided information concerning how the aging effect will be

managed. Specifically, Note F indicated that the material for the AMR line item component is

not evaluated in the GALL Report. Note G indicated that the environment for the AMR line item

component and material is not evaluated in the GALL Report. Note H indicated that the aging

effect for the AMR line item component, material, and environment combination is not evaluated

in the GALL Report. Note I indicated that the aging effect identified in the GALL Report for the

line item component, material, and environment combination is not applicable. Note J indicated

that neither the component nor the material and environment combination for the line item is

evaluated in the GALL Report.

For component type, material, and environment combination that are not evaluated in the GALL

Report, the staff reviewed the applicant’s evaluation to determine whether the applicant 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.

The staff’s evaluation is discussed in the following sections.

During its review, the staff determined that similar AMR line items required clarification for

several systems. In several of the auxiliary systems, the LRA states that copper alloy

components in an inside air (external) environment experience no AERMs. However, the

existence of AERMs depends on the particular alloy and whether there is condensation or

pooling on the component. For example, high zinc (>15 percent) alloys in condensation or
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pooling water may exhibit stress corrosion cracking, selective leaching, or pitting and crevice

corrosion. The LRA definition of inside air (external) would support condensation and pooling. 

In RAI 3.3.2.1-1, dated October 12, 2004, the staff requested the applicant to clarify how

condensation and pooling were considered in the evaluation of potential aging of susceptible

alloys. In its response, by letter November 3, 2004, the applicant stated that the copper alloy

components exposed to an inside air (external) environment were evaluated individually to

determine where condensation could occur (i.e., components containing fluid at a temperature

below the dew point of the external environment). The aging effects evaluation then determined

the aging effects/mechanisms based on the particular alloys are susceptible and whether

condensation or periodic wetting occurred. The applicant provided its guidelines for assessing

the particular alloys. 

The staff reviewed the applicant's criteria for determining aging effects based on the particular

copper alloy and found them acceptable and consistent with industry guidance. The applicant

evaluated the components individually and applied acceptable criteria for determining the

AERMs of the alloys exposed to condensation or pooling. Therefore, the staff found the

applicant's evaluation of copper alloys in inside air to be acceptable. 

Aging Management of Bolting in Auxiliary Systems Bolting. The staff reviewed LRA

Tables 3.3.2.1 through 34, which relates to the AMR evaluations for bolting in auxiliary systems

bolting. The staff was concerned that cracking and loss of preload are not identified as aging

effects for bolting managed by the Bolting Integrity Program, including bolting subject to high

pressure, high temperature or vibration. The Bolting Integrity Program should provide for bolting

preload control for all bolting within scope of license renewal.

The LRA AMR tables credit the Bolting Integrity Program for managing loss of bolting function

due to various corrosion mechanisms in auxiliary systems bolting. Loss of preload and cracking

are not identified as aging effects for bolting in the AMR tables for auxiliary systems.

GALL AMP XI.M18 specifically credits the Bolting Integrity Program developed and

implemented in accordance with commitments made in response to communications on bolting

events to provide an effective means of ensuring bolting reliability. The program relies on

industry recommendations for a comprehensive bolting maintenance, as delineated in EPRI

TR-104213 for pressure retaining bolting. The program covers all bolting within the scope of

license renewal. The GALL Report includes loss of material, cracking and loss of preload as

aging effects. Bolting preload control, as delineated in EPRI NP-5769 with exceptions noted in

NUREG-1339, is applied to manage loss of preload. NUREG CR-6679 also identifies loss of

preload as an aging effect and the draft GALL Report update 2005 includes loss of preload as

an aging effect for bolting in ESF, auxiliary and S&PC systems. Further, SRP-LR

Section A.1.2.1 states, "However leakage from bolted connections should not be considered

abnormal events. Although bolting connections are not supposed to leak, experience has

shown that leaks do occur, and the leakage could cause corrosion. Thus, the aging effects from

leakage of bolted connections should be evaluated for license renewal."

The Bolting Integrity Program is identified as an existing program that takes exceptions to GALL

AMP XI.M18 evaluation elements. The exceptions affect element 1 - scope of the program and

possibly element 4 - detection of aging effects. It appears that Element 4 - detection of aging

effects - is identified as being affected by the exceptions. The applicant credits ASME Code
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Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program for ASME Section XI

inspections of Class 1 and Class 2 bolting. 

For auxiliary system closure bolting, the staff is concerned that cracking and loss of preload are

not entirely addressed by either the ASME Code Section XI Subsections IWB, IWC, and IWD

Inservice Inspection Program or Bolting Integrity Program. Although ASME Section XI requires

bolt torquing loads to be in accordance with ASME Section III for replacement of Class 1 and 2

bolting, no bolt torquing requirements are specified for Class 3 bolting, NSR bolting or bolting

that is reused after being removed for maintenance. ASME Section XI does address

examination of Class 1 bolting, but no examination is required for Class 2 bolting smaller than 2

inch and Class 3 bolting regardless of size or NSR bolting. ASME Section XI does provide for

inspection during leakage testing, but this inspection may not necessarily detect loss of preload

or flange leakage at other times. GALL AMP XI.M18, “Bolting Integrity,” does manage cracking

and loss of preload in all closure bolting within scope of license renewal. As identified in EPRI

NP-5769, preload reduction is caused by a number of factors, including stress relaxation (both

at room temperature and elevated temperature), thermal cycling (particularly for gaskets), creep

and flow of gasket material during initial compression, vibration and shock, and elastic

interactions between separately-tightened bolts. The GALL Report includes high pressure and

high temperature systems as being susceptible to crack initiation. Therefore, the applicant

should clarify if the bolting integrity AMP is consistent with GALL AMP XI.M18 in regard to

managing cracking and loss of preload or explain how these aging effects are managed by

other programs or maintenance practices.

By letter dated October 8, 2004, the applicant provided additional information in response to

Audit Inspection Question 310 on bolting activities. The applicant stated that, "Structural bolting

procurement activities, receipt inspection and installation (torquing), as defined in TVA

procedure General Engineering Specification (GES) G-29B-S01, P.S.4.M.4.4, ASME Section III

and Non-Section III (including American Institute of Steel Construction (AISC), ANSI B31.1, and

ANSI B31.5) bolting material, are considered part of the Bolting Integrity Program and meet the

industry recommendations for these activities as delineated in NUREG-1339 and EPRI

NP-5769. 

By letter dated March 16, 2005, the applicant responded to the clarification request on bolting.

For valve closure bolting not within the RCPB, the applicant clarified that stress relaxation is a

thermal effect that results in loss of preload. The applicant explained that stress relaxation is a

design driven effect that would be detected and corrected early and is not considered an

applicable aging effect in non-RCPB valve closure bolting. The applicant stated that installation

procedures are in place that specify proper bolting installation practices and bolt torque values.

In this letter, the applicant also clarified that non-RCPB bolting is not susceptible to SCC as the

yield strength is less than 150 ksi. Further, the applicant explained that crack initiation and

growth due to cyclic loading is not considered a license renewal concern due to high cycle

fatigue, since it would be discovered and corrected during the current licensing period.

The staff reviewed the applicant's response and agreed that loss of preload in auxiliary system

closure bolting should be managed by proper bolting installation practices and torque values

supplemented by inspections. The staff also concurred that proper bolting practices and the

selection of bolting less than 150 ksi should result in auxiliary system closure bolting not being

susceptible to SCC. 
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However, the staff did not agree that cracking and loss of preload are not aging effects for

license renewal, unless the applicant demonstrates that these potential adverse effects will be

corrected prior to the period of extended operation. LRA Section B.2.1.16 states that the BWR

fleet of plants, including BFN, has experienced bolting degradation issues. Plant-specific and

industry operating experience should be reviewed to determine if the applicant's bolting

practices are effective in precluding loss of preload and cracking for all auxiliary system closure

bolting within the scope of license renewal. For example, despite implementation of bolting

practices, recent industry operating experience such as LER 2005-01 for Fermi 2 demonstrates

the importance of sufficient bolt torque to prevent major gasket leakage in BWR auxiliary

systems such as reactor building closed cooling water (RBCCW). The applicant was requested

to review operating experience and submit the results of any self assessments, inspections or

maintenance activities to determine if closure bolting in auxiliary systems will be effectively

managed for cracking and loss of preload. This information should provide objective evidence

to support the conclusion that the effects of aging will be managed adequately so that the

component intended function(s) will be maintained during the period of extended operation. If

by a review of operating experience the applicant cannot demonstrate that effective bolting

practices are in place to manage cracking and loss of preload in auxiliary system closure

bolting, the applicant should commit to a Bolting Integrity Program consistent with the GALL

Report or explain how these aging effects are managed by other programs or maintenance

practices. 

By letter dated June 3, 2005, the applicant provided additional information concerning cracking

and loss of preload in auxiliary systems bolting. In this response the applicant included

information relevant to their review of operating experience with bolting.

Cracking - The applicant clarified that high yield strength heat-treated alloy steel bolting

materials are not specified for flanged connections at BFN. The applicant also clarified that the

use of MoS2 thread lubricant is not allowed by site and engineering procedures. Further the

applicant clarified that a review of the operating experience had not identified any instances

where mechanical component failure was attributable to stress corrosion cracking of high

strength pressure boundary bolting. Thus, the applicant concluded that the aging effect loss of

bolting function was not identified at BFN because both the susceptible material and corrosive

environment portions of the stress corrosion crack mechanism are not present. 

Loss of Preload - The applicant clarified that loss of preload due to stress relaxation (creep) is

not an aging effect for standard grade B7 carbon steel bolting used in auxiliary system bolting

with temperatures less than 700 °F. The applicant also clarified that BFN has taken actions to

address NUREG-1339, "Resolution to Generic Safety Issue 29; Bolting Degradation or Failure

in Nuclear Power Plants." These actions include the implementation of good bolting practices in

accordance with those referenced in EPRI NP-5769, with the exceptions noted in

NUREG-1339, and EPRI TR-104213 to address the potential for joint failure such that it is not a

concern for the current or extended operating term. The applicant identified that a review of the

BFN operating experience did not identify any instances where the mechanical component

failure was attributable to loss of pressure boundary bolting preload. In regard to recent industry

experience with joint failures associated with loss of preload identified in Fermi 2 LER 2005-01,

the applicant attributed this failure to inadequate gasket compression due to a number of

factors including insufficient initial bolt torque. The applicant characterizes this failure as

indicative of a design/maintenance problem rather than an aging concern. 
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The staff reviewed the applicant's response dated March 16, 2005, and found the response to

be reasonable and acceptable. The applicant provided additional information to clarify that

cracking and loss of preload in bolting are being effectively managed. However, the response

did not provide the results of any self assessments, inspections or maintenance activities, and

operating experience to determine if closure bolting in auxiliary systems was effectively

managed at BFN for cracking and loss of preload. The staff discussed this issue with the

applicant in a teleconference, and the verification of this confirmatory item was addressed

during the AMP inspection performed on September 2005. The applicant also agreed to include

this in the Appendix A Commitment Table. In the inspection report, a letter dated November 8,

2005, the staff concluded that the bolting practices in BFN are functioning adequately. The

staff, therefore, concluded that there is reasonable assurance that aging effects, including

cracking and loss of preload, for bolting used in auxiliary systems are being and will continue to

be effectively managed during the period of extended operation.

No Aging Effect or Aging Management Program Identified. The staff reviewed LRA

Tables 3.3.2.1 through 3.3.2.34, which summarized the results of AMR evaluations for the

auxiliary systems component groups.

The applicant included entries in these tables for which there are no aging effects or AMPs

identified. However, the material/environment combinations for these components do have

aging effects identified in other table entries. For example, LRA Table 3.3.2.31, row 14 shows

stainless steel fittings in treated water with no aging effect or AMP, while the next row has the

same component/material/ environment with loss of material identified as an AERM. The staff

inquired as to the purpose of the entries showing no aging effect or AMP. By letter dated

October 8, 2004, the applicant submitted its formal response to the staff, stating that the reason

for the line entries that indicate no aging effects is an attempt to ensure completeness of the

GALL Report comparison. For the example given, LRA Table 3.3.2.31, rows 14 and 15 address

stainless steel fittings that form a portion of containment isolation. The applicable GALL Report,

Volume 2 line item was determined to be V.C.1-b. GALL Report, Volume 2, Item V.C.1-b lists

four aging effects; pitting and crevice corrosion; MIC; and biofouling. For a treated water line,

the AMR determined that MIC and biofouling did not require management for the period of

extended operation. This was documented in the AMR as:

 • pitting corrosion – Yes

 • crevice corrosion – Yes 

 • MIC – No

 • biofouling – No

The first two aging mechanisms form the basis for LRA Table 3.3.2.31, row 15. The last two are

documented in LRA Table 3.3.2.31, row 14 as no aging effect with Note 4 identified. Note 4

states, “Based on system design and operating history, MIC and biofouling are not applicable to

the treated water portions of this system.” Also, Table 3.3.2.14, row 58 should refer to Notes I,

5, and Table 3.3.2.28; row 56 should refer to Notes I, 2.

The staff found that the applicant’s entries showing no aging effect or AMP are acceptable

since they are included only to ensure completeness of the GALL Report comparison; and also

concurred with the corrections identified for LRA Table 3.3.2.14, row 58 and LRA

Table 3.3.2.28, row 56. 
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The staff reviewed LRA Tables 3.3.2.6, 3.3.2.9, 3.3.2.12, 3.3.2.14, 3.3.2.21, 3.3.2.22, 3.3.2.23,

3.3.2.28, 3.3.2.30, and 3.3.2.31, which summarize the results of AMR evaluations for the high

pressure fire protection; heating, ventilation, and air conditioning; CO2, sampling and water

quality; reactor water cleanup; reactor building closed cooling water; reactor core isolation

cooling; diesel generator; diesel generator starting air; and radiation monitoring systems

component groups, respectively.

The applicant identified glass fittings in environments of air/gas, inside air, treated water, raw

water, lubricating oil, and aqueous film-forming foam (AFFF) as having no aging effects

requiring management. During the onsite audit, the staff inquired as to the specific applications

of these glass fittings and the chemical properties of AFFF with regard to its reactivity with

glass. By letter dated October 8, 2004, the applicant submitted its formal response to the staff,

stating that the following components, which contain glass, are included within the scope of

license renewal for BFN:

 • System 26, High Pressure Fire Protection - level gauge

 • System 31, Heating, Ventilation, and Air Conditioning - level gauge

 • System 37, Gland Seal Water - level gauge

 • System 39, CO2 - level gauge

 • System 43, Sampling and Water Quality - level gauge

 • System 64, Containment - level gauge

 • System 68, Reactor Recirculation - sight glass

 • System 70, Reactor Building Closed Cooling Water - level gauge

 • System 82, Diesel Generator - level gauge

 • System 86, Diesel Generator Starting Air - sight glass

 • System 90, Radiation Monitoring - sight glass, moisture traps, and air filters

In addition, the applicant stated that AFFF contains the following:

 • water

 • 2-(2-butoxyethoxy) ethanol

 • ethylene glycol

 • alkyl polyglycoside

 • fluoroalkyl surfactant

This mixture of hydrocarbons, surfactants, fluorosurfactants, and water is not reactive with

glass.

The staff concluded that the applicant’s determination of no aging effect for these glass

components for the environments identified is acceptable since the environments identified are

not reactive with glass.

3.3.2.3.1 Auxiliary Boiler System – Summary of Aging Management Evaluation – Table 3.3.2.1

The staff reviewed LRA Table 3.3.2.1, which summarizes the results of AMR evaluations for the

auxiliary boiler system component groups.
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In LRA Table 3.3.2.1, the applicant proposes that fittings, piping, and valves made from carbon

and low-alloy steel in an environment of treated water (internal) and subjected to galvanic

corrosion will be managed by the One-Time Inspection Program. 

The staff reviewed the One-Time Inspection Program and its evaluation is documented in SER

Section 3.0.3.1. Galvanic corrosion is typically minimized through standard design practices.

Therefore, any galvanic corrosion is expected to be sufficiently slow that the One-Time

Inspection Program is appropriate for this aging effect. If there is any significant galvanic

corrosion, this AMP will identify the problem and initiate appropriate corrective action.

Therefore, the staff found the use of the One-Time Inspection Program to be appropriate for

this aging effect. 

LRA Section 3.3.2.1, states that valves made from copper alloy and exposed to inside air

(external environment) experience no AERMs and require no AMPs.

In general RAI 3.3.2.1-1 the staff questioned whether the copper alloy components exposed to

inside air would be subject to aging effects. The staff found the applicant’s assessment of the

copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3.

On the basis of its review of the information provided in the LRA and the additional information

provided, the staff found the aging effects of the above AMR items are consistent with industry

experience for these combinations of materials and environments. The staff did not identify any

omitted aging effects. Therefore, the staff found that the applicant had identified the appropriate

aging effects for the materials and environments associated with the above components in the

auxiliary boiler system.

Loss of Material Due to Corrosion for Cast Iron and Carbon/Low Alloy Steels in an Air/Gas

Environment The applicant identified loss of material due to crevice, general, and pitting

corrosion as an AERM for valves constructed of cast iron and cast iron alloy, as well as fittings,

piping, traps, and valves constructed of carbon or low-alloy steel in a moist air/gas environment

on their internal surface. The One-Time Inspection Program is credited for managing this aging

effect. The staff inquired as to the technical basis for concluding that the One-Time Inspection

Program is adequate to manage this aging effect for these material and environment

combinations for this system. By letter dated October 8, 2004, the applicant submitted its formal

response to the staff, stating that the air/gas components in the auxiliary boiler system were

exposed to secondary quality water or steam that had been isolated by the layup of the auxiliary

boilers. The portions of the system that now contain air/gas are isolated and there is no

mechanism for introducing contaminants or additional oxygen. Since the portions of the

auxiliary boiler system exposed to air/gas were originally chemistry controlled, the potential for

corrosion is low. The One-Time Inspection Program will verify this by performing a sampling

inspection. If corrosion is found to be present, additional inspections and corrective actions may

be required by the One-Time Inspection Program. 

The staff concluded that the applicant’s response is acceptable. The water to which these

components were exposed was chemically treated, and the components are now isolated such

that neither contaminants nor additional oxygen will be introduced into the air/gas environment.

Therefore, the potential for corrosion of these components is low. The one-time inspection will

verify that corrosion is not occurring. If corrosion is detected, additional inspections and

corrective actions will be taken. 
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Loss of Material due to Selective Leaching of Copper Alloy in a Treated Water Environment.

The applicant identified loss of material due to selective leaching for components constructed of

copper alloy in a treated water environment on their internal surface as an AERM. The

One-Time Inspection Program is credited for managing this aging effect. The staff inquired as

to the technical basis for concluding that the One-Time Inspection Program is adequate to

manage this aging effect for this material and environment combination for components in this

system. By letter dated October 8, 2004, the applicant submitted its formal response to the

staff, stating that the One-Time Inspection Program had been identified in error. The correct

AMP for this aging effect is the Selective Leaching of Materials Program.

The staff concluded that the applicant’s response is acceptable since the Selective Leaching of

Materials Program was developed specifically to address loss of material due to selective

leaching. The One-Time Inspection Program was incorrectly listed in Table 3.2.2.1 for this

component. 

3.3.2.3.2 Fuel Oil System – Summary of Aging Management Evaluation – Table 3.3.2.2

The staff reviewed LRA Table 3.3.2.2, which summarizes the results of AMR evaluations for the

fuel oil system component groups.

In LRA Table 3.3.2.2, the applicant states that pumps, piping, and fittings made from carbon

and low-alloy steel in fuel oil experience no aging effects. Copper alloy in fuel oil is subjected to

loss of material due to MIC. The applicant also states that fittings made from copper alloy in

inside air experience no aging effects. For flexible hoses made from elastomer - rubber in fuel

oil (internal) subjected to elastomer degradation due to oxidation, the applicant proposes that

these be managed by the One-Time Inspection Program. Flexible hoses made from elastomer -

rubber in inside air may experience elastomer degradation due to ultraviolet radiation, and will

be managed by the Systems Monitoring Program.

LRA Section 3.3.2.2 states that components made from copper alloy and exposed to inside air

(external environment) experience no AERMs and require no AMPs. In a general RAI, the staff

questioned whether the copper alloy components exposed to inside air would be subject to

aging effects. The staff found the applicant’s assessment of the copper alloy components to be

acceptable, as discussed in SER Section 3.3.2.3. 

The staff’s review of LRA Section 3.3.2.2 identified areas in which additional information was

necessary to complete the review of the applicant’s results. The applicant responded to the

staff’s RAI as discussed below.

In RAI 3.3.2.2-2, dated October 12, 2004, the staff noted that numerous line items In LRA

Table 3.3.2.2 state that carbon and low-alloy steel components in fuel oil experience no AERMs

and require no AMPs. This is not consistent with the GALL Report or with industry experience.

Notes associated with these line items indicate that the AERMs identified in the GALL Report

for this material/environment combination are not applicable (Note I) for the following reasons:

(1) pitting, crevice, general, or galvanic corrosion are not concerns because there is no water

collection in these components (Note 5, applied to fittings, piping, pumps, restricting orifice,

strainers, and tubing); (2) biofouling is not a concern (Note 7, applied to tanks); or (3) galvanic

corrosion is not a concern because there are no galvanic couples in the portions of the system

where water could accumulate and provide a conductor (applied to tanks). Adjacent line items
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in LRA Table 3.3.2.2 for the same material, environment, and GALL reference state that the

components are subjected to loss of material due to MIC and credit the Fuel Oil Chemistry

Program and the One-Time Inspection Program for aging management. Therefore, the staff

requested the applicant to clarify the above AMR and whether the Fuel Oil Chemistry Program

and the One-Time Inspection Program are credited for all carbon steel and low-alloy

components in the system.

In its response, by letter dated November 3, 2004, the applicant clarified that the AMR line

items that state that carbon and low-alloy steel components in fuel oil experience no AERMs

are there to indicate that some potential aging mechanisms identified in the GALL Report are

not applicable. GALL Report, Volume 2, Section VII.G.8-a, lists the four aging mechanisms as

general, galvanic, pitting, and crevice corrosion, while the applicant’s AMR determined that the

only aging mechanism applicable to these components (where there is no water accumulation)

is MIC. MIC forms the basis of the adjacent AMR line item. The applicant also clarified that the

Fuel Oil Chemistry Program and the One-Time Inspection Program are credited as aging

managements programs for all carbon steel and low-alloy steel components in the fuel oil

system with a fuel oil internal environment. The staff concurred with the applicant’s assessment

that MIC is the predominant aging effect for carbon and low-alloy steel in fuel oil where there is

no potential for water accumulation. The staff also noted that the inspections performed on this

system will identify the AERMs in the GALL Report, if they are present. Therefore, the staff

found that the applicant had identified the appropriate aging effects. 

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant’s response to the above RAIs, the staff found the aging effects of the

above AMR items are consistent with industry experience for these combinations of materials

and environments. The staff did not identify any omitted aging effects. Therefore, the staff

found that the applicant had identified the appropriate aging effects for the materials and

environments associated with the above components in the fuel oil system.

LRA Table 3.3.2.2 identifies the following AMPs for managing the aging effects described

above: Fuel Oil Chemistry Program, One-Time Inspection Program, and the Systems

Monitoring Program. The staff’s detailed reviews of these AMPs are found in SER

Sections 3.0.3.2.18, 3.0.3.1.7, and 3.0.3.3.1, respectively.

In RAI 3.3.2.2-1, dated October 12, 2004, the staff stated that LRA Section 3.3.2.2. implies that

the one-time inspections will be limited to the system locations where contaminants are

expected to accumulate; however, AERMs (particularly MIC) are identified for a larger

population of components. Therefore, the staff requested the applicant to clarify the use of the

one-time inspections. In its response, by letter November 3, 2004, the applicant stated that the

Fuel Oil Chemistry Program and the One-Time Inspection Program are credited as AMPs for all

components in the fuel oil system with a fuel oil internal environment where aging effects were

identified. These programs are being applied to all components with identified AERMs;

therefore, the staff found this acceptable.

For the flexible hoses made of elastomer (rubber) in a fuel oil environment, the LRA credits the

One-Time Inspection Program to manage the aging effect of elastomer degradation due to

oxidation. The One-Time Inspection Program is typically used to verify that an aging effect is

not occurring or when an aging effect is expected to occur slowly, such that the component

intended function can be maintained for the extended period of operation. For these same
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hoses, the LRA credits the Systems Monitoring Program to manage the aging effect of

elastomer degradation due to ultraviolet radiation. The Systems Monitoring Program provides

for visual inspections of the hoses. The staff found the periodic inspections, combined with the

one-time inspection of the hose internal surface, adequate for managing the aging of the

flexible hoses. Therefore, the staff found the management of these hoses to be acceptable.

The staff reviewed LRA Table 3.3.2.2, which summarized the results of AMR evaluations for the

fuel oil system component groups. The applicant identified no aging effect or AMP for

components constructed of cast iron and cast iron alloy, as well as carbon or low-alloy steel in

an air/gas environment on their internal surface. During the onsite audit, the staff inquired as to

the technical justification for concluding that there are no aging effects for these

material/environment combinations for components in this system. By letter dated October 8,

2004, the applicant submitted its formal response to the staff, stating that components in the

fuel oil system are exposed to a fuel oil vapor environment. This fuel oil vapor environment

protects the component surfaces and prevents internal corrosion. 

The staff concluded that the applicant’s determination of no AERMs for components in the fuel

oil system in an air/gas environment on the internal surface is acceptable since the components

will be exposed to fuel oil vapor, which will protect the surfaces of the components from

corrosion. 

On the basis of its review of the information provided in the LRA and RAI responses, the staff

found the applicant had identified appropriate AMPs for managing the aging effects of the

above fuel oil system components. In addition, the staff found the program descriptions in the

UFSAR supplement acceptable.

No Aging Effect or Aging Management Program Identified. The applicant identified no aging

effect or AMP for components constructed of cast iron and cast iron alloy, as well as carbon or

low-alloy steel in an air/gas environment on their internal surface. During the onsite audit, the

staff inquired as to the technical justification for concluding that there are no aging effects for

these material/environment combinations for components in this system. By letter dated

October 8, 2004, the applicant submitted its formal response to the staff, stating that

components in the fuel oil system are exposed to a fuel oil vapor environment. This fuel oil

vapor environment protects the component surfaces and prevents internal corrosion. 

The staff concluded that the applicant’s determination of no AERMs for components in the fuel

oil system in an air/gas environment on the internal surface is acceptable since the components

will be exposed to fuel oil vapor, which will protect the surfaces of the components from

corrosion. 

3.3.2.3.3 Residual Heat Removal Service Water System – Summary of Aging Management

Evaluation – Table 3.3.2.3

The staff reviewed LRA Table 3.3.2.3, which summarizes the results of AMR evaluations for the

RHRSW system component groups.

In LRA Table 3.3.2.3, the applicant identifies aging effect for the RHRSW system components

within the scope of license renewal and subject to AMR. The AMR lists the components,

materials, environments, AERMs, and AMPs credited for managing the AERMs. The AMR line
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items that do not rely on the GALL Report include the following: fittings, piping, and valves

made from aluminum alloy in an environment of treated water (internal) are subjected to crack

initiation and growth due to SCC, and loss of material due to crevice and pitting corrosion, and

will be managed by the Chemistry Control Program and the One-Time Inspection Program.

Fittings, piping, and valves made from carbon and low-alloy steel in an environment of treated

water (internal) are subject to loss of material due to crevice, general, and pitting corrosion.

Fittings made from polymer in environments of inside air (external) and treated water (internal)

experience no AERMs and require no AMPs. 

Through a staff teleconference follow up request dated February 11, 2005, the staff requested

the applicant to provide additional clarification regarding the type of elastomer or polymer, its

environment, and justification that there are no AERMs for the elastomer or polymer

components. In its response, by letter dated March 11, 2005, the applicant clarified that the

polymer components in this system are Derlin (acetal) insulating couplings between dissimilar

material threaded piping. Based on its review of the material data sheet for Derlin, the staff

concluded that the material is rated for continuous service in environmental conditions (e.g.,

temperature) significantly in excess of the conditions in the RHRSW system. Therefore, the

staff concurred with the applicant’s evaluation that there are no AERMs for the polymer

components in this system. 

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant’s response to the above RAIs, the staff found the aging effects of the

above AMR items are consistent with industry experience for these combinations of materials

and environments. The staff did not identify any omitted aging effects. Therefore, the staff

found that the applicant had identified the appropriate aging effects for the materials and

environments associated with the above components in the RHRSW.

No Aging Effect or Aging Management Program Identified. The applicant identified no aging

effect or AMP for components constructed of cast iron and cast iron alloy, as well as carbon or

low-alloy steel in an embedded/encased environment on their external surface. During the

onsite audit, the staff inquired as to the technical justification for concluding that there are no

aging effects for these material and environment combinations for components in this system.

By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that no aging effects are identified for embedded/encased components. If excessive corrosion

that could prevent the performance of the intended functions during the period of extended

operation was detected on the inside surface or outside surface in air environments adjacent to

the embedded/encased portions, corrective actions would be taken to restore the component,

including the embedded/encased portions, if this was determined to be necessary.

The staff concluded that the applicant’s determination of no AERMs for components in the

RHRSW system in an embedded/encased environment is acceptable since exposure to a

corrosive environment will be limited. Inspections will be performed on adjacent surfaces

exposed to an air environment. If corrosion was detected on adjacent surfaces in an air

environment, corrective actions would be taken to restore the component, including the

embedded/encased portions, if this was determined to be necessary.
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3.3.2.3.4 Raw Cooling Water System – Summary of Aging Management Evaluation –

Table 3.3.2.4

The staff reviewed LRA Table 3.3.2.4, which summarizes the results of AMR evaluations for the

raw cooling water system component groups.

In LRA Table 3.3.2.4, the applicant identifies aging effect for the raw cooling water system

components within the scope of license renewal and subject to AMR. The AMR lists the

materials, environments, AERMs, and AMPs credited for managing the AERMs. The AMR line

items that do not rely on the GALL Report include the following: fittings, tubing, and valves

made from copper alloy and exposed to inside air (external environment) experience no AERMs

and require no AMPs; expansion joints made from elastomer exposed to inside air (external)

and raw water (internal) experience no AERMs and require no AMPs; fittings and piping made

from polymer in air/gas (internal) or inside air (external) environments experience no AERMs

and require no AMPs.

In the general RAI 3.3.2.2-1, the staff questioned whether the copper alloy components

exposed to inside air would be subject to aging effects. The staff found the applicant's

assessment of the copper alloy components to be acceptable, as discussed in SER

Section 3.3.2.3. 

In its response to the staff's informal request February 11, 2005, by letter dated March 11,

2005, the applicant clarified that the elastomer components are fabric reinforced expansion

joints (Garlock Style 204) made from chlorobutyl/polyester. The coating cover reduces

ultraviolet radiation to negligible levels, the system temperature is low relative to the qualified

temperature, and the elastomers are not exposed to significant radiation. Based on the above,

the staff concurred with the applicant's conclusion that there are no AERMs for the elastomer

components in this system. 

With respect to the polymer components, by the letter dated March 11, 2005, the applicant

clarified that the polymer components are molded plastic fittings and piping in air/gas and inside

air. The applicant stated that once the proper polymer, resistant to the environment, is chosen,

there are no AERMs. The applicant further stated that industry guidance does not identify any

AERMs for this polymer and environment, but that the components would be included in the

Systems Monitoring Program to verify that there is no hardening or loss of material strength due

to polymer degradation.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the above RAIs, the staff found the aging effects of the

above AMR items are consistent with industry experience for these combinations of materials

and environments. The staff did not identify any omitted aging effects or the need for any AMPs

for the above combinations of material and environment. Therefore, the staff found that the

applicant had identified the appropriate aging effects for the materials and environments

associated with the above components in the raw cooling water system.
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3.3.2.3.5 Raw Service Water System – Summary of 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

raw service water system component groups.

In LRA Table 3.3.2.4, the applicant identifies the aging effects of the service water system

components within the scope of license renewal and subject to AMR. The AMR lists the

materials, environments, AERMs, and AMPs credited for managing the AERMs. The only AMR

line items that do not rely on the GALL Report are as follows: fittings and valves made from

copper alloy and exposed to inside air (external environment) experience no AERMs and

require no AMPs. 

In a general RAI 3.3.2.2-1, the staff questioned whether the copper alloy components exposed

to inside air would be subject to aging effects. The staff found the applicant’s assessment of the

copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3.1.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the RAI, the staff found the aging effects of the above

AMR items are consistent with industry experience for these combinations of materials and

environments. The staff did not identify any omitted aging effects or the need for any AMPs for

the above combinations of material and environment. Therefore, the staff found that there is

reasonable assurance that the component intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.29(a).

3.3.2.3.6 High Pressure Fire Protection System – Summary of 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

high pressure fire protection system component groups.

In LRA Section 3.3.2.1.6 and Table 3.3.2.6, the applicant identified the materials, environments,

and AERMs. The materials identified include carbon steel, alloy steel, stainless steel, aluminum,

cast iron, elastomers, glass, and copper alloys. 

The applicant identified the environments to which these materials could be exposed as air and

gas (wetted, ambient and dry), raw water (well water), treated water and AFFF and includes

environments inside, outside, and buried. The applicant identified loss of material (from

corrosion or leaching) and degradation (UV degradation of elastomers) as the aging effects

associated with the fire water system. 

Staff Evaluation. The staff reviewed the LRA to determine whether the applicant had

demonstrated that it would adequately manage the effects of aging for the fire protection

system during the period of extended operation, as required by the regulations that govern

LRA. The staff also reviewed LRA Sections of 3.3.2.6 and Table 3.3.2.6 for completeness and

consistency with the GALL Report and industry experience. 

On the basis of its review of the LRA, the staff found that the aging effects resulting from

exposure of the fire water system components to the environments described in LRA
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Table 3.3.2.6 are consistent with the GALL Report and with industry experience for these

material-environment combinations. Therefore, the staff found that the applicant identified the

applicable aging effects and associated AMPs and that they are appropriate for the combination

of materials and environments listed.

3.3.2.3.7 Potable Water System – Summary of 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

potable water system component groups.

In LRA Table 3.3.2.7, the applicant stated the aging effects of the potable water system

components within the scope of license renewal and subject to AMR. The AMR lists the

materials, environments, AERMs, and AMPs credited for managing the AERMs. The AMR line

items that do not rely on the GALL Report include the following: fittings, tubing, and valves

made from copper alloy and exposed to inside air, which experience no AERMs and require no

AMPs; fittings and piping made from carbon and low-alloy steel in raw water for loss of material

due to galvanic, general, crevice and pitting corrosion, which will be managed by the One-Time

Inspection Program. LRA Section 2.3.3.7 clarifies that the raw water is potable water supplied

by the city of Athens, Alabama. LRA Table 3.3.2.7 notes clarify that the water is chlorinated to

prevent the growth of microorganisms, such that biofouling and MIC are not expected, but that

chlorination introduces the possibility of SCC for the stainless steel components. For valves

made from carbon and low-alloy steel in raw water, loss of material due to general, crevice, and

pitting corrosion will be managed by the One-Time Inspection Program. For fittings made from

cast iron and cast iron alloy in raw water, loss of material due to general, crevice, pitting, and

galvanic corrosion will be managed by the One-Time Inspection Program. For valves made

from cast iron and cast iron alloy (gray) in raw water, loss of material due to general, crevice,

pitting, and galvanic corrosion will be managed by the One-Time Inspection Program. For

fittings and valves made from stainless steel in raw water, crack initiation and growth due to

SCC will be managed by the One-Time Inspection Program. For fittings, tubing, and valves

made from copper alloy in raw water, loss of material due to crevice and pitting corrosion will be

managed by the One-Time Inspection Program. 

In general RAI 3.3.2.2-1 the staff questioned whether the copper alloy components exposed to

inside air would be subject to aging effects. The staff found the applicant's assessment of the

copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3. 

The staff also noted that for the carbon and low-alloy exposed to raw water, galvanic corrosion

is identified as a potential aging effect for the fittings and piping, but not for the valves. In its

March 11, 2005, response to the staff's informal request February 11, 2005, the applicant

clarified that galvanic corrosion is only applicable when the component is in contact with a more

cathodic material, and that the valves in question are not connected to more cathodic materials.

The staff found this explanation reasonable and acceptable. 

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the RAI, the staff found the aging effects of the above

AMR items are consistent with industry experience for these combinations of materials and

environments. The staff did not identify any omitted aging effects. Therefore, the staff found

that the applicant had identified the appropriate aging effects for the materials and

environments associated with the above components in the potable water system.
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Loss of Material due to Corrosion for Copper Alloys in a Raw Water Environment. The applicant

identified loss of material due to crevice and pitting corrosion for components constructed of

copper alloy and stainless steel in a raw water environment on their internal surface as an

AERM. The One-Time Inspection Program is credited for managing this aging effect. The staff

inquired as to the technical basis for concluding that the One-Time Inspection Program is

adequate to manage this aging effect for these material and environment combinations for

components in this system. By letter dated October 8, 2004, the applicant submitted its formal

response to the staff, stating that LRA Table 3.3.2.7 for the potable water system evaluates the

potable (city) water as a raw water source. The actual chemistry is much milder than expected

for raw water. Therefore, loss of material affecting component operation during the period of

extended operation is not expected. The One-Time Inspection Program will verify this by

performing a sampling inspection. If corrosion is found to be present, additional inspections and

corrective actions may be required by the One-Time Inspection Program. 

The staff concluded that the applicant’s response is acceptable since raw water for this system

is actually potable water, which has a milder chemistry. Therefore, the potential for corrosion is

low. The One-Time Inspection Program will verify that corrosion is not occurring. If corrosion is

detected, additional inspections and corrective actions will be taken. 

3.3.2.3.8 Ventilation System – Summary of 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

ventilation system component groups.

In LRA Table 2.3.3-8, the applicant lists individual system components within the scope of

license renewal and subject to AMR. The AMR lists the components, materials, environments,

AERMs, and AMPs credited for managing the AERMs. The AMR line items that do not rely on

the GALL Report include the following: ducting made from carbon and low-alloy steel in air/gas

(internal) and elastomer - rubber and silicone rubber in air/gas (internal) experience no AERMs

and require no AMPs. Elastomer - rubber and silicone rubber in air/gas (external) experience

elastomer degradation due to ultraviolet radiation.

In RAI 3.3.2.1.8-1, dated December 10, 2004, the staff requested additional information

regarding the applicant's claim in LRA Table 3.3.2.8 that the carbon and low-alloy steel

ductwork experiences no aging effects. The staff noted that adjacent entries in LRA

Table 3.3.2.8 for the same material, environment, and GALL Report reference identify a loss of

material due to general corrosion. It appeared to the staff that the applicant takes exception to

the GALL Report's identification of crevice corrosion, pitting corrosion, and MIC as not

applicable while general corrosion is applicable. In its response, by letter November 3, 2004,

the applicant confirmed that the AMR was intended to state that the applicant took exception to

the GALL-identified AERMs of crevice corrosion, pitting corrosion, and MIC, because the GALL

identifies these AERMs for drip pans and drain lines, which are typically wet. Instead, the

applicant identifies general corrosion (in adjacent line items) and credits the One-Time

Inspection Program. The staff found the applicant's response acceptable because the applicant

stated that the ducting is not expected to be wetted. The staff also found that the one-time

inspection will be adequate to identify a loss of material in the ducting. 

The technical staff also questioned the AMR items related to elastomer - rubber and silicone

rubber ductwork in air/gas and inside air. For these material/environment combinations, the
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applicant claims that there are no AERMs based on industry guidance. The degradation of

elastomers depends on environmental factors such as the temperature, radiation levels, and

presence of aggressive chemicals. Degradation can also be caused by wear (for items such as

seals and vibration dampers). The staff asked the applicant to provide additional information on

the above factors to justify that there are no AERMs for the elastomers, or to provide aging

management for the elastomer components in the ductwork. In its response dated November 3,

2004, the applicant clarified that the elastomer degradation due to ultraviolet radiation is

identified (in adjacent LRA Table 3.3.2.8 AMR items) and managed by the Systems Monitoring

Program. The applicant did not identify elastomer degradation due to thermal exposure or

ionizing radiation because the components in question remain below the thresholds for

significant degradation from these factors. Based on the above, the staff found that the

applicant had adequately addressed the concerns; therefore, the RAI 3.3.2.1.8-1 is resolved. 

On the basis of its review of the information provided in the LRA (and the additional information

included in the applicant's response to the above RAI, the staff found the aging effects of the

above ventilation system component types that are not addressed by the GALL Report are

consistent with industry experience for these combinations of materials and environments. The

staff did not identify any omitted aging effects. Therefore, the staff found that the applicant had

identified the appropriate aging effects for the materials and environments associated with the

above components in the ventilation system.

On the basis of its review, the staff concluded that the applicant had adequately identified the

aging effects for the ventilation system components that are not addressed by the GALL Report

so 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 54.29(a). 

3.3.2.3.9 Heating, Ventilation, and Air Conditioning System – Summary of 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

HVAC system component groups.

In LRA Table 2.3.3.9, the applicant lists individual system components within the scope of

license renewal and subject to AMR. The AMR lists the components, materials, environments,

AERMs, and AMPs credited for managing the AERMs. The AMR line items that do not rely on

the GALL Report include the following:

Components in raw water (potable): for the carbon and low-alloy steel components (fittings,

heat exchangers, strainers, tanks and valves), the applicant identifies loss of material due to

general, crevice, pitting, and galvanic corrosion, and credits the One-Time Inspection Program.

For the cast iron and cast iron alloy components (fittings, heat exchangers, pumps, and valves),

the applicant identifies loss of material due to general, crevice, pitting, and galvanic corrosion,

and credits the One-Time Inspection Program. In addition, for the cast iron and cast iron alloy

heat exchangers, the applicant also identifies selective leaching, and credits the Selective

Leaching of Materials Program (as clarified by letter dated March 11, 2005). For the stainless

steel components (fittings, flexible connectors, heat exchangers, piping and valves), the

applicant identifies crack initiation and growth due to SCC and loss of material due to crevice

and pitting corrosion, and credits the One-Time Inspection Program. For the copper alloy

components (fittings, heat exchangers, tubing, and valves), the applicant identifies loss of
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material due to crevice, galvanic, and pitting corrosion, and credits the One-Time Inspection

Program.

Components in treated water: for the carbon and low-alloy steel components (fittings, heat

exchangers, piping, strainers, tanks and valves), the applicant identifies galvanic corrosion and

credits the Closed-Cycle Cooling Water System Program. For the stainless steel components

(fittings, flexible connectors, piping, pumps, strainers, tubine and valves), the applicant identifies

crack initiation and growth due to SCC and loss of material due to crevice and pitting corrosion,

and credits the Closed-Cycle Cooling Water System Program. 

Components in raw water: for carbon steel and low-alloy steel piping, the applicant identifies

loss of material due to general, crevice, pitting, and galvanic corrosion, and credits the

One-Time Inspection Program. For stainless steel heat exchangers, the applicant identifies

crack initiation and growth due to SCC and loss of material due to crevice and pitting corrosion,

and credits the One-Time Inspection Program. 

In addition to the above aging effects, the applicant identifies loss of heat transfer due to

particulate fouling, and credits the One-Time Inspection Program, for heat exchanger

components made from aluminum alloy, copper alloy, and stainless steel in raw water (potable),

raw water, and air/gas environments.

The applicant identified no aging effects and, consequently, no AMPs, for polymer components

(fittings, flexible connectors, tubing and valves) in air/gas (internal) and inside air (external),

elastomer ductwork and flexible connectors in air/gas (internal) or inside air (external), and

copper alloy components in inside air (external). 

In general RAI 3.3.2.2-1 the staff questioned whether the copper alloy components exposed to

inside air would be subject to aging effects. The staff found the applicant's assessment of the

copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3. 

The staff asked for additional information related to elastomer components, since the applicant

determined that there are no AERMs based on industry guidance. The degradation of

elastomers depends on the environmental factors such as the temperature, radiation levels,

and presence of aggressive chemicals (aggressive chemicals are not anticipated for this

system). In its response to the staff's informal request February 11, 2005, by letter dated

March 11, 2005, the applicant demonstrated that the temperature and radiation levels remain

below the thresholds for which there is significant aging of the silicon and neoprene

components, the neoprene coated glass material (Dupont's Ventglass). Therefore, the staff

concurred with the applicant's assessment.

With respect to the polymer components, by letter dated March 11, 2005, the applicant clarified

that the polymer components are molded plastic (valves), molded nylon (fittings), hypalon

coated nylon (flexible connectors), and Nycoa Nylon 589 (tubing) in air/gas and inside air. The

applicant stated that once the proper polymer, resistant to the environment, is chosen, there are

no AERMs. The applicant further stated that industry guidance does not identify any AERMs for

these polymers and environments, but that the components would be included in the Systems

Monitoring Program to verify that there is no hardening or loss of material strength due to

polymer degradation.
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In RAI 3.3.2.1.9-2, dated October 12, 2004, the staff stated that in Table 3.3.2.1.9 the applicant

claimed that there are no AERMs for this material environment combination of copper-alloy heat

exchanger in inside air (external). Condensation in the heat exchangers could lead to aging

effects, and there is the potential for loss of heat transfer by such mechanisms as particulate

fouling. In its November 3, 2004, response, the applicant clarified that the coils are for cooling

freon, so that there is no condensation. Also, due to the design of the cooling coils (no fins),

they are not susceptible to particulate fouling. Since there will be no condensation on the coils

and since the design is not susceptible to particulate fouling, the staff agreed with the

applicant's assessment. Therefore, the staff found the applicant's response acceptable and

RAI 3.3.2.1.9-2 is resolved.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the above RAIs, the staff found the aging effects of the

above heating, ventilation, and air conditioning system component types that are not addressed

by the GALL Report are consistent with industry experience for these combinations of materials

and environments. The staff did not identify any omitted aging effects. Therefore, the staff

found that the applicant had identified the appropriate aging effects for the materials and

environments associated with the above components in the heating, ventilation, and air

conditioning system.

Crack Initiation and Growth due to SCC for Copper Alloys and Stainless Steel in Raw Water

Environments. The applicant identified crack initiation and growth due to SCC as an AERM for

heat exchangers constructed of stainless steel in a raw water environment. The applicant

credited the One-Time Inspection Program to manage this aging effect. The staff inquired as to

the technical basis for identifying this aging effect for this material and environment

combination. By letter dated October 8, 2004, the applicant submitted its formal response to the

staff, stating that, upon further review, the cracking aging effect was inappropriately identified

for the raw water environment and should be deleted from the Table 3.3.2.9 entry for these

components.

The staff concluded that the applicant’s response is acceptable for this material and

environment combination since the conditions for SCC are not expected to be present in the

environment identified. 

Crack Initiation and Growth due to SCC for Stainless Steel and Cast Austenitic Stainless Steel

in Treated Water Environments. The applicant identified crack initiation and growth due to SCC

as an AERM for fittings, flexible connectors, piping, tubing and valves constructed of stainless

steel in a treated water environment. The applicant credited the Closed-Cycle Cooling Water

System Program to manage this aging effect. During the onsite audit, the staff inquired as to

how the Closed-Cycle Cooling Water System Program would detect cracking prior to the loss of

intended function for these components. By letter dated October 8, 2004, the applicant

submitted its formal response to the staff, stating that, upon further review, the cracking aging

effect is unnecessary for these components. In addition, components were identified with

cracking of stainless steel in a raw water environment in potable water, and heating, ventilation

systems, and air conditioning. The applicant determined that this cracking aging effect is also

unnecessary.
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The staff concluded that the applicant’s response is acceptable for this material and

environment combination since the conditions conducive to SCC are not present in the system

identified.

Loss of Material Due to Corrosion for Cast Iron and Carbon/Low Alloy Steels in an Air/Gas

Environment. The applicant identified loss of material due to crevice, galvanic, general, and

pitting corrosion as an AERM for heat exchangers constructed of cast iron and cast iron alloy,

as well as heaters and heat exchangers constructed of carbon or low-alloy steel in an air/gas

environment on their internal surface. The One-Time Inspection Program is credited for

managing this aging effect. During the onsite audit, the staff inquired as to the technical basis

for concluding that the One-Time Inspection Program is adequate to manage this aging effect

for components with these material and environment combinations in this system. By letter

dated October 8, 2004, the applicant submitted its formal response to the staff, stating that the

components in the heating, ventilation, and air conditioning system located in an air/gas

environment were exposed to heated and cooled circulated air. Loss of material is consistent

with the GALL Report, although the GALL Report identifies only general corrosion. Based on

the potential for water accumulation on or in the area of the cooling coils, additional potential

aging mechanisms were identified. Actual experience based on a review of work orders and

PERs demonstrates that loss of material has not been an issue for these components within

this system. In particular, no instances of pitting, crevice, or galvanic corrosion were identified in

this review. The One-Time Inspection Program will verify this by performing a sampling

inspection. If corrosion is found to be present, additional inspections and corrective actions may

be required by the One-Time Inspection Program. 

The staff concluded that the applicant’s response is acceptable since these components are

normally exposed to heated and cooled air and the potential for loss of material due to crevice,

galvanic, and pitting corrosion is low. Loss of material due to crevice, galvanic, and pitting

corrosion of these components was included since there is the potential for water accumulation

near them; however, a review of past operating experience confirms that this aging effect has

not been a problem. The One-Time Inspection Program will verify that loss of material is not

occurring. If loss of material is detected, additional inspections and corrective actions will be

taken.

Fouling Product Buildup due to Particulate for Copper Alloy and Stainless Steel in an Air/Gas

Environment. The applicant identified fouling product buildup due to particulate as an AERM for

heat exchangers constructed of copper alloy and stainless steel in an air/gas environment on

their internal surface. The One-Time Inspection Program is credited for managing this aging

effect. During the onsite audit, the staff inquired as to the technical basis for concluding that the

One-Time Inspection Program is adequate to manage this aging effect for these material and

environment combinations for this system. By letter dated October 8, 2004, the applicant

submitted its formal response to the staff, stating that the air/gas environment to which the

cooling coils are exposed is heated and cooled circulated air. The actual plant experience

based on a review of work orders and problem reports demonstrates that fouling has not been

an issue with this system. The One-Time Inspection Program will verify this by performing a

sampling inspection. If fouling is found to be present, additional inspections and corrective

actions may be required by the One-Time Inspection Program. 

The staff concluded that the applicant’s response is acceptable. These components are

normally exposed to heated and cooled air and the potential for fouling due to particulate is low.
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A review of past operating experience confirms that this aging effect has not been a problem,

and the One-Time Inspection Program will verify that fouling is not occurring. If fouling is

detected, additional inspections and corrective actions will be taken. 

Fouling Product Buildup due to Particulate for Stainless Steel in a Raw Water Environment. 

The applicant identified fouling product buildup due to particulate as an AERM for heat

exchangers constructed of stainless steel in a raw water environment on their internal surface.

The One-Time Inspection Program is credited for managing this aging effect. During the onsite

audit, the staff inquired as to the technical basis for concluding that the One-Time Inspection

Program is adequate to manage this aging effect. By letter dated October 8, 2004, the applicant

submitted its formal response to the staff, stating that the raw water referred to in this line item

is actually potable (city) water. The chemistry of the potable water is much milder than expected

for raw water. Therefore, loss of material and fouling potentially affecting component operability

during the period of extended operation is not expected. The One-Time Inspection Program will

verify this by performing a sampling inspection. If corrosion or fouling is found to be present,

additional inspections and corrective actions may be required by the One-Time Inspection

Program.

The staff concluded that the applicant’s response is acceptable since the raw water referred to

in this line item is actually potable (city) water. The chemistry of the potable water is much

milder than expected for raw water. Therefore, loss of material and fouling potentially affecting

component operability during the period of extended operation is not expected. The One-Time

Inspection Program will verify this by performing a sampling inspection. 

No Aging Effect or Aging Management Program Identified. The applicant identified no aging

effect or AMP for heat exchangers constructed of aluminum alloy and copper alloy in an outside

air environment on the external surface. During the onsite audit, the staff inquired as to the

technical justification for concluding that there are no aging effects for this material/environment

combination for this system. By letter dated October 8, 2004, the applicant submitted its formal

response to the staff, stating that the cooling coils identified in an outside environment are in

the Freon cycle and the air flow over the coils is to cool the Freon. Therefore, condensation on

the coils will not occur and loss of material is not identified as an aging mechanism requiring

management for the period of extended operation. Air side fouling of cooling coils that have no

condensation mechanism is only a problem for fin type heat exchangers. Therefore, fouling is

not identified as an aging mechanism requiring management for the period of extended

operation.

The staff concluded that the applicant’s response is acceptable since these components are

cooling coils exposed to air flow on the outside surface. The air flow is to cool Freon inside the

coils; therefore, the air will be heated and condensation will not occur on these components.

The applicant also identified no aging effect or AMP for heat exchangers constructed of copper

alloy in an air/gas environment on their internal surface. During the onsite audit, the staff

inquired as to the technical justification for concluding that there are no aging effects for these

material and environment combinations for components in this system. By letter dated

October 8, 2004, the applicant submitted its formal response to the staff onsite audit questions

that Table 3.3.2.9, rows 131 and 132 are referring to the Freon side of the cooling coil and

correctly identify no aging effects. The material should reference Freon in the materials

description. These items are for the external surface of cooling coils and correctly identify loss

of material.
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The staff concluded that the applicant’s response is acceptable since the components will be

exposed to Freon, which is not a corrosive environment for copper alloys; and also concurred

with the corrections to Table 3.3.2.9, rows 131 and 132

3.3.2.3.10 Control Air System – Summary of Aging Management Evaluation – Table 3.3.2.10

The staff reviewed LRA Table 3.3.2.10, which summarizes the results of AMR evaluations for

the control air system component groups.

In LRA Table 3.3.2.10, the applicant identifies the aging effects of the control air system

components within the scope of license renewal and subject to AMR. The AMR lists the

materials, environments, AERMs, and AMPs credited for managing the AERMs. The AMR line

items that do not rely on the GALL Report include the following: for fittings made from carbon

and low-alloy steel in inside air, the applicant identifies loss of material due to general corrosion

and credits the Systems Monitoring Program. For components (heat exchangers, piping, and

valves) made from carbon and low-alloy steel in treated water, the applicant identifies loss of

material due to general, crevice, pitting, and galvanic corrosion, and credits the Closed-Cycle

Cooling Water System Program. Fittings, tubing, and valves made from copper alloy and

exposed to inside air (external environment) experience no AERMs and require no AMPs. 

In general RAI 3.3.2.2-1, the staff questioned whether the copper alloy components exposed to

inside air would be subject to aging effects. The staff found the applicant's assessment of the

copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3. 

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the above RAIs, the staff found the aging effects of the

above control air system component types that are not addressed by the GALL Report are

consistent with industry experience for these combinations of materials and environments. The

staff did not identify any omitted aging effects. Therefore, the staff found that the applicant had

identified the appropriate aging effects for the materials and environments associated with the

above components in the control air system.

3.3.2.3.11 Service Air System – Summary of 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 service air system component groups.

In LRA Section 3.3.2.11 and Table 3.3.2.11, the applicant identified the materials,

environments, and AERMs. The materials identified include carbon steel, alloy steel, stainless

steel, cast iron, and cast iron alloy. The applicant identified the environments to which these

materials could be exposed as air gas and inside air. The applicant identified loss of material

and loss of bolting function due to general corrosion.

The staff reviewed the LRA to determine whether the applicant had demonstrated that it would

adequately manage the effects of aging for the service air system during the period of extended

operation, as required by 10 CFR 54.21(a)(3). The staff reviewed LRA Section 3.3.2.11 and

Table 3.3.2.11 for completeness and consistency with the GALL Report and industry

experience. 
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The staff found that the applicant 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).

3.3.2.3.12 CO2 System – Summary of Aging Management Evaluation – Table 3.3.2.12

In Section 3.3.2.12 and LRA Table 3.3.2.12, the applicant identified the materials,

environments, and AMR. The materials identified include carbon steel, alloy steel, stainless

steel, aluminum, cast iron, elastomers, glass, and copper alloys. The applicant identified the

environments to which these materials could be exposed as inside air and gas. The applicant

identified loss of material from corrosion as the aging effect associated with the CO2 system

components.

The staff reviewed the LRA to determine whether the applicant had demonstrated that it would

adequately manage the effects of aging for the CO2 system during the period of extended

operation, as required by 10 CFR 54.21(a)(3). The staff reviewed LRA Section 3.3.2.12 and

Table 3.3.2.12 for completeness and consistency with the GALL Report and industry

experience.

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).

3.3.2.3.13 Station Drainage System – Summary of 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 station drainage system component groups.

In LRA Table 3.3.2.13, the applicant identifies the aging effects of the station drainage system

components within the scope of license renewal and subject to AMR. The AMR lists the

materials, environments, AERMs, and AMPs credited for managing the AERMs. The only AMR

that does not rely on the GALL Report is as follows: valves made from copper alloy and

exposed to inside air (external environment) experience no AERMs and require no AMPs. 

In general RAI 3.3.2.2-1, the staff questioned whether the copper alloy components exposed to

inside air would be subject to aging effects. The staff found the applicant's assessment of the

copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3. 

On the basis of its review of the information provided in the LRA and the applicant's

November 3, 2004, response to the staff's RAI, the staff found the applicant's assessment

consistent with industry experience for this combination of material and environment. The staff

did not identify any omitted aging effects or the need for any AMPs for this combination of

material and environment. Therefore, the staff found that there is reasonable assurance that

the intended functions of the station drainage system valves made from copper alloy and

exposed to inside air will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.29(a). 
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3.3.2.3.14 Sampling and Water Quality System – Summary of Aging Management Evaluation –

Table 3.3.2.14

The staff reviewed LRA Table 3.3.2.14, which summarizes the results of AMR evaluations for

the sampling and water quality system component groups.

In LRA Table 3.3.2.14, the applicant identified the aging effects of the sampling and water

quality system components within the scope of license renewal and subject to AMR. The AMR

lists the materials, environments, AERMs, and AMPs credited for managing the AERMs. The

AMR line items that do not rely on the GALL Report include the following: fittings, heat

exchangers, tubing, and valves made from copper alloy and exposed to inside air (external

environment) experience no AERMs and require no AMPs. Polymer components (fittings,

strainers, tubing, and valves) exposed to air/gas, inside air, and treated water experience no

AERMs and require no AMPs. Panel (Open sample panel) made from carbon and low-alloy

steel in inside air (external) is subject to loss of material due to general corrosion.

In general RAI 3.3.2.1-1 the staff questioned whether the copper alloy components exposed to

inside air would be subject to aging effects. The staff found the applicant's assessment of the

copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3. 

With respect to the polymer components, in its response to the staff's informal request of

February 11, 2005, by letter dated March 11, 2005, the applicant clarified that the polymer

components are teflon fittings in treated water, air/gas, and inside air, polymer strainers in

treated water and inside air, and polymer tubing and valves in treated water, air/gas, and inside

air environments. The applicant stated that once the proper polymer, resistant to the

environment, is chosen, there are no AERMs. The applicant further stated that industry

guidance does not identify any AERMs for this polymer and environment, but that the

components would be included in the Systems Monitoring Program to verify that there is no

hardening or loss of material strength due to polymer degradation.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the above RAIs, the staff found the aging effects of the

above AMR items are consistent with industry experience for these combinations of materials

and environments. The staff did not identify any omitted aging effects or the need for any AMPs

for the above combinations of material and environment. Therefore, the staff found that the

applicant had identified the appropriate aging effects for the materials and environments

associated with the above components in the sampling and water quality system.

3.3.2.3.15 Building Heat System – Summary of 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 building heat system component groups.

In LRA Table 3.3.2.15, the applicant identifies the aging effects of the building heat system

components within the scope of license renewal and subject to AMR. The AMR lists the

materials, environments, AERMs, and AMPs credited for managing the AERMs. The only AMR

that does not rely on the GALL Report is as follows: heaters made from copper alloy and

exposed to inside air (external environment) experience no AERMs and require no AMPs. 
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In general RAI 3.3.2.2-1, the staff questioned whether the copper alloy components exposed to

inside air would be subject to aging effects. The staff found the applicant's assessment of the

copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3.1.

On the basis of its review of the information provided in the LRA, the staff found the applicant's

assessment consistent with industry experience for this combination of material and

environment. The staff did not identify any omitted aging effects or the need for any AMPs for

this combination of material and environment. Therefore, the staff found that there is

reasonable assurance that the intended functions of the above building heat system

components will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.29(a). 

3.3.2.3.16 Raw Water Chemical Treatment System – Summary of Aging Management

Evaluation – Table 3.3.2.16

The staff reviewed LRA Table 3.3.2.16, which summarizes the results of AMR evaluations for

the raw water chemical treatment system component groups.

In LRA Table 3.3.2.16, the applicant identifies the aging effects of the raw water chemical

treatment system components within the scope of license renewal and subject to AMR. The

AMR lists the components, materials, environments, AERMs, and AMPs credited for managing

the AERMs. The AMR line items that do not rely on the GALL Report include the following:

nickel alloy components (fittings, piping, and restricting orifice) exposed to raw water

experience loss of material due to biofouling, MIC, crevice and pitting corrosion, and are

managed by the One-Time Inspection Program, while nickel alloy components (fittings, piping,

and restricting orifice) exposed to outside air experience no AERMs and require no AMPs. 

On the basis of its review of the information provided in the LRA, the staff found the aging

effects of the above raw water chemical treatment system AMR items are consistent with

industry experience for these combinations of materials and environments. The staff did not

identify any omitted aging effects. Therefore, the staff found that the applicant identified the

appropriate aging effects for the materials and environments associated with the above

components in the raw water chemical treatment system.

Loss of Material due to Biofouling, MIC, Crevice and Pitting Corrosion for Nickel Alloys in a Raw

Water Environment. The applicant identified loss of material due to biofouling, MIC, crevice and

pitting corrosion for components constructed of nickel alloy in a raw water environment on their

internal surface as an AERM. The One-Time Inspection Program is credited for managing this

aging effect. During the onsite audit the staff inquired as to the technical basis for concluding

that the One-Time Inspection Program is adequate to manage this aging effect for this

material/environment combination for components in this system. By letter dated October 8,

2004, the applicant submitted its formal response to the staff, stating that the raw water referred

to in this line item is a diluted raw water chemical treatment solution. The diluted chemicals in

these nickel alloy components minimize any aging effects that potentially affect component

operability during the period of extended operation. If corrosion is found to be present,

additional inspections and corrective actions may be required by the One-Time Inspection

Program.
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The staff concluded that the applicant’s response is acceptable since the raw water referred to

in this line item is a diluted raw water chemical treatment solution. The diluted chemicals in

these nickel alloy components minimize any aging effects that potentially affect component

operability during the period of extended operation. 

No Aging Effect or Aging Management Program Identified. The applicant identified no aging

effect or AMP for fittings, piping, and valves constructed of polymer with a raw water

environment on the internal surface. During the onsite audit, the staff inquired as to the

technical justification for concluding that there are no aging effects for this material/environment

combination for this system. By letter dated October 8, 2004, the applicant submitted its formal

response to the staff, stating that the polymer referred to in Table 3.3.2.16 is the internal

surface of polypropylene-lined carbon steel components. The LRA does not credit the lining for

prevention of corrosion and this material/environment combination should be deleted.

The staff found that the applicant’s response is acceptable, because the LRA does not credit

the lining for prevention of corrosion on the internal surface, and also concurred with the

correction to LRA Table 3.3.2.16 to delete this material/environment combination. 

3.3.2.3.17 Demineralizer Backwash Air System – Summary of Aging Management Evaluation –

Table 3.3.2.17

The staff reviewed LRA Table 3.3.2.17, which summarizes the results of AMR evaluations for

the demineralizer backwash air system component groups.

In LRA Table 3.3.2.17, the applicant identifies the aging effects of the demineralizer backwash

air system components within the scope of license renewal and subject to AMR. The AMR lists

the materials, environments, AERMs, and AMPs credited for managing the AERMs. The only

AMR that does not rely on the GALL Report is as follows: traps and valves made from copper

alloy and exposed to inside air (external environment) experience no AERMs and require no

AMPs. Traps made from copper alloy and exposed to air/gas (internal)-pooled moisture

experience loss of material due to selective leaching. 

In general RAI 3.3.2.2-1, the staff questioned whether the copper alloy components exposed to

inside air would be subject to aging effects. The staff found the applicant's assessment of the

copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3. 

LRA Table 3.3.2.17 identifies the Selective Leaching of Materials Program for managing the

aging effects described above. 

The staff's detailed review of this AMP is found in SER Section 3.0.3.1.8. 

On the basis of its review of the information provided in the LRA, the staff found the applicant's

assessment consistent with industry experience for this combination of material and

environment. The staff did not identify any omitted aging effects or the need for any AMPs for

this combination of material and environment. Therefore, the staff found that there is

reasonable assurance that the intended functions of the above demineralizer backwash air

system components will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.29(a). 
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3.3.2.3.18 Standby Liquid Control System – Summary of Aging Management Evaluation –

Table 3.3.2.18

The staff reviewed LRA Table 3.3.2.18, which summarizes the results of AMR evaluations for

the standby liquid control system component groups.

In LRA Table 3.3.2.18, the applicant identified the aging effects of the standby liquid control

system components within the scope of license renewal and subject to AMR. The AMR lists the

components, materials, environments, AERMs, and AMPs credited for managing the AERMs.

The AMR line items that do not rely on the GALL Report include the following: polymer (Derlin)

fittings exposed to inside air and treated water experience no aging effects and require no

aging management. Fittings made of carbon and low-alloy steel and exposed to air/gas

(internal) experience loss of material due to general corrosion. 

In its response to the staff's informal request February 11, 2005, by letter dated March 11,

2005,

the applicant stated that the Derlin is used as insulating flanges to prevent galvanic corrosion.

Based on its review of industry experience, the applicant determined that there are no AERMs

for Derlin in this application. Based on its review of the standby liquid control system and the

material property data sheet for Derlin, the staff concurred with the applicant's assessment.

LRA Table 3.3.2.18 identifies the One-Time Inspection Program for managing the aging effects

described above.

The staff's detailed review of this AMP is found in SER Section 3.0.3.1.7. 

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the above RAI, the staff found the aging effects of the

above AMR items are consistent with industry experience for these combinations of materials

and environments. The staff did not identify any omitted aging effects or the need for any AMPs

for the above combinations of material and environment. Therefore, the staff found that there is

reasonable assurance that the component intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.29(a). 

3.3.2.3.19 Off-Gas System – Summary of Aging Management Evaluation – Table 3.3.2.19

The staff reviewed LRA Table 3.3.2.19, which summarizes the results of AMR evaluations for

the off-gas system component groups.

In LRA Table 3.3.2.19, the applicant identified the aging effects of the off-gas system

components within the scope of license renewal and subject to AMR. The AMR lists the

materials, environments, AERMs, and AMPs credited for managing the AERMs. The only AMR

that does not rely on the GALL Report is as follows: fittings made from copper alloy and

exposed to inside air (external environment) experience no AERMs and require no AMPs.

Valves made of carbon and low-alloy steel in air/gas (internal) and inside air (external) are

subject to loss of material due to general corrosion. 
3-247

In general RAI 3.3.2.2-1, the staff questioned whether the copper alloy components exposed to

inside air would be subject to aging effects. The staff found the applicant's assessment of the

copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3. 

LRA Table 3.3.2.19 identifies the following AMPs for managing the aging effects described

above: One-Time Inspection Program and Systems Monitoring Program. The staff's detailed

review of these AMPs is found in SER Sections 3.0.3.1.7 and 3.0.3.3.1. 

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the above RAIs, the staff found the aging effects of the

above AMR items are consistent with industry experience for these combinations of materials

and environments. The staff did not identify any omitted aging effects or the need for any AMPs

for the above combinations of material and environment. Therefore, the staff found that there is

reasonable assurance that the component intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.29(a). 

3.3.2.3.20 Emergency Equipment Cooling Water System – Summary of Aging Management

Evaluation – Table 3.3.2.20

The staff reviewed LRA Table 3.3.2.20, which summarizes the results of AMR evaluations for

the emergency equipment cooling water system component groups.

In LRA Table 3.3.2.20, the applicant identifies the aging effects of the emergency equipment

cooling water system components within the scope of license renewal and subject to AMR. The

AMR lists the materials, environments, AERMs, and AMPs credited for managing the AERMs.

The AMR line items that do not rely on the GALL Report include the following: fittings, heat

exchangers, tubing, and valves made from copper alloy and exposed to inside air (external

environment) experience no AERMs and require no AMPs. Aluminum alloy heat exchanger

subcomponents in an air/gas environment experience fouling due to particulate buildup, and are

managed by the One-Time Inspection Program. 

In a RAI 3.3.2.1.20-1, dated October 12, 2004. the staff asked for additional justification that

there are no AERMs, including a loss of heat transfer, for the copper alloy heat exchanger

components in this system. In its response, by letter November 3, 2004, the applicant stated

that the components in question are the u-bend connectors for the internal cooling coil in the

room coolers. These components are likely to be exposed to condensation and, therefore, may

experience loss of material; however, they are external to the cooler such that loss of heat

transfer is not a concern. The applicant proposes to use the Systems Monitoring Program to

manage the identified aging effect. The staff found that the applicant had identified the

appropriate aging effects for the above component and had proposed an acceptable AMP.

Therefore, the staff found this acceptable.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the above RAIs, the staff found the aging effects of the

above emergency equipment cooling water system component types are consistent with

industry experience for these combinations of materials and environments. The staff did not

identify any omitted aging effects. Therefore, the staff found that the applicant had identified the

appropriate aging effects for the materials and environments associated with the above
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components in the emergency equipment cooling water system. Therefore, RAI 3.3.2.1.20-1 is

considered resolved.

3.3.2.3.21 Reactor Water Cleanup System – Summary of Aging Management Evaluation –

Table 3.3.2.21

The staff reviewed LRA Table 3.3.2.21, which summarizes the results of AMR evaluations for

the reactor water cleanup system component groups.

In LRA Table 3.3.2.21, the applicant identifies the aging effects of the reactor water cleanup

system components within the scope of license renewal and subject to AMR. The AMR lists the

materials, environments, AERMs, and AMPs credited for managing the AERMs. The only AMR

that does not rely on the GALL Report is as follows: valves made from copper alloy and

exposed to inside air (external environment) experience no AERMs and require no AMPs. Heat

exchangers made of carbon and low-alloy steel and exposed to treated water (internal)

experience loss of material due to crevice, general, and pitting corrosion. 

In general RAI 3.3.2.1-1, the staff questioned whether the copper alloy components exposed to

inside air would be subject to aging effects. The staff found the applicant's assessment of the

copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3. 

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the above RAI, the staff found the aging effects of the

above AMR items are consistent with industry experience for these combinations of materials

and environments. The staff did not identify any omitted aging effects or the need for any AMPs

for the above combinations of material and environment. Therefore, the staff found that there is

reasonable assurance that the component intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.29(a). 

LRA Table 3.3.2.21 identifies the Closed-Cycle Water Cooling System Program for managing

the aging effects described above. 

The staff's detailed review of this AMP is found in SER Section 3.0.3.2.12.

Crack Initiation and Growth due to SCC for Stainless Steel and Cast Austenitic Stainless Steel

in Treated Water Environments. The staff reviewed LRA Table 3.3.2.21, which summarized the

results of AMR evaluations for the reactor water cleanup system component groups. The

applicant identified crack initiation and growth due to SCC and change in material properties

due to thermal aging as aging effects requiring management for valves constructed of stainless

steel and CASS in a treated water environment. The applicant credited the ASME Section XI

Inservice Inspection Program to manage these aging effects. During the onsite audit, the staff

inquired as to the ASME class of these valves, whether they are currently included in the ASME

Section XI Subsections IWB, IWC and IWD Inservice Inspection Program, and the basis for

concluding that the ASME inspection will detect changes in material properties.

By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that the CASS valves that are included in this line item are the reactor water cleanup system 1-

inch root valves providing flow to and from the recently added durability monitoring panels for
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Units 2 and 3. These valves are non-nuclear Code class, therefore, the ASME Section XI

Subsections IWB, IWC and IWD Inservice Inspection Program is not applicable.

The applicant further stated that thermal embrittlement degrades the mechanical properties of

material (strength, ductility, toughness) as a result of prolonged exposure to high temperatures.

CASS materials are susceptible to thermal embrittlement. The degree of susceptibility is

dependent upon material composition and time at temperature. The maximum time these

valves would be exposed to these high temperatures would be for Unit 3. The Unit 3 valves

were installed in the spring 2000 refueling outage with a proposed license expiration date of

July 2, 2036. This represents a potential for approximately 36.5 years of operation at the

elevated temperatures. The Unit 2 valves were installed in the spring 2001 refueling outage with

a proposed license expiration date of June 28, 2034, or approximately 33.5 years of operation.

None of these CASS valves will be operated beyond their original 40-year design life and

thermal aging has not been identified as a current license basis (40 years) issue.

The applicant referenced NRC letter, "License Renewal Issue No. 98-0030, Thermal Aging

Embrittlement of Cast Austenitic Stainless Steel Components," dated May 19, 2000 from Mr. C.

I. Grimes (NRC) to D. J. Walters (NEI), to support its position that change in material properties

due to thermal aging is not a concern for these valves, citing the results of a bounding fracture

mechanics analysis for valve bodies of less than 4-inch NPS, included in Attachment 2 to this

letter. 

The applicant concluded that thermal aging of these 1-inch NPS CASS valves is not an AERM,

based on the following considerations:

 • Thermal aging is not a CLB issue and is not a concern for operation beyond forty years.

These valves will be operated for less than forty years, including the period of extended

operation.

 • Even assuming thermal aging for valves is a CLB concern, the conclusion from the

NRC's bounding fracture analysis for valves less than NPS 4 was that "a CASS valve

loaded to the maximum anticipated stress can sustain a through wall crack well in

excess of its wall thickness without fracturing" and "that requirements for licensees to

either (a) inspect . . . of these components would represent an unnecessary duplication

of effort." 

However, to resolve this issue, the applicant stated that thermal aging will be identified in the

LRA as being an AERM for these 1-inch NPS non-Class 1 valves, and that the Systems

Monitoring Program will be identified as the AMP to perform an external visual inspection.

The staff concluded that the applicant’s response is acceptable on the basis that: (1) the valves

have operating lives less than 40 years; (2) NRC-sponsored fracture mechanics analyses

demonstrate a high degree of flaw tolerance, including through-wall cracking; and (3) periodic

external visual examination conducted as part of the Systems Monitoring Program will detect

through-wall cracking, in the unlikely event that it should occur.

During the onsite audit, the staff also asked why the BWR Stress Corrosion Cracking Program

is not credited for this aging effect in all cases. By letter dated October 8, 2004, the applicant

submitted its formal response to the staff, stating that Table 3.3.2.21, lines 24 and 54 refer to
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fittings and piping that are less than 4-inch NPS. The corresponding GALL Report Volume 2,

Item IV.C1.1-i, references the ASME Section XI Subsections IWB, IWC, and IWD Inservice

Inspection Program, the Chemistry Control Program, and the One-Time Inspection Program.

For fittings and piping greater than or equal to 4-inch NPS, line items 27 and 56 specify the

BRW Stress Corrosion Cracking Program and the Chemistry Control Program, which is

consistent with Item IV.C1.1-f. Table 3.3.2.21, line 102 credits the BWR Stress Corrosion

Cracking Program and the chemistry control program for aging management of Valves-RCPB,

which is consistent with IV.C1.3-c. Note that the BWR Stress Corrosion Cracking Program

invokes the ASME Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program

for inspection and flaw evaluation to monitor IGSCC.

The applicant further stated that LRA Table 3.3.2.21, rows 20, 49, and 93, for non-reactor

coolant pressure boundary fittings, piping, and valves, respectively, incorrectly listed the ASME

Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program and/or BWR Stress

Corrosion Cracking Program. The correct AMPs for rows 20, 49, and 93 are the Chemistry

Control Program and One-Time Inspection Program.

The staff found that the applicant’s use of the ASME Code Section XI Program for components

less than 4" NPS is consistent with the GALL Report, and also concurred with the applicant’s

corrections to LRA Table 3.3.2.21. The staff found the applicant’s response to be acceptable.

3.3.2.3.22 Reactor Building Closed Cooling Water System – Summary of Aging Management

Evaluation – Table 3.3.2.22

The staff reviewed LRA Table 3.3.2.22, which summarizes the results of AMR evaluations for

the reactor building closed cooling water system component groups.

In LRA Table 3.3.2.22, the applicant identifies the aging effects of the reactor building closed

cooling water system components within the scope of license renewal and subject to AMR. The

AMR lists the materials, environments, AERMs, and AMPs credited for managing the AERMs.

The AMR line items that do not rely on the GALL Report include the following: fittings, piping,

and valves made from copper alloy and exposed to inside air (external environment) experience

no AERMs and require no AMPs. Carbon and low-alloy steel components (fittings, heat

exchangers, piping, pumps, tanks, and valves) in treated water are exposed to loss of material

due to general, pitting, crevice, and galvanic corrosion, and are managed by the Closed-Cycle

Cooling Water System Program. 

In general RAI 3.3.2.1-1, the staff questioned whether the copper alloy components exposed to

inside air would be subject to aging effects. The staff found the applicant's assessment of the

copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3. 

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the RAI, the staff found the aging effects of the above

reactor building closed cooling water system component types are consistent with industry

experience for these combinations of materials and environments. The staff did not identify any

omitted aging effects. Therefore, the staff found that the applicant had identified the appropriate

aging effects for the materials and environments associated with the above components in the

reactor building closed cooling water system.
3-251

3.3.2.3.23 Reactor Core Isolation Cooling System – Summary of Aging Management

Evaluation – Table 3.3.2.23

The staff reviewed LRA Table 3.3.2.23, which summarizes the results of AMR evaluations for

the reactor core isolation cooling system component groups.

In LRA Table 3.3.2.23, the applicant identified the aging effects of the reactor core isolation

cooling system components within the scope of license renewal and subject to AMR. The AMR

lists the materials, environments, AERMs, and AMPs credited for managing the AERMs. The

AMR line items that do not rely on the GALL Report include the following: heat exchangers,

pumps, strainers, and valves made from copper alloy and exposed to inside air (external

environment) experience no AERMs and require no AMPs. Aluminum alloy fittings in treated

water experience crack initiation and growth due to SCC and loss of material due to crevice,

pitting, and galvanic corrosion, and are managed with the Chemistry Control Program and the

One-Time Inspection Program. Copper alloy valves in treated water can experience loss of

material due to flow-accelerated corrosion, and are managed through the Flow-Accelerated

Corrosion Program.

In general RAI 3.3.2.2-1, the staff questioned whether the copper alloy components exposed to

inside air would be subject to aging effects. The staff found the applicant's assessment of the

copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3. 

In RAI 3.3.2.1.23-1, dated October 12, 2004, the staff requested the applicant to explain why

loss of heat transfer is not an applicable AERM for the copper alloy heat exchanger

components in inside air. In its response dated November 3, 2004, the applicant clarified that

these components are the connectors for the lube oil lines going to the internal copper tubes.

The staff concluded that heat transfer is not an intended function for these connectors. In

addition, these connectors remain above ambient temperature, such that there is no

condensation that would lead to other aging effects. The staff concurred that there will be no

other aging effects in the absence of condensation or pooling. Based on the above, the staff

found the applicant's response acceptable. 

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the RAI, the staff found the aging effects of the above

reactor core isolation cooling system component types are consistent with industry experience

for these combinations of materials and environments. The staff did not identify any omitted

aging effects. Therefore, the staff found that the applicant had identified the appropriate aging

effects for the materials and environments associated with the above components in the reactor

core isolation cooling system.

3.3.2.3.24 Auxiliary Decay Heat Removal System – Summary of Aging Management

Evaluation – Table 3.3.2.24

The staff reviewed LRA Table 3.3.2.24, which summarizes the results of AMR evaluations for

the auxiliary decay heat removal system component groups.

In LRA Section 3.3.2.24 and Table 3.3.2.24, the applicant identified the materials,

environments, and AERMs. The materials identified include carbon steel, low-alloy steel, and

stainless steel. The applicant identified the environments to which these materials could be
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exposed as air gas and inside air. The applicant identified loss of material from general and

pitting corrosion and of bolting function due to general corrosion.

The staff reviewed the LRA to determine whether the applicant had demonstrated that it would

adequately manage the effects of aging for the auxiliary decay heat removal system during the

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff reviewed LRA

Section 3.3.2.24 and Table 3.3.2.24 for completeness and consistency with the GALL Report

and industry experience. 

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).

3.3.2.3.25 Radioactive Waste Treatment System – Summary of Aging Management Evaluation

– Table 3.3.2.25

The staff reviewed LRA Table 3.3.2.25, which summarizes the results of AMR evaluations for

the radioactive waste treatment system component groups.

In LRA Table 3.3.2.25, the applicant identifies the aging effects of radioactive waste treatment

system components within the scope of license renewal and subject to AMR. The AMR lists the

materials, environments, AERMs, and AMPs credited for managing the AERMs. The AMR line

items that do not rely on the GALL Report include the following: valves made from copper alloy

and exposed to inside air (external environment) experience no AERMs and require no AMPs. 

Carbon and low-alloy steel components (fittings, piping, and valves) in raw water experience

loss of material due to general, crevice, and pitting corrosion, galvanic corrosion, and MIC, and

are managed through the One-Time Inspection Program. Carbon and low-alloy steel

components (fittings, piping, and valves) in treated water experience loss of material due to

general, crevice, pitting, and galvanic corrosion, and are managed by the One-Time Inspection

Program. For cast iron and cast iron alloy pumps in treated water, the applicant uses the

One-Time Inspection Program to manage loss of material due to general, crevice and pitting

corrosion. 

For elastomer (neoprene and silicon) fittings in air/gas and inside air, the applicant does not

identify any AERMs or AMPs. 

Additional items the technical staff was also asked to review include the following AMR line

items that do not rely on the GALL Report: aluminum alloy fittings and piping in treated water

may experience crack initiation and growth due to SCC and a loss of material due to crevice

and pitting corrosion, and are managed by the Chemistry Control Program and the One-Time

Inspection Program, while the aluminum alloy in air experiences no AERMs. For the copper

alloy (bronze) fittings, the bronze in treated water may experience a loss of material due to

crevice and pitting corrosion and loss of material due to selective leaching, which are managed

by the One-Time Inspection Program and Selective Leaching of Materials Program,

respectively, while the bronze in inside air experiences no AERMs. For the cast iron and cast

iron alloy strainers, the side exposed to treated water may experience loss of material due to

general, crevice, and pitting corrosion and a loss of material due to selective leaching, which

are managed by the One-Time Inspection Program and the Selective Leaching of Materials
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Program, respectively, while the side in inside air experiences loss of material due to general

corrosion and is managed through the Systems Monitoring Program. 

In general RAI 3.3.2.2-1, the staff questioned whether the copper alloy components exposed to

inside air would be subject to aging effects. The staff found the applicant's assessment of the

copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3. 

In RAI 3.3.2.1.23-1, dated October 12, 2004, the staff asked for additional information related to

elastomer components, since the applicant determined that there are no AERMs based on

industry guidance. The degradation of elastomers depends on the environmental factors such

as the temperature, radiation levels, and presence of aggressive chemicals (aggressive

chemicals are not anticipated for this system). In its response dated November 3, 2004, the

applicant demonstrated that the temperature and radiation levels remain below the thresholds

for which there is significant aging of the silicon and neoprene. Therefore, the staff concurred

with the applicant's assessment. 

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's responses to the RAIs, the staff found the aging effects of the above

radioactive waste treatment system component types are consistent with industry experience

for these combinations of materials and environments. The staff did not identify any omitted

aging effects. Therefore, the staff found that the applicant identified the appropriate aging

effects for the materials and environments associated with the above components in the

radioactive waste treatment system.

3.3.2.3.26 Fuel Pool Cooling and Cleanup System – Summary of Aging Management

Evaluation – Table 3.3.2.26

The staff reviewed LRA Table 3.3.2.26, which summarizes the results of AMR evaluations for

the fuel pool cooling and cleanup system component groups.

In LRA Table 3.3.2.26, the applicant identifies the aging effects of the spent fuel pool cooling

and cleanup system components within the scope of license renewal and subject to AMR. The

AMR lists the materials, environments, AERMs, and AMPs credited for managing the AERMs.

The AMR line items that do not rely on the GALL Report include the following: for aluminum

alloy components (fittings, piping, and valves) in treated water, the applicant identifies crack

initiation and growth due to SCC and loss of material due to crevice and pitting corrosion, and

galvanic corrosion, and credits the Chemistry Control Program and the One-Time Inspection

Program.

On the basis of its review of the information provided in the LRA, the staff found the aging

effects of the above spent fuel pool cooling and cleanup system component types are

consistent with industry experience for these combinations of materials and environments. The

staff did not identify any omitted aging effects. Therefore, the staff found that the applicant

identified the appropriate aging effects for the materials and environments associated with the

above components in the spent fuel pool cooling and cleanup system. 
3-254

3.3.2.3.27 Fuel Handling and Storage System – Summary of Aging Management Evaluation –

Table 3.3.2.27

The staff reviewed LRA Table 3.3.2.27, which summarizes the results of AMR evaluations for

the fuel handling and storage system component groups.

In Section 3.3.2.27 and LRA Table 3.3.2.27, the applicant identified the materials,

environments, and AERMs. The materials identified include aluminum alloy, carbon steel,

low-alloy steel, and stainless steel. The applicant identified the environments to which these

materials could be exposed as inside air and treated water. The applicant identified loss of

material from crack initiation and growth due to stress corrosion; loss of material due to crevice,

pitting, general, and galvanic corrosion of bolting function due to stress relaxation; and loss of

material due to mechanical wear.

The staff reviewed the LRA to determine whether the applicant had demonstrated that it would

adequately manage the effects of aging for the service air system during the period of extended

operation, as required by 10 CFR 54.21(a)(3). Additionally, the staff considered the aging effect

loss of of bolting function due to stress relaxation, which is addressed in SER Section 3.3.2.36.

The staff reviewed LRA Section 3.3.2.27 and Table 3.3.2.27 for completeness and consistency

with the GALL Report and industry experience. 

3.3.2.3.28 Diesel Generator System – Summary of Aging Management Evaluation –

Table 3.3.2.28

The staff reviewed LRA Table 3.3.2.28, which summarizes the results of AMR evaluations for

the diesel generator system component groups.

In LRA Table 3.3.2.28, the applicant identifies the aging effects of the diesel generator system

components within the scope of license renewal and subject to AMR. The AMR lists the

materials, environments, AERMs, and AMPs credited for managing the AERMs. The AMR line

items that do not rely on the GALL Report include the following: fittings, piping, tubing, and

valves made from copper alloy and exposed to inside air (external environment) experience no

AERMs and require no AMPs. For stainless steel fittings in treated water, the applicant

identifies crack initiation/growth due to SCC and loss of material due to crevice and pitting

corrosion, and credits the Closed-Cycle Cooling Water Program. For flexible connectors made

from elastomer and exposed to treated water (internal) and inside air (external), the applicant

identifies elastomer degradation due to thermal exposure and credits the Systems Monitoring

Program. For flexible connectors made from elastomer and exposed to inside air, the applicant

identifies elastomer degradation due to thermal exposure and ultraviolet radiation, and credits

the Systems Monitoring Program. LRA Table 3.3.2.28 also identifies wear as an AERM for the

elastomer flexible connectors, and credits the Systems Monitoring Program.

In general RAI 3.3.2.2-1, the staff questioned whether the copper alloy components exposed to

inside air would be subject to aging effects. The staff found the applicant's assessment of the

copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3. 

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the above RAI, the staff found the aging effects of the

above diesel generator system component types are consistent with industry experience for
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these combinations of materials and environments. The staff did not identify any omitted aging

effects. Therefore, the staff found that the applicant identified the appropriate aging effects for

the materials and environments associated with the above components in the diesel generator

system.

Crack Initiation and Growth due to SCC for Copper Alloys and Stainless Steel in Raw Water

Environments. The applicant identified crack initiation and growth due to SCC as an AERM for

heat exchangers constructed of copper alloy in a raw water environment. The applicant credited

the Open-Cycle Cooling Water System Program to manage this aging effect. The staff asked

how the Open-Cycle Cooling Water System Program will detect cracking prior to the loss of

intended function for these components. By letter dated October 8, 2004, the applicant

submitted its formal response to the staff, stating that the Open-Cycle Cooling Water System

Program is implemented by a variety of maintenance, inspection, and testing procedures. The

primary method of detecting cracking in heat exchangers is eddy current testing in accordance

with the heat exchanger program (NEDP-17). This procedure requires the heat exchanger

engineer to coordinate and schedule heat exchanger activities. The actual inspections are

scheduled as preventive maintenance tasks. In particular, the diesel generator cooling water

heat exchangers are scheduled with a frequency of two years.

The staff concluded that the applicant’s response is acceptable for this material and

environment combination since the Open-Cycle Cooling Water System Program is implemented

by a variety of maintenance, inspection, and testing procedures, which include eddy current

testing in accordance with the heat exchanger program. Eddy current testing will detect

cracking. 

3.3.2.3.29 Control Rod Drive System – Summary of Aging Management Evaluation –

Table 3.3.2.29

The staff reviewed LRA Table 3.3.2.29, which summarizes the results of AMR evaluations for

the CRD system component groups.

In LRA Table 3.3.2.29, the applicant identifies the aging effects of the CRD system components

within the scope of license renewal and subject to AMR. The AMR lists the materials,

environments, AERMs, and AMPs credited for managing the AERMs. The AMR line items that

do not rely on the GALL Report include the following: fittings, heat exchangers, and valves

made from copper alloy and exposed to inside air (external environment) experience no AERMs

and require no AMPs. Aluminum alloy fittings in treated water are subjected to crack

initiation/growth due to SCC and loss of material due to crevice and pitting corrosion, and are

managed by the Chemistry Control Program and the One-Time Inspection Program.

In general RAI 3.3.2.2-1, the staff questioned whether the copper alloy components exposed to

inside air would be subject to aging effects. The staff found the applicant's assessment of the

copper alloy components to be acceptable, as discussed in SER Section 3.3.2.3.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the above RAI, the staff found the aging effects of the

above CRD system component types are consistent with industry experience for these

combinations of materials and environments. The staff did not identify any omitted aging
3-256

effects. Therefore, the staff found that the applicant identified the appropriate aging effects for

the materials and environments associated with the above components in the CRD system. 

Crack Initiation and Growth due to SCC for Stainless Steel and Cast Austenitic Stainless Steel

in Treated Water Environments The applicant identified loss of material due to corrosion as an

AERM for fittings, piping, strainers, and valves constructed of stainless steel in a treated water

environment. However, cracking due to SCC was only identified for valves. The staff inquired as

to why cracking due to SCC was not identified for stainless steel fittings, piping, and strainers in

a treated water environment for this system. By letter dated October 8, 2004, the applicant

submitted its formal response to the staff, stating that stainless steel components have the

potential for corrosion if the chemistry control program is not properly implemented. However,

stress corrosion cracking only requires an AMP where the normal operating temperature is

greater than 140 °F. The AMR identifies that the CRD system RCPB components (valves) that

interface with the reactor water cleanup system experience normal operating temperatures in

excess of 140 °F. These closed valves are the only components in the CRD system that exceed

140 °F.

The staff concluded that the applicant’s determination that cracking due to SCC is only

applicable to RCPB valves in the CRD system is acceptable since these are the only

components that operate at temperatures above 140 °F.

3.3.2.3.30 Diesel Generator Starting Air System – Summary of Aging Management Evaluation

– Table 3.3.2.30

The staff reviewed LRA Table 3.3.2.30, which summarizes the results of AMR evaluations for

the diesel generator starting air system component groups.

In LRA Table 3.3.2.30, the applicant identifies the aging effects of the diesel generator starting

air system components within the scope of license renewal and subject to AMR. The AMR lists

the materials, environments, AERMs, and AMPs credited for managing the AERMs. The AMR

line items that do not rely on the GALL Report include the following: fittings, flexible connectors,

piping, tubing, and valves made from copper alloy and exposed to inside air (external

environment) experience no AERMs and require no AMPs. Flexible connectors made of

elastomer in an air/gas (internal) and inside air (external) environment exhibit no AERMs and

require no AMPs. Strainers made of stainless steel in an air/gas (internal) and inside air

(external) environment exhibit no AERMs and require no AMPs. 

In a general RAI, the staff questioned whether the copper alloy components exposed to inside

air would be subject to aging effects. The staff found the applicant's assessment of the copper

alloy components to be acceptable, as discussed in SER Section 3.3.2.3. 

Depending on the environmental conditions such as temperature, ultraviolet radiation, and

aggressive chemicals, there is the potential for elastomers to experience aging effects and

require aging management. The applicant was asked to clarify that there are no aging effects

commensurate with the environment exposed to or to provide appropriate aging management

for these components (as they have done for numerous other systems); however, the applicant

discussed the diesel generator system instead.
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By letter dated May 24, 2005 the applicant submitted additional information in regard to the

management of elastomers in the diesel generator starting air system. The applicant clarified

that the rubber flexible connector can be exposed to a maximum temperature of about 115 °F

and, conservatively, thermal stress is considered an applicable aging effect. The applicant

identified that the Systems Monitoring Program will be used to manage the external surface and

the internal surface will be managed by the One-Time Inspection Program. The applicant also

clarified that no specific recommendations were provided by the manufacturer regarding service

life and appropriate inspections. 

The staff reviewed the applicant’s response and found the response to be reasonable and

acceptable because the applicant identified that the external and internal surfaces of the rubber

flexible connectors will be managed by the Systems Monitoring Program and the One-Time

Inspection Program, respectively. There is reasonable assurance that these AMPs are capable

of detecting and correcting degradation of the elastomers caused by thermal or other

environmental aging factors prior to adversely affecting the intended function of the

components. 

On the basis of its review of the information provided in the LRA and the RAI response, the staff

found the applicant's assessment consistent with industry experience for this combination of

material and environment. The staff did not identify any omitted aging effects or the need for

any AMPs for this combination of material and environment. Therefore, the staff found that

there is reasonable assurance that the intended functions of the above components of the

diesel generator starting air system will be maintained consistent with the CLB for the period of

extended operation, as required by 10 CFR 54.29(a). 

3.3.2.3.31 Radiation Monitoring System – Summary of Aging Management Evaluation –

Table 3.3.2.31

The staff reviewed LRA Table 3.3.2.31, which summarizes the results of AMR evaluations for

the radiation monitoring system component groups.

In LRA Table 3.3.2.31, the applicant identifies the aging effects of the radiation monitoring

system components within the scope of license renewal and subject to AMR. The AMR lists the

materials, environments, AERMs, and AMPs credited for managing the AERMs. The AMR line

items that do not rely on the GALL Report include the following: fittings, pumps, strainers, and

valves made from copper alloy and exposed to inside air (external environment) experience no

AERMs and require no AMPs. Traps made from aluminum alloy exposed to raw water are

subjected to crack initiation/growth due to SCC, and will be managed by the One-Time

Inspection Program. Tubing made from polymer (tygon) in air/gas experience no AERMs and

require no AMPs.

In a general RAI, the staff questioned whether the copper alloy components exposed to inside

air would be subject to aging effects. The staff found the applicant's assessment of the copper

alloy components to be acceptable, as discussed in SER Section 3.3.2.3. 

With respect to the polymer components, in response to the staff's informal request of

February 11, 2005, by letter dated March 11, 2005, the applicant clarified that the polymer

components are tygon tubing in air/gas and inside air. The applicant stated that once the proper

polymer, resistant to the environment, is chosen, there are no AERMs. The applicant further
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stated that industry guidance does not identify any AERMs for this polymer and environment,

but the components would be included in the Systems Monitoring Program to verify that there is

no hardening or loss of material strength due to polymer degradation.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant's response to the above RAIs, the staff found the aging effects of the

above radiation monitoring system component types are consistent with industry experience for

these combinations of materials and environments. The staff did not identify any omitted aging

effects. Therefore, the staff found that the applicant had identified the appropriate aging effects

for the materials and environments associated with the above components in the radiation

monitoring system 

3.3.2.3.32 Neutron Monitoring System – Summary of Aging Management Evaluation –

Table 3.3.2.32

The staff reviewed LRA Table 3.3.2.32, which summarizes the results of AMR evaluations for

the neutron monitoring system component groups.

In LRA Section 3.3.2.32 and Table 3.3.2.32, the applicant identified the materials,

environments, and AERMs. The materials identified include carbon steel, and low-alloy steel.

The applicant identified the environments to which these materials could be exposed as air gas

and inside air. The applicant identified loss of material from crack initiation and growth due to

stress corrosion and cyclic loading, loss of bolting function due to general corrosion and wear

and loss of material due to crevice and pitting corrosion.

The staff reviewed the LRA to determine whether the applicant had demonstrated that it would

adequately manage the effects of aging for the neutron monitoring system during the period of

extended operation, as required by 10 CFR 54.21(a)(3). The staff reviewed LRA

Section 3.3.2.32 and Table 3.3.2.32 for completeness and consistency with the GALL Report

and industry experience. 

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).

3.3.2.3.33 Traversing In-Core Probe System – Summary of Aging Management Evaluation –

Table 3.3.2.33

The staff reviewed LRA Table 3.3.2.33, which summarizes the results of AMR evaluations for

the traversing in-core probe system component groups.

In LRA Section 3.3.2.33 and Table 3.3.2.33, the applicant identified the materials,

environments, and AERMs. The materials identified include stainless steel. The applicant

identified the environments to which these materials could be exposed as air gas and inside air.

The applicant has not identified any loss of material nor any aging effects.

The staff reviewed LRA Section 3.3.2.33 and Table 3.3.2.33 for completeness and consistency

with the GALL Report and industry experience. 
3-259

The staff found that the applicant 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).

3.3.2.3.34 Cranes System – Summary of Aging Management Evaluation – Table 3.3.2.34

The staff reviewed LRA Table 3.3.2.34, which summarizes the results of AMR evaluations for

the cranes system component groups.

In Section 3.3.2.34 and LRA Table 3.3.2.34, the applicant identified the materials,

environments, and AERMs. The materials identified include carbon steel, and low-alloy steel.

The applicant identified the environments to which these materials could be exposed as inside

air. The applicant identified loss of material from crack initiation, loss of bolting function due to

stress relaxation and wear, loss of material due to general corrosion and mechanical wear.

The staff reviewed the LRA to determine whether the applicant had demonstrated that it would

adequately manage the effects of aging for the cranes system during the period of extended

operation, as required by 10 CFR 54.21(a)(3). Additionally, the staff considered the aging

effect, loss of of bolting function due to stress relaxation, which is addressed in SER

Section 3.3.2.36. The staff reviewed LRA Section 3.3.2.34 and Table 3.3.2.34 for completeness

and consistency with the GALL Report and industry experience. 

The staff found that the applicant demonstrated that the effects of aging will be adequately

managed so that the intended functions will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21(a)(3).

Conclusion. On the basis of its review, the staff found that the applicant had appropriately

evaluated AMR results involving material, environment, aging effects requiring management,

and AMP combinations that are not evaluated in the GALL Report for entries shown in

Table 3.3-1. 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 LRA Table 3.3.2.9, which summarized the results of AMR evaluations

for the heating, ventilation, and air conditioning system component groups.

The applicant identified no aging effect or AMP for heat exchangers constructed of aluminum

alloy and copper alloy in an outside air environment on the external surface. The staff inquired

as to the technical justification for concluding that there are no aging effects for this

material/environment combination for this system. By letter dated October 8, 2004, the

applicant submitted its formal response to the staff, stating that the cooling coils identified in an

outside environment are in the Freon cycle and the air flow over the coils is to cool the Freon.

Therefore, condensation on the coils; will not occur and loss of material is not identified as an

aging mechanism requiring management for the period of extended operation. Air side fouling

of cooling coils that have no condensation mechanism is only a problem for fin type heat

exchangers. Therefore, fouling is not identified as an aging mechanism requiring management

for the period of extended operation.
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The staff concluded that the applicant’s response is acceptable since these components are

cooling coils exposed to air flow on the outside surface. The air flow is to cool Freon inside the

coils; therefore, the air will be heated and condensation will not occur on these components.

The applicant also identified no aging effect or AMP for heat exchangers constructed of copper

alloy in an air/gas environment on their internal surface. The staff inquired as to the technical

justification for concluding that there are no aging effects for these material and environment

combinations for components in this system. By letter dated October 8, 2004, the applicant

submitted its formal response to the staff, stating that Table 3.3.2.9, rows 131 and 132 are

referring to the Freon side of the cooling coil and correctly identify no aging effects. The

material should reference Freon in the materials description. These items are for the external

surface of cooling coils and correctly identify loss of material.

The staff concluded that the applicant’s response is acceptable since the components will be

exposed to Freon, which is not a corrosive environment for copper alloys. The staff also

concurred with the corrections to Table 3.3.2.9, rows 131 and 132. 

The staff reviewed LRA Table 3.3.2.2, which summarized the results of AMR evaluations for the

fuel oil system component groups. The applicant identified no aging effect or AMP for

components constructed of cast iron and cast iron alloy, as well as carbon or low-alloy steel in

an air/gas environment on their internal surface. The staff inquired as to the technical

justification for concluding that there are no aging effects for these material/environment

combinations for components in this system. By letter dated October 8, 2004, the applicant

submitted its formal response to the staff, stating that components in the fuel oil system are

exposed to a fuel oil vapor environment. This fuel oil vapor environment protects the component

surfaces and prevents internal corrosion. 

The staff concluded that the applicant’s determination of no AERM for components in the fuel

oil system in an air/gas environment on the internal surface is acceptable since the components

will be exposed to fuel oil vapor, which will protect the surfaces of the components from

corrosion. 

The staff reviewed LRA Table 3.3.2.3, which summarized the results of AMR evaluations for the

residual heat removal service water system component groups.

The applicant identified no aging effect or AMP for components constructed of cast iron and

cast iron alloy, as well as carbon or low-alloy steel in an embedded/encased environment on

their external surface. The staff inquired as to the technical justification for concluding that there

are no aging effects for these material and environment combinations for components in this

system. By letter dated October 8, 2004, the applicant submitted its formal response to the

staff, stating that no aging effects are identified for embedded/encased components. If

excessive corrosion that could prevent the performance of the intended functions during the

period of extended operation was detected on the inside surface or outside surface in air

environments adjacent to the embedded/encased portions, corrective actions would be taken to

restore the component, including the embedded/encased portions, if this was determined to be

necessary.

The staff concluded that the applicant’s determination of no AERM for components in the

residual heat removal service water system in an embedded/encased environment is

acceptable since exposure to a corrosive environment will be limited. Inspections will be
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performed on adjacent surfaces exposed to an air environment. If corrosion is detected on

adjacent surfaces in an air environment, corrective actions will be taken to restore the

component, including the embedded/encased portions, if this is determined to be necessary.

The staff reviewed LRA Table 3.3.2.16, which summarized the results of AMR evaluations for

the raw water chemical treatment system component groups.

The applicant identified no aging effect or AMP for fittings, piping, and valves constructed of

polymer with a raw water environment on the internal surface. The staff inquired as to the

technical justification for concluding that there are no aging effects for this material/environment

combination for this system. By letter dated October 8, 2004, the applicant submitted its formal

response to the staff, stating that the polymer referred to in Table 3.3.2.16 is the internal

surface of polypropylene-lined carbon steel components. The LRA does not credit the lining for

prevention of corrosion and this material/environment combination should be deleted.

The staff found that the applicant’s response is acceptable, because the LRA does not credit

the lining for prevention of corrosion on the internal surface. The staff also concurred with the

correction to Table 3.3.2.16, to delete this material/environment combination. 

3.3.3 Conclusion

The staff concluded that the applicant had provided sufficient information to demonstrate that

the effects of aging on the auxiliary systems components that are within the scope of license

renewal and subject to an AMR will be adequately managed so that the intended function(s) will

be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3).

The staff also reviewed the applicable UFSAR 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).
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3.4 Aging Management of Steam and Power Conversion System

This section of the SER documents the staff’s review of the applicant’s AMR results for the

steam and power conversion system components and component groups associated with the

following systems:

 • main steam

 • condensate and demineralized water

 • feedwater

 • heater drains and vents

 • turbine drains and miscellaneous piping

 • condenser circulating water

 • gland seal water

3.4.1 Summary of Technical Information in the Application

In LRA Section 3.4, the applicant provided AMR results for components. In LRA Table 3.4.1,

“Summary of Aging Management Evaluations for Steam and Power Conversion System

Evaluated in Chapter VIII of NUREG-1801,” the applicant provided a summary comparison of

its AMRs with the AMRs evaluated in the GALL Report for the steam and power conversion

system 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.

3.4.2 Staff Evaluation

The staff reviewed LRA Section 3.4 to determine if the applicant had provided sufficient

information to demonstrate that the effects of aging for the steam and power conversion system

components that are within the scope of license renewal and subject to an AMR will be

adequately managed so that the intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

The staff performed an onsite audit, during the weeks of June 21 and July 26, 2004, of AMRs to

confirm the applicant’s claim that certain identified AMRs were consistent with the GALL

Report. The staff did not repeat its review of the matters described in the GALL Report;

however, the staff did verify that the material presented in the LRA was applicable and that the

applicant had identified the appropriate GALL AMRs. The staff’s evaluations of the AMPs are

documented in SER Section 3.0.3. Detail of the staff’s audit evaluation are documented in the

BFN audit and review report and are summarized in SER Section 3.4.2.1.

In the onsite audit, the staff also 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 SRP-LR Section 3.4.2.2. The staff’s
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audit evaluations are documented in the audit and review report and are summarized in SER

Section 3.4.2.2.

In the onsite audit, the staff conducted a technical review of the remaining AMRs that are 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 evaluating whether the

aging effects listed were appropriate for the combinations of materials and environments

specified. The staff’s audit evaluations are documented in the BFN audit and review report and

are summarized in SER Section 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 UFSAR 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 Components in

the GALL Report

Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

Piping and fittings in

main feedwater line,

steam line and in

auxiliary feedwater

(AFW) piping (PWR

only)

(Item Number

3.4.1.1)

Cumulative fatigue

damage

TLAA, evaluated in

accordance with

10 CFR 54.21(c)

TLAA This TLAA is

evaluated in

Section 4.3, Metal

Fatigue

Piping and fittings,

valve bodies and

bonnets, pump

casings, tanks,

tubes, tubesheets,

channel head and

shell (except main

steam system)

(Item Number

3.4.1.2)

Loss of material

due to general

(carbon steel only),

pitting, and crevice

corrosion

Chemistry Control

Program; One-Time

Inspection Program

Chemistry Control

Program; One-Time

Inspection Program

Consistent with

GALL which

recommends further

evaluation (See

Section 3.4.2.2.2)

External surface of

carbon steel

components

(Item Number

3.4.1.5)

Loss of material

due to general

corrosion

Plant-specific Systems Monitoring

Program

See Section

3.4.2.2.4
Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

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Carbon steel piping

and valve bodies

(Item Number

3.4.1.6)

Wall thinning due to

flow-accelerated

corrosion

Flow-Accelerated

Corrosion Program

Flow-Accelerated

Corrosion Program

Consistent with

GALL which

recommends no

further evaluation

(See Section

3.4.2.1)

Carbon steel piping

and valve bodies to

main steam system

(Item Number

3.4.1.7)

Loss of material

due to pitting and

crevice corrosion

Chemistry Control

Program

Chemistry Control

Program

Consistent with

GALL, with

exceptions, which

recommends no

further evaluation

(See Section

3.4.2.1)

Closure bolting in

high-pressure or

high-temperature

systems

(Item Number

3.4.1.8)

Loss of material

due to general

corrosion; crack

initiation and growth

due to cyclic

loading and/or SCC

Bolting Integrity

Program

Bolting Integrity

Program

Consistent with

GALL with

exceptions, which

recommends no

further evaluation

(See Section

3.4.2.1)

Heat exchangers

and

coolers/condensers

serviced by

open-cycle cooling

water

(Item Number

3.4.1.9)

Loss of material

due to general

(carbon steel only),

pitting, and crevice

corrosion, MIC, and

biofouling; buildup

of deposit due to

biofouling

Open-Cycle Cooling

Water System

Program

Open-Cycle Cooling

Water System

Program

Consistent with

GALL which

recommends no

further evaluation

(See Section

3.4.2.1)

Heat exchangers

and

coolers/condensers

serviced by

closed-cycle cooling

water

(Item Number

3.4.1.10)

Loss of material

due to general

(carbon steel only),

pitting, and crevice

corrosion

Closed-Cycle

Cooling Water

System Program

Closed-Cycle

Cooling Water

System Program

Consistent with

GALL which

recommends no

further evaluation

(See Section

3.4.2.1)

External surface of

aboveground

condensate storage

tank

(Item Number

3.4.1.11)

Loss of material

due to general

(carbon steel only),

pitting, and crevice

corrosion

Aboveground

Carbon Steel Tanks

Program

Aboveground

Carbon Steel Tanks

Program

Consistent with

GALL which

recommends no

further evaluation

(See Section

3.4.2.1)
Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

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External surface of

buried condensate

storage tank and

AFW piping

(Item Number

3.4.1.12)

Loss of material

due to general,

pitting, and crevice

corrosion; MIC

Buried piping and

tanks surveillance 

Buried piping and

tanks inspection

N/A Not applicable

At BFN, the

condensate storage

tanks and piping

and fittings

associated with the

condensate storage

tank are not located

underground

The staff’s review of the BFN component groups 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 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 3.4.2.3, 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, or 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.

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 AERMs. The applicant identified the following

programs that manage the aging effects related to the steam and power conversion system

components:

 • ASME Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program

 • Bolting Integrity Program

 • BWR stress corrosion cracking program

 • Chemistry Control Program

 • Compressed Air Monitoring Program

 • Flow-Accelerated Corrosion Program

 • One-Time Inspection Program

 • Systems Monitoring Program

 • Aboveground Carbon Steel Tanks Program

 • Selective Leaching of Materials Program

 • Buried Piping and Tanks Inspection Program
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Staff Evaluation. In LRA Tables 3.4.2-1 through 3.4.2-7, the applicant provided a summary of

AMRs for the steam and power conversion system components, and identified which AMRs it

considered to be consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed

consistency with the GALL Report, and for which the GALL Report does not recommend further

evaluation, the staff performed an audit and review to determine whether the plant-specific

components contained in these GALL Report component groups 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 audited those AMRs with

Notes A through E, which indicated that 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 is different from but consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent

with the AMP identified by the GALL Report. This note indicates that the applicant 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 is different from but consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP takes some

exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify

consistency with the GALL Report. The staff 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.
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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 the BFN 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.

For aging management evaluations that the applicant stated are consistent with the GALL

Report and for which further evaluation is not recommended, the staff conducted its audit to

determine whether the applicant’s reference to the GALL Report in the LRA is acceptable. 

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 are reviewed and are evaluated in the GALL Report; and (3) identified those aging

effects for the steam and power conversion system components that are subject to an AMR.

On the basis of its audit, 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 concluded that the AMR results, which the applicant claimed to be consistent with the

GALL Report, are consistent with the AMRs in the GALL Report. Therefore, the staff concluded

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 CFR54.21(a)(3).

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

Evaluation is Recommended

Summary of Technical Information in the Application. In LRA Section 3.4.2.2, the applicant

provided further evaluation of aging management as recommended by the GALL Report for the

steam and power conversion system. For some line items consistent with the GALL Report in

LRA Tables 3.4.2-1 through 3.4.2-7 (LRA Table 2 in each section), the applicant provided

information concerning how it will manage the following aging effects:

 • cumulative fatigue damage

 • loss of material due to general, pitting, and crevice corrosion

 • loss of material due to general, pitting, and crevice corrosion, MIC, and biofouling

 • general corrosion
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 • loss of material due to general, pitting, crevice corrosion, and MIC

 • quality assurance for aging management of NSR components

Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant

claimed consistency with the GALL Report, and for which the GALL Report recommends further

evaluation, the staff audited and reviewed the applicant’s evaluation to determine whether it had

adequately addressed the issues that the applicant further evaluated. In addition, the staff

reviewed the applicant’s further evaluations against the criteria contained in SRP-LR

Section 3.4.2.2. Details of the staff’s audit are documented in the staff’s audit and review report.

The staff’s evaluation of the aging effects is discussed in the following sections.

3.4.2.2.1 Cumulative Fatigue Damage

In LRA Section 3.3.2.2.3, 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.

3.4.2.2.2 Loss of Material due to General, Pitting, and Crevice Corrosion

The staff reviewed the LRA Section 3.4.2.2.2 against the criteria in SRP-LR Section 3.4.2.2.2.

SRP-LR Section 3.4.2.2.2 states that 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 that loss of material due to pitting

and crevice corrosion should be evaluated further for stainless steel tanks and heat

exchanger/cooler tubes. The Chemistry Control Program relies on monitoring and control of

water chemistry based on the guidelines in BWRVIP-79 (EPRI TR-103515) for water chemistry

in BWRs; 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

Chemistry Control Program. A one-time inspection of selected components and susceptible

locations is an acceptable method to ensure that corrosion is not occurring and that the

components’ intended function will be maintained during the period of extended operation. The

AMP recommended by the GALL Report is XI.M32, “One-Time Inspection.”

In LRA Section 3.4.2.2.2, the applicant credits the Chemistry Control Program to manage loss

of material for the components requiring further evaluation. The applicant addressed the GALL

Report recommendation for further evaluation to verify the effectiveness of the chemistry

control through the One-Time Inspection Program. The staff reviewed the Chemical Instruction

(CI) 13.1, Chemistry Program, Revision 20, which implements chemistry control of primary

water used in the steam and power conversion system. The implementing procedure

recommends that the effectiveness of the Chemistry Control Program should be verified by

means of tools like plant action levels at cut-off points established for contaminant

concentrations recommended by Industry guidance to ensure that corrosion is not occurring,

with corrective actions if these are exceeded. The staff did not find any instances of exceeding

action level II or III in the past five years of operation (i.e., levels exceeding O2 > 100 ppb or
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chlorides > 150 ppb or sulfates > 150 ppb). The staff concluded that the applicant had

satisfactorily complied with GALL recommendations in managing this aging effect and

demonstrated that the effects of aging for loss of material will be adequately managed so that

the intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21(a)(3).

3.4.2.2.3 Loss of Material due to General, Pitting, and Crevice Corrosion, Microbiologically

Influenced Corrosion, and Biofouling

Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not

applicable to BFN.

3.4.2.2.4 General Corrosion

The staff reviewed the LRA Section 3.4.2.2.4 against the criteria in SRP-LR Section 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 bolting exposed to operating

temperature less than 212 °F. The GALL Report recommends further plant-specific evaluation

to ensure that this aging effect is adequately managed.

In LRA Section 3.4.2.2.4, the applicant stated that it will implement the Systems Monitoring

Program to manage general corrosion of external surfaces exposed to operating temperatures

less than 212 °F.

The applicant credits the Systems Monitoring Program to manage general corrosion of external

surfaces exposed to operating temperatures less than 212 °F. This is consistent with the GALL

Report. The staff accepted the Systems Monitoring Program, and its evaluation of this program

is documented in SER Section 3.0.3.3.1.

The staff found that the applicant demonstrated that the effects of aging for loss of material will

be adequately managed so that the intended functions will be maintained consistent with the

CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.4.2.2.5 Loss of Material due to General, Pitting, Crevice, and Microbiologically Influenced

Corrosion

Consistent with the SRP-LR, this further evaluation only applies to PWRs. Therefore, it is not

applicable to BFN.

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
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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 3.4.2.7, the

staff reviewed additional details of the results of the AMRs for MEAP combinations that are not

consistent with the GALL Report, or that are not addressed in the GALL Report. The

components impacted by the AMRs are from the following steam and power conversion

systems:

 • Table 3.4.2.1: Main Steam System (001)

 • Table 3.4.2.2: Condensate and Demineralized Water System (002)

 • Table 3.4.2.3: Feedwater System (003)

 • Table 3.4.2.4: Heater Drains and Vents System (006)

 • Table 3.4.2.5: Turbine Drains and Miscellaneous Piping System (008)

 • Table 3.4.2.6: Condenser Circulating Water System (027)

 • Table 3.4.2.7: Gland Seal Water System (037)

In LRA Tables 3.4.2.1 through 3.4.2.7, the applicant indicated, via Notes F through J, that

combinations of component type, material, environment, and AERM do not correspond to a line

item in the GALL Report, and provided information concerning how the aging effect will be

managed. Specifically, Note F indicated that the material for the AMR line item component is

not evaluated in the GALL Report. Note G indicated that the environment for the AMR line item

component and material is not evaluated in the GALL Report. Note H indicated that the aging

effect for the AMR line item component, material, and environment combination is not evaluated

in the GALL Report. Note I indicated that the aging effect identified in the GALL Report for the

line item component, material, and environment combination is not applicable. Note J indicated

that neither the component nor the material and environment combination for the line item is

evaluated in the GALL Report.

Staff Evaluation. For component type, material, and environment combinations that are not

evaluated in the GALL Report, the staff reviewed the applicant’s evaluation to determine

whether the applicant 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. The staff’s evaluation is discussed in the following sections.

In RAI 3.4-1, dated November 18, 2004, the staff stated that in LRA Tables 3.4.2.1 through

3.4.2.7, carbon and low-alloy steel bolting in an inside air (external) or outside air (external)

environment is not identified with the aging effect of cracking requiring management. In

RAI 3.4-1, dated November 18, 2004, the staff requested the applicant to discuss the specific

material grading used for the bolting in each of the associated systems, and justify the basis for

concluding that crack initiation/growth due to SCC is not a concern for the bolting during the

period of extended operation. In its response, by letter dated December 16, 2004, the applicant

stated that the cracking aging effect is not identified because high-yield bolting materials (yield

strength above 150 ksi) had not been identified and a review of the BFN operating experience

had not identified any instances where mechanical component failure was attributable to SCC
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of high-strength bolting. In addition, the use of molybdenum disulfide thread lubricant, which is

considered to promote SCC, is not allowed by site and engineering procedures. Therefore, loss

of bolting function due to SCC of bolted joints of vendor-supplied mechanical equipment is not

expected and no aging management is required for the period of extended operation. 

Based on the above information provided by the applicant, the staff’s concern described in

RAI 3.4-1 is resolved.

In RAI 3.4-2, dated November 18, 2004, the staff stated that in LRA Tables 3.4.2.2, 3.4.2.3,

3.4.2.6, and 3.4.2.7, copper-alloy components in an inside air (external) environment are not

identified with any aging effects requiring management. Therefore, the staff requested the

applicant to provide a discussion of the air environment involved, and to justify the basis for

concluding that there are no aging effects requiring management under the

material/environment combinations. The staff also requested the applicant to provide a

summary description of the stated industry guidance. In its response, by letter dated

December 16, 2004, the applicant stated that the copper-alloy components exposed to an

inside air (external) environment were evaluated individually to determine where condensation

or periodic wetting could occur. Copper-alloy components containing fluid at a temperature

below the dew point of the external environment is subject to condensation. The identified aging

effects/mechanisms were then determined based on the particular copper alloy present and

whether condensation or periodic wetting could occur. Based on this evaluation, the applicant

concluded that there were no instances where copper-alloy components with greater than 15

percent zinc were subject to an aggressive environment or condensation/periodic wetting.

Therefore, no aging effects that require management during the period of extended operation

were identified for the copper-alloy components in the subject tables. The applicant also

provided a summary description of the industry guidance (i.e., EPRI Technical Report 1003056,

“Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools”), which supports the

above finding for copper alloy.

Based on the above information provided by the applicant, the staff’s concern described in

RAI 3.4-2 is resolved.

In RAI 3.4-3, dated November 18, 2004, the staff stated that in LRA Tables 3.4.2.1, 3.4.2.3,

3.4.2.4, and 3.4.2.5, carbon and low-alloy steel bolting in an inside air (external) environment is

not identified with any aging effects requiring management. Also, the applicant indicated that

carbon and low-alloy steels are not susceptible to external general corrosion when the

temperature is greater than 212 °F. Therefore, the staff requested the applicant to discuss the

specific temperature environment for bolting, instead of piping, and to justify the basis for

concluding that no aging effects need to be identified for the bolting. 

In its response, by letter dated December 16, 2004, the applicant stated that LRA Table 3.4.2.1

for the main steam system, LRA Table 3.4.2.3 for the feedwater system, LRA Table 3.4.2.4 for

the heater drain and vents system, and LRA Table 3.4.2.5 for the turbine drains and

miscellaneous piping system do not identify general corrosion as an aging effect for carbon and

low-alloy steel bolting in an inside air (external) environment as this bolting is maintained dry by

the heat to which it is exposed. The applicant stated that during normal operations the internal

environment for those portions of the above systems within the scope of license renewal is

much higher than 212 °F (>300 °F). Since the bolting connections are constantly in contact with

the high temperature components within these systems, the bolting itself within these systems
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will experience temperatures higher than 212 °F. Carbon and low-alloy steels are not

susceptible to external general corrosion at temperatures above 212 °F.

Based on the above information provided by the applicant, the staff’s concern described in

RAI 3.4-3 is resolved.

In RAI 3.4-4, dated November 18, 2004, the staff stated that in LRA Table 3.4.2.3, carbon and

low-alloy steel components in air/gas (internal) - moist air environments are identified as being

susceptible to loss of material due to crevice, galvanic, general, and pitting corrosion. In lieu of

a periodic inspection program, the One-Time Inspection Program is credited as the only

applicable AMP. In LRA Table 3.4.2.6, carbon and low-alloy steel and cast iron and cast

iron-alloy components in raw water (internal) environments are identified as being susceptible to

loss of material due to biofouling, MIC, crevice, general, and pitting corrosion. The One-Time

Inspection Program is credited as the only applicable AMP. Therefore, the staff requested the

applicant to provide justification that the One-Time Inspection program, instead of the Periodic

Inspection Program, should be used to manage the aging effects for the above components

and material/environment combinations. 

In its response, by letter dated December 16, 2004, the applicant stated that the carbon and

low-alloy steel components in LRA Table 3.4.2.3 for the feedwater system are exposed to an

air/gas--moist air environment in two applications. The first application is the small segment

between the dual isolation valves on system vents and drains, and the second application is

valve packing leakoff lines on Unit 1 feedwater isolation valves. These leakoff lines will be

removed prior to Unit 1 restart, and will not be applicable to the LRA. 

The small segment of piping/fittings between the dual isolation valves on system vents and

drains is exposed to feedwater quality water when the valves are open to support maintenance

activities and has trapped air with varying amount of feedwater, based on how the valves are

closed (i.e., the sequence and time between valve closings). The applicant stated that the

safety consequences for this short segment of piping failing are minimal as this line is

downstream of a closed isolation valve that is manually opened only to support maintenance

activities. Minimal degradation is expected based on the quality of the water potentially in these

components. For completeness, however, and using the One-Time Inspection Program the

applicant will perform inspections to verify that these lines are not degrading. Based on the

expected minimal degradation as stated in the above, the staff considered the applicant's

proposed use of the One-Time Inspection Program to be acceptable. 

In LRA Table 3.4.2.6, for the condenser circulating water system, carbon and low-alloy steel

and cast iron and cast iron-alloy components in raw water (internal) environments are identified

as being susceptible to loss of material due to biofouling, MIC, crevice, general, and pitting

corrosion. The in-scope components in the condenser circulating water system are those

components that provide the anti-siphon vacuum breaker function. The applicant stated that

upon re-reviewing the license renewal scope for the condenser circulating water system, it was

determined that raw water was inadvertently specified as the internal environment for the

anti-siphon vacuum breaker components. The applicable internal environment (air/gas) has

already been evaluated for this system and is included in the LRA. The raw water environment

will be deleted from this system. 
3-273

Based on the above information provided by the applicant, the staff’s concern described in

RAI 3.4-4 is resolved. 

In RAI 3.4-5, dated November 18, 2004, the staff stated that in LRA Tables 3.4.2.1 and 3.4.2.3,

bolting made of carbon and low-alloy steel, nickel alloy, and stainless steel in inside air

(external) environments are identified as being susceptible to loss of bolting function due to

wear. The Bolting Integrity Program is credited as the AMP. The staff noted that LRA

Section B.2.1.16 does not specifically address "loss of bolting function" due to wear as an aging

effect to be managed by the AMP. Therefore, the staff requested the applicant to discuss how

the identified aging effect will be managed by the program. 

In its response, by letter dated December 16, 2004, the applicant stated that bolting

degradation due to wear (fretting) could occur at locations of repeated relative motion of

mechanical component bolted joints. Wear of bolted joint components is generally not a

concern; however, for license renewal purposes, wear is being assumed as a potential

mechanism for ”critical bolting applications.” “Critical bolting applications” constitute reactor

coolant pressure boundary components where closure bolting failure could result in loss of

reactor coolant and jeopardize safe operation of the plant. Loss of material function due to wear

is managed by the Bolting Integrity Program. This program specifies inspection requirements in

accordance with ASME Code Section XI and recommendations of EPRI NP-5769. These

inspection requirements include visual inspections looking for wear as well as for cracks,

corrosion, and physical damage on the surface.

Based on the above information provided by the applicant, the staff’s concern described in

RAI 3.4-5 is resolved.

In RAI 3.4-6, dated November 18, 2004, the staff stated that in LRA Table 3.4.2.2,

aluminum-alloy fittings and piping in a treated-water (internal) environment are identified as

being susceptible to crack initiation/growth due to SCC and loss of material due to crevice,

galvanic, and pitting corrosion. Therefore, the staff requested the applicant to explain (1) why

loss of material due to general corrosion is not identified as a potential AERM, (2) why FAC is

not a concern for the portion of the condensate system that contains single phase fluid with

temperatures less than 200 °F, and (3) how the Chemistry Control Program is used to manage

the aging effects of the components/material/environment combinations identified above. 

In its response, by letter dated December 16, 2004, the applicant stated that as per industry

guidance, aluminum and aluminum-based alloys are not susceptible to loss of material due to

general corrosion. The applicant also stated that FAC is only associated with carbon and

low-alloy steels; therefore, it would not be identified as an aging mechanism for the

aluminum-alloy components. Also, the portions of the condensate system that are within the

license renewal boundary are the supply lines to the emergency core cooling pumps. These

lines contain single phase fluid with temperatures significantly less than 200 °F with only

periodic flow. Consequently, erosion/corrosion is not an aging mechanism that must be

managed for the period of extended operation in the condensate system. 

The applicant stated that the main objective of the Chemistry Control Program is to minimize

loss of material due to general, crevice, and pitting corrosion and crack initiation and growth

caused by SCC. Corrosion and cracking of aluminum alloys in treated water is managed by
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maintaining oxygen, chlorides, and sulfates within the limits of the Chemistry Control Program.

The specific chemistry limits are the same as the limits used to manage aging of 

carbon/low-alloy and stainless steel components in a treated-water environment. The applicant

stated that the use of the Chemistry Control Program is consistent with industry practice as

identified in its past precedence review. The One-Time Inspection Program is used to verify the

Chemistry Control Program's effectiveness. 

Based on the above information provided by the applicant, the staff’s concern described in

RAI 3.4-6 is resolved.

In RAI 3.4-7, dated November 18, 2004, the staff stated that in LRA Table 3.4.2.2, polymer

fittings in an inside air (external) or treated-water (internal) environment are not identified with

any aging effects. Therefore, the staff requested the applicant to provide a discussion of the air

and treated-water environments involved and justify the basis for concluding that there are no

aging effects requiring management under such material/environment combinations. 

In its response, by letter dated December 16, 2004, the applicant stated that polymer fittings in

LRA Table 3.4.2.2 within the condensate system are the insulation couplings between carbon

steel and stainless steel pipe, and between aluminum and stainless steel pipe. Acetal (the

generic name for a family of polymer products that includes DELRIN) provides high strength

and stiffness along with increased dimensional stability and ease of machining. The applicant

stated that a review of available industry information did not identify any aging effects for

DELRIN that would be attributable to the treated-water (internal) environment or the inside air

(external) environment. 

Based on the above information provided by the applicant, the staff’s concern described in

RAI 3.4-7 is resolved.

In RAI 3.4-8, dated November 18, 2004, the staff stated that in LRA Table 3.4.2.2,

aluminum-alloy fittings in a treated-water (internal) environment are identified as being

susceptible to crack initiation/growth due to SCC and loss of material due to crevice and pitting

corrosion. Therefore, the staff requested the applicant to explain why loss of material due to

general and galvanic corrosion is not identified as a potential AERM during the period of

extended operation. The staff also requested the applicant to explain how the Chemistry

Control Program, with the association of One-Time Inspection Program, is used to manage the

identified aging effects. 

In its response, by letter dated December 16, 2004, the applicant stated that as per industry

guidance, aluminum and aluminum-based alloys in a treated-water environment are not

susceptible to loss of material due to general corrosion. In addition, the applicant stated that the

aluminum valves listed in LRA Table 3.4.2.2 as being within the condensate system are not in

contact with more cathodic materials. Therefore, galvanic corrosion is not a concern for

aluminum valves in a treated-water environment for the condensate system. 

The applicant also stated that the main objective of the Chemistry Control Program is to

minimize loss of material due to general, crevice, and pitting corrosion and crack initiation and

growth caused by SCC. Corrosion and cracking of aluminum alloys in treated water is managed

by maintaining oxygen, chlorides, and sulfates within the limits of the Chemistry Control

Program. The specific chemistry limits are the same as the limits used to manage aging of
3-275

carbon/low-alloy and stainless steel components in a treated-water environment. The applicant

stated that the use of the Chemistry Control Program is consistent with industry practice as

identified in its past precedence review. The One-Time Inspection program is used to verify the

Chemistry Control Program's effectiveness as recommended by the GALL Report. 

After evaluating the applicant's identification of aging effects for each of the above components,

the staff evaluated the AMPs to determine whether they are appropriate for managing the

identified aging effects. The staff also determined that the UFSAR Supplement contains an

adequate description of the program. 

Based on the above information provided by the applicant, the staff’s concern described in

RAI 3.4-8 is resolved. 

In RAI 3.4-9, dated November 18, 2004, the staff stated that in LRA Table 3.4.2.3, stainless

steel fittings, piping, valves, and restricting orifices forming the reactor coolant pressure

boundary (RCPB) in an air/gas (internal), moist air environment are identified as being

susceptible to crack initiation/growth due to SCC and loss of material due to crevice and pitting

corrosion. Also, CASS valves in an RCPB in an air/gas (internal), moist air environment are

identified as susceptible to change in material properties/reduction in fracture toughness due to

thermal aging. The One-Time Inspection Program is credited to manage the identified aging

effects. Therefore, the staff requested the applicant to provide justification that the One-Time

Inspection Program alone, in lieu of a more appropriate periodic inspection program, should be

used to manage the identified aging effects for the above-mentioned components and

material/environment combinations. 

In its response, by letter dated December 16, 2004, the applicant stated that the stainless steel

reactor coolant pressure boundary components in Table 3.4.2.3, for the feedwater system, are

exposed to an air/gas environment when air is trapped in the vessel flange leak detection line

when the vessel head is secured. The air/gas environment is considered moist air because the

trapped air is not dried and there is a small potential for leakage. The aging effects are

conservatively identified as a moist air environment. 

The applicant stated that fittings are addressed in rows 19 and 20 of LRA Table 3.4.2.3. The

AMPs identified for cracking are the ASME Section XI Subsections IWB, IWC, and IWD

Inservice Inspection Program and the One-Time Inspection Program. The applicant stated that

these same aging effects and AMPs should be shown for each applicable component (i.e.,

piping in rows 40 and 41, and restricting orifices in line item 46). Because of that, line item 46 in

the table should be replaced by two line items with aging effects/mechanisms and AMPs similar

to those in rows 40 and 41. Valves are addressed in rows 68 and 69. The BWR Stress

Corrosion Cracking Program, instead of the One-Time Inspection Program, is the appropriate

AMP for the cracking aging effect of stainless steel RCPB valves in line item 68, which should

be corrected accordingly. For the cracking aging effect for piping components less than 4

inches NPS, GALL Report Item IV.C1.1-I states, "a plant-specific destructive examination or a

nondestructive examination (NDE) that permits inspection of the inside surfaces of the piping is

to be conducted to ensure that cracking has not occurred and the component intended function

will be maintained during the extended period of operation." The applicant has included this

small bore piping inspection in the One-Time Inspection Program. 
3-276

For loss of material due to crevice and pitting corrosion, the One-Time Inspection Program is

credited as an AMP because corrosion is not expected to occur for the stainless steel

components in an air/gas (internal) with moist air environment. The piping is not subject to

condensation and is dry except for the abnormal case when reactor vessel flange leakage

occurs. The applicant stated that any water that is introduced to this line is reactor grade

treated water and, as such, has minimal potential for corrosion. 

The applicant stated that thermal aging of CASS valves is addressed in line item 67, where an

incorrect AMP was identified. The correct AMP is the ASME Section XI Subsection IWB, IWC,

and IWD Inservice Inspection Program. Therefore, line item 67 should be corrected

accordingly. 

Based on the above updated information, the staff considered that the applicant had adequately

addressed its concern regarding the use of the One-Time Inspection Program as the sole AMP

for the identified aging effects. Therefore, the staff’s concern described in RAI 3.4-9 is resolved.

3.4.2.3.1 Main Steam System – Summary of Aging Management Evaluation – Table 3.4.2.1

The staff reviewed LRA Table 3.4.2.1, which summarizes the results of AMR evaluations for the

main steam system component groups.

In LRA Table 3.4.2.1, the applicant identified no aging effects for stainless steel and carbon and

low-alloy steel components exposed to air, for piping and tubing component types. Air is not

identified in the GALL Report as an environment for these components and materials. 

On the basis of current industry research and operating experience, dry air on metal will not

result in aging that will be of concern during the period of extended operation. The external

environments being referred to are typical of ambient air (e.g., under a shelter, indoor, or

air-conditioned enclosure or room). Therefore, the staff concluded that there are no aging

effects requiring management for stainless steel in an air environment.

In LRA Table 3.4.2.1, the applicant identified no aging effects for carbon and low-alloy steel

condenser components. No aging effects were identified by the AMR for the main condenser

components made of carbon steel, or stainless steel in a treated-water environment or inside

air. These materials have successfully performed as main condenser materials at other plants.

Further, the applicant concluded that aging management of the main condenser is not required

based on analysis of materials, environments, and aging effects. Condenser integrity required

to perform the post-accident intended function (holdup and plateout of main steam isolation

valve (MSIV) leakage) is continuously confirmed by normal plant operation. The main

condenser must perform a significant pressure boundary function (maintain vacuum) to allow

continued plant operation. For these reasons, the applicant has not identified any applicable

aging effects for the main condenser. The staff concurred with the applicant’s conclusion

because the main condenser integrity is continuously confirmed during normal plant operation

and, thus, the condenser post-accident function will be ensured.
3-277

3.4.2.3.2 Condensate and Demineralized Water System – Summary of Aging Management

Evaluation – Table 3.4.2.2

The staff reviewed LRA Table 3.4.2.2, which summarizes the results of AMR evaluations for the

condensate and demineralized water system component groups.

In LRA Table 3.4.2.2, the applicant identified no aging effects for stainless, carbon, and

low-alloy steel components exposed to air for piping and tubing component types. Air is not

identified in the GALL Report as an environment for these components and materials. 

On the basis of current industry research and operating experience, dry air on metal will not

result in aging that will be of concern during the period of extended operation. Therefore, the

staff concluded that there are no AERMS for stainless, carbon, and low-alloy steel in an air

environment.

In LRA Table 3.4.2.2, the applicant identified an aging effect of galvanic corrosion for carbon

and low-alloy steel components exposed to treated water internally. The GALL Report does not

indicate the aging effect, but recommends further evaluation for these components.

In managing the galvanic aging effect, the applicant stated that galvanic corrosion can only

progress if the dissimilar metals are in contact in the presence of an electrolyte. Control of

galvanic corrosion in treated water systems is possible by maintaining adequate chemistry

controls. As treated water is a poor electrolyte, the dissimilar metals in this environment would

experience little or no galvanic corrosion. This is evidenced by the lack of industry operating

experience of galvanic corrosion failures in treated water systems. A review of BFN PERs and

work orders did not identify instances where galvanic corrosion was a failure mechanism.

The staff found that the applicant demonstrated that the effects of aging for loss of material due

to galvanic corrosion 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). 

In LRA Table 3.4.2.2, aluminum-alloy fittings in a treated-water environment are identified as

being susceptible to crack initiation/growth due to SCC and loss of material due to crevice,

galvanic, and pitting corrosion. Since this material was not listed in the GALL Report, the staff

needed some additional explanation to justify the Chemistry Control Program and One-Time

Inspection Program to manage the effect.

The applicant stated that the aging effects identified for aluminum alloys are consistent with

EPRI Report 1003056, "Non-Class 1 Mechanical Implementation Guideline and Mechanical

Tools, Revision 3." Aluminum alloys were evaluated using the guidelines given in the report.

BFN utilizes the Chemistry Control Program and One-Time Inspection Program to manage the

effect, which is also the industry standard; based on past precedents review of similar

applications for managing the aging effects of aluminum alloys in treated-water environments,

the staff found the response acceptable. 

In LRA Table 3.4.2.2, for carbon and low-alloy steel piping in air/gas environment (internal) the

applicant mentions only one-time inspection for aging management due to general corrosion.
3-278

GALL Table VIII.E.1, Condensate System, does not address the air/gas environment identified

in the LRA. 

The applicant clarified that the row 35 environment in LRA Table 3.4.2.2 referred to the area

between the two isolation valves on condensate system vents and drains. This small segment

of piping is exposed to condensate flow when the valves are open and has air trapped with

varying amount of condensate based on how the valves are closed, that is, the sequence and

time between valve closings. The safety consequences for this short segment of piping failing

are non-existent, because this line is downstream of a closed isolation valve. However, for

completeness and to verify that these lines are not degrading, the applicant will perform some

inspections using the One-Time Inspection Program, even though the GALL Report does not

address the air/gas environment.

3.4.2.3.3 Feedwater System – Summary of 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

feedwater system component groups.

In LRA Table 3.4.2.3, stainless steel fittings (item 11) in a treated water environment are

identified as being susceptible to crack initiation and SCC, which is not identified in GALL

Report (VIIID2.1.1-b) for this item.

The applicant stated in Mechanical Evaluation Report - Feedwater System 003 that the shape

of components in this system made from stainless steel material may present a high stress

environment, and the treated water may contain contaminants such as chlorides and sulfides.

This combination, with temperatures above 140 °F, may promote SCC. This conclusion is

supported by evidence from industry experience. The staff concurred with the applicant that this

aging effect needed appropriate evaluation and managing. The staff agreed that the proposed

management through the Chemistry Control Program and One-Time Inspection Program will be

adequate to manage the aging.

3.4.3 Conclusion

The staff concluded that the applicant had 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 function(s) will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21(a)(3).

The staff also reviewed the applicable UFSAR supplement program summaries and concluded

that they adequately describe the AMPs credited for managing aging of the steam and power

conversion system, as required by 10 CFR 54.21(d).
3-279

3.5 Aging Management of Containments, Structures, and Component Supports

This section of the SER documents the staff’s review of the applicant’s AMR results for the

containments, structures, and component supports components and component groups

associated with the following systems:

 • primary containment structures

 • reactor buildings

 • equipment access lock

 • diesel generator buildings

 • standby gas treatment building

 • off-gas treatment building

 • vacuum pipe building

 • residual heat removal service water tunnels

 • electrical cable tunnel from intake pumping station to the powerhouse

 • underground concrete encased structures

 • earth berm

 • intake pumping station

 • gate structure No. 3

 • intake channel

 • north bank of cool water channel east of gate structure No. 2

 • south dike of cool water channel between gate structure Nos. 2 and 3

 • condensate water storage tanks’ foundations and trenches

 • containment atmosphere dilution storage tanks’ foundations

 • reinforced concrete chimney

 • turbine buildings

 • diesel high-pressure fire pump house

 • vent vaults

 • transformer yard

 • 161 kV (kiloVolt) switchyard

 • 500 kV switchyard

 • structures and component supports commodities group

3.5.1 Summary of Technical Information in the Application

In LRA Section 3.5, the applicant provided AMR results for components. In LRA Table 3.5.1,

“Summary of Aging Management Evaluations for Structures and Component Supports

Evaluated in Chapter II and III of NUREG-1801,” the applicant provided a summary comparison

of its AMRs with the AMRs evaluated in the GALL Report for the containments, structures, and

component supports components and component groups.

The applicant’s AMRs incorporated applicable operating experience in the determination of the

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 the 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.
3-280

3.5.2 Staff Evaluation

The staff reviewed LRA Section 3.5 to determine whether the applicant had provided sufficient

information to demonstrate that the effects of aging for the containments, structures, and

component supports components that are within the scope of license renewal and subject to an

AMR will be adequately managed so that the intended functions will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).

During the weeks of June 21 and July 26, 2004, the staff performed an onsite audit, of AMRs to

confirm the applicant’s claim that certain identified AMRs are consistent with the GALL matters

described in the GALL Report. The staff verified that the material presented in the LRA is

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. Detail of the staff’s audit

evaluation are documented in the BFN audit and review report, and are summarized in SER

Section 3.5.2.1.

In the onsite audit, the staff also 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 are consistent with the acceptance criteria in SRP-LR Section 3.5.2.2, dated

July 2001. The staff’s audit evaluations are documented in the BFN audit and review report,

and are summarized in SER Section 3.5.2.2.

In the onsite audit, the staff also conducted a technical review of the remaining AMRs that are

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 evaluating

whether the aging effects listed are appropriate for the combination of materials and

environments specified. The staff’s audit evaluations are documented in the BFN audit and

review report, and are summarized in 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 UFSAR 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 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 in

the GALL Report

Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

Penetration

sleeves, penetration

bellows, and

dissimilar metal

welds

Cumulative fatigue

damage

TLAA evaluated in

accordance with

10 CFR 54.21(c)

TLAA This TLAA is

evaluated in

Section 4.6, Primary

Containment

Fatigue
Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

3-281

Penetration

sleeves, bellows,

and dissimilar metal

welds

(Item Number

3.5.1.2)

Cracking due to

cyclic loading, crack

initiation and growth

due to SCC

Containment

Inservice Inspection

(ISI) Program;

Containment Leak

Rate Test Program

Containment ISI

Program;

Containment Leak

Rate Test Program

Consistent with

GALL, with

exceptions, which

recommends no

further evaluation

(See Section

3.5.2.1)

Penetration

sleeves, penetration

bellows, and

dissimilar metal

welds

(Item Number

3.5.1.3)

Loss of material

due to corrosion

Containment ISI

Program;

Containment Leak

Rate Test Program

Containment ISI

Program;

Containment Leak

Rate Test Program

Consistent with

GALL, which

recommends no

further evaluation

(See Section

3.5.2.1)

Personnel airlock

and equipment

hatch

(Item Number

3.5.1.4)

Loss of material

due to corrosion

Containment ISI

Program;

Containment Leak

Rate Test Program

Containment ISI

Program;

Containment Leak

Rate Test Program

Consistent with

GALL, which

recommends no

further evaluation

(See Section

3.5.2.1)

Personnel airlock

and equipment

hatch

(Item Number

3.5.1.5)

Loss of leak

tightness in closed

position due to

mechanical wear of

locks, hinges, and

closure

mechanisms

Containment Leak

Rate Test Program;

Plant Technical

Specifications

Program

Containment Leak

Rate Test Program;

Plant Technical

Specifications

Program

Consistent with

GALL, which

recommends no

further evaluation

(See Section

3.5.2.1)

Seals, gaskets, and

moisture barriers

(Item Number

3.5.1.6)

Loss of sealant and

leakage through

containment due to

deterioration of joint

seals gaskets, and

moisture barriers

Containment ISI

Program;

Containment Leak

Rate Test Program

Containment ISI

Program;

Containment Leak

Rate Test Program

Consistent with

GALL, which

recommends no

further evaluation

(See Section

3.5.2.1)

Concrete elements:

foundation, dome,

and wall

(Item Number

3.5.1.7)

Aging of accessible

and inaccessible

concrete areas due

to leaching of

calcium hydroxide,

aggressive

chemical attack,

and corrosion of

embedded steel

Containment ISI

Program

N/A Not applicable

BFN has a Mark I

steel containment 

Concrete elements:

foundation

(Item Number

3.5.1.8)

Cracks, distortion,

and increases in

components stress

level due to

settlement

Structures

Monitoring Program

N/A Not applicable

BFN has a Mark I

steel containment 
Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

3-282

Concrete elements:

foundation

(Item Number

3.5.1.9)

Reduction in

foundation strength

due to erosion of

porous concrete

subfoundation

Structures

Monitoring Program

N/A Not applicable

BFN has a Mark I

steel containment 

Concrete elements:

foundation, dome,

and wall

(Item Number

3.5.1.10)

Reduction of

strength and

modulus due to

elevated

temperature)

Plant-specific N/A Not applicable

BFN has a Mark I

steel containment 

Prestressed

containment:

tendons and

anchorage

components

(Item Number

3.5.1.11)

Loss of prestress

due to relaxation,

shrinkage, creep,

and elevated

temperature

TLAA evaluated in

accordance with

10 CFR 54.21(c)

TLAA Not applicable

BFN has a Mark I

steel containment

and not prestressed

concrete with

tendons

Steel elements:

liner plate,

containment shell

(Item Number

3.5.1.12)

Loss of material

due to corrosion in

accessible and

inaccessible areas

Containment ISI

Program;

Containment Leak

Rate Test Program

Containment ISI

Program;

Containment Leak

Rate Test Program

Consistent with

GALL which

recommends further

evaluation (See

Section 3.5.2.1)

Steel elements:

vent header, drywell

head, torus,

downcomers, and

pool sheel

(Item Number

3.5.1.13)

Cumulative fatigue

damage (CLB

fatigue analysis

exists)

TLAA evaluated in

accordance with

10 CFR 54.21(c)

TLAA This TLAA is

evaluated in

Section 4.6, Primary

Containment

Fatigue

Steel elements:

protected by coating

(Item Number

3.5.1.14)

Loss of material

due to corrosion in

accessible areas

only

Protective Coating

Monitoring and

Maintenance

Program

N/A Not applicable

BFN does not credit

coatings to prevent

general corrosion 

Prestressed

containment:

tendons and

anchorage

components

(Item Number

3.5.1.15)

Loss of material

due to corrosion of

prestressing

tendons and

anchorage

components

Containment ISI

Program

N/A Not applicable

BFN has a Mark I

steel containment

and not prestressed

concrete with

tendons

Concrete elements:

foundation, dome,

and wall

(Item Number

3.5.1.16)

Scaling, cracking,

and spalling due to

freeze-thaw;

expansion and

cracking due to

reaction with

aggregate

Containment ISI

Program

N/A Not applicable

BFN has a Mark I

steel containment
Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

3-283

Steel elements:

vent line bellows,

vent headers, and

downcomers

(Item Number

3.5.1.17)

Cracking due to

cyclic loads; crack

initiation and growth

due to SCC

Containment ISI

Program;

Containment Leak

Rate Test Program

Containment ISI

Program;

Containment Leak

Rate Test Program

Consistent with

GALL, which

recommends further

evaluation (See

3.5.2.1)

Steel elements:

suppression

chamber liner

(Item Number

3.5.1.18)

Crack initiation and

growth due to SCC

Containment ISI

Program;

Containment Leak

Rate Test Program

Containment ISI

Program;

Containment Leak

Rate Test Program

Consistent with

GALL, with

exceptions, which

recommends no

further evaluation

(See Section

3.5.2.1)

Steel elements:

drywell head and

downcomer pipes

(Item Number

3.5.1.19)

Fretting and lock up

due to wear

Containment ISI

Program

Containment ISI

Program

Consistent with

GALL, with

exceptions, which

recommends no

further evaluation

(See Section

3.5.2.1)

All Groups except

Group 6: accessible

interior/exterior

concrete and steel

components

(Item Number

3.5.1.20)

All types of aging

effects

Structures

Monitoring Program

Structures

Monitoring Program

Consistent with

GALL, which

recommends further

evaluation (See

Section 3.5.2.1)

Groups 1-3, 5, 7-9:

inaccessible

concrete

components, such

as exterior walls

below grade and

foundation

(Item Number

3.5.1.21)

Aging of

inaccessible

concrete areas due

to aggressive

chemical attack,

and corrosion of

embedded steel

Plant-specific Consistent with

GALL, which

recommends further

evaluation if an

aggressive

below-grade

environment exists

(See Section

3.5.2.2.1)

Group 6: all

accessible/

inaccessible

concrete, steel, and

earthen

components

(Item Number

3.5.1.22)

All types of aging

effects, including

loss of material due

to abrasion,

cavitation, and

corrosion

Inspection of

Water-Control

Structures;

FERC/US Army

Corps of Engineers

Dam Inspection and

Maintenance

Program

Inspection of

Water-Control

Structures;

FERC/US Army

Corps of Engineers

Dam Inspection and

Maintenance

Program

Consistent with

GALL which

recommends further

evaluation (See

Section 3.5.2.2.8)

Group 5: liners

(Item Number

3.5.1.23)

Crack initiation and

growth due to SCC;

loss of material due

to crevice corrosion

Chemistry Control

Program;

Monitoring of Spent

Fuel Pool Water

Level Program

Chemistry Control

Program;

Monitoring of Spent

Fuel Pool Water

Level Program

Consistent with

GALL, with

exceptions, which

recommends no

further evaluation

(See Section

3.5.2.1)
Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

3-284

Groups 1-3, 5, 6: all

masonry block walls

(Item Number

3.5.1.24)

Cracking due to

restraint, shrinkage,

creep, and

aggressive

environment

Masonry Wall

Program

Masonry Wall

Program

Consistent with

GALL, which

recommends no

further evaluation

(See Section

3.5.2.1)

Groups 1-3, 5, 7-9:

foundation

(Item Number

3.5.1.25)

Cracks, distortion,

and increases in

component stress

level due to

settlement

Structures

Monitoring Program

Structures

Monitoring Program

Consistent with

GALL, which

recommends further

evaluation (See

Section 3.5.2.2.2)

Groups 1-3, 5-9:

foundation

(Item Number

3.5.1.26)

Reduction in

foundation strength

due to erosion of

porous concrete

subfoundation

Structures

Monitoring Program

N/A Not applicable

BFN does not use

porous concrete

subfoundations 

Groups 1-5:

concrete

(Item Number

3.5.1.27)

Reduction of

strength and

modulus due to

elevated

temperature

Plant-specific Structures

Monitoring Program

Consistent with

GALL, which

recommends further

evaluation (See

Section 3.5.2.2.3)

Groups 4, 8: liners

(Item Number

3.5.1.28)

Crack initiation and

growth due to SCC;

loss of material due

to crevice corrosion

Plant-specific N/A Not applicable

BFN does not have

any Group 7

structues

BFN does not have

in-scope stainless

steel liners in an

exposed-to-fluid

environment for any

Group 8 structure

All groups: support

members, anchor

bolts, concrete

surrounding anchor

bolts, welds, grout

pad, bolted

connections, etc.

(Item Number

3.5.1.29)

Aging of component

supports

Structures

Monitoring Program

Structures

Monitoring Program

Consistent with

GALL, which

recommends no

further evaluation if

within the scope of

the applicant’s

Structures

Monitoring Program

(See

Section 3.5.2.1)

Groups B1.1, B1.2,

and B1.3: support

members, anchor

bolts, and welds

(Item Number

3.5.1.30)

Cumulative fatigue

damage (CLB

fatigue analysis

exists)

TLAA evaluated in

accordance with

10 CFR 54.21(c)

TLAA This TLAA is

evaluated in

Section 4.6, Primary

Containment

Fatigue
Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

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Groups B1.1, B1.2,

and B1.3: support

members, anchor

bolts, welds, spring

hangers, guides,

stops, and vibration

isolators

(Item Number

3.5.1.32)

Loss of material

due to

environmental

corrosion; loss of

mechanical function

due to corrosion,

distortion, dirt,

overload, etc.

ISI Program ISI Program Consistent with

GALL, which

recommends no

further evaluation

(See Section

3.5.2.1)

Group B1.1:

high-strength

low-alloy bolts

(Item Number

3.5.1.33)

Crack initiation and

growth due to SCC

Bolting integrity

Program

Exception to GALL

(See Section

3.5.2.3.26)

The staff’s review of the BFN component groups 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 component 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 component 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 component

supports that the applicant indicated are not consistent with, or not addressed in, the GALL

Report. The staff’s review of AMPs that are credited to manage or monitor aging effects of the

containments, structures, and component supports components is documented in SER

Section 3.0.3.

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

structures, and component supports components:

 • 10 CFR 50 Appendix J Program

 • ASME Section XI Subsection IWE Program

 • Structures Monitoring Program

 • Chemistry Control Program

 • Fire Protection Program

 • Masonry Wall Program

 • Inspection of Water-Control Structures Program

 • ASME Section XI Subsection IWF Program

 • One-Time Inspection Program
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Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant

has claimed consistency with the GALL Report, and for which the GALL Report 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 audited those AMRs with

Notes A through E, which indicated that 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 is different from but consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent

with the AMP identified by the GALL Report. This note indicates that the applicant had not been

able 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 is different from but consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP takes some

exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify

consistency with the GALL Report. The staff 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 is consistent with the AMP

identified in the GALL Report and whether the AMR is 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 is valid for the site-specific conditions.
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The staff conducted an audit and review of the information provided in the LRA, as documented

in the BFN 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.

For aging management evaluations that the applicant stated are consistent with the GALL

Report and for which further evaluation is not recommended, the staff conducted its review and

audit to determine if the applicant’s reference to the GALL Report in the LRA is acceptable. 

The staff determined 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

SCs that are subject to an AMR. The staff also determined that the LRA line item is consistent

with the GALL Report Volume 2 system tables line item for component type and MEAP.

To confirm consistency with the GALL Report, during the onsite audit in the weeks of June 21

and July 26, 2004, the staff requested the applicant to clarify the following LRA line items:

In LRA Table 3.5.2.1, the applicant credits the 10 CFR Part 50, Appendix J Program for some

structures and component supports in the primary containment. The GALL Report is also based

on an expectation that plant technical specifications will be credited. The staff requested the

applicant to identify these items and explain the BFN plant technical specifications that govern

the leakage testing of these items after each opening.

By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that Table 3.5.2.1, rows 4 and 6 apply to the drywell personnel access airlock. Table 3.5.2.1,

rows 8 and 10, apply to the torus and drywell access hatches and equipment hatches. These

containment pressure boundary components will continue to be inspected consistent with the

CLB Technical Specifications for Appendix J requirements. BFN Technical Specification

Requirements, Section 5.5.12, "Primary Containment Leakage Rate Testing Program,"

provides the requirement to establish a program to implement the leakage rate testing of the

containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, and provides the

leakage rate acceptance criteria of the program. With these clarifications, the staff concluded

that these items are consistent with the GALL Report.

In reference to LRA Table 3.5.2.1, the staff further requested the applicant to identify the

caulking and sealants included under this item and clarify why Appendix J is not a credited

AMP. By letter dated October 8, 2004, the applicant submitted its formal response to the staff,

stating that Table 3.5.2.1 applies to the moisture barrier seal between the drywell steel shell

and the concrete floor in the bottom of the drywell, elevation 549.92 feet. Appendix J testing is

not required, since the drywell floor moisture barrier seal between drywell steel shell and the

549.92-foot elevation concrete does not have a pressure boundary function. The staff

concurred with the applicant’s explanation and found this acceptable.

In LRA Table 3.5.2.2, the staff observed that the AMP referenced for spent fuel pool liners is

not consistent with GALL Report Item III.A5.2-b. The Chemistry Control Program is referenced.

However, the GALL Report also includes "monitoring of the spent fuel pool level." The staff

requested that the applicant provide the technical basis for this omission. By letter dated
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October 8, 2004, the applicant submitted its formal response to the staff, stating that the AMP

section for LRA Table 3.5.2.2 should have identified that the spent fuel pool level is monitored

by plant operations. Browns Ferry will submit a change to correct this omission. With this

correction, the staff concluded that the applicant’s AMR is consistent with the GALL Report.

In reference to LRA Table 3.5.2.2, the staff also requested the applicant to describe the AMR

for Boral and to clarify whether stainless steel components are used to support the Boral. If the

AMR supports the conclusion that Boral does not require aging management, but the stainless

steel supports do, then the Chemistry Control Program would be an acceptable AMP for this

item. If not, the applicant was requested to provide the technical basis for crediting the

Chemistry Control Program as the appropriate AMP for Boral.

By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that the Boral core is made up of a central segment of a dispersion of boron carbide in

aluminum. This central segment is clad on both sides with aluminum to form a plate. The Boral

plates are sandwiched between two stainless steel plates which are closure-welded form the

container. Vent holes have been added to prevent the buildup of hydrogen gas between the

stainless steel containers. If the stainless steel containers remain intact, the Boral core will be

unaffected and will retain its neutron-absorbing capacity. The Chemistry Control Program will

manage aging of the stainless steel containers. With these clarifications, the staff concluded

that this item is consistent with the GALL Report. 

In reference to LRA Tables 3.5.2.12, 3.5.2.13, and 3.5.2.26, the staff requested that the

applicant identify each of the components included and explain the reference to Note C

(Component is different from, but consistent with, GALL Report item for material, environment,

and aging effect. The AMP is consistent with the GALL Report). 

In its response, by letter dated October 8, 2004, the applicant stated that Table 3.5.2.1.12, rows

41 and 42, apply to security barrier steel framing at the intake pumping station. Note C was

used because the security barrier steel framing was evaluated with structural steel beams

columns, and trusses (steel components) commodity group. Table 3.5.2.13, rows 4, 5, 6, 7, and

8, apply to concrete that is sandwiched between the steel sheet pile cells of Gate Structure

Number 3. Note C was used because the concrete sandwiched between the steel sheet pile

cells was evaluated with concrete elements that were not sandwiched between steel sheet

piles. Table 3.5.2.26, rows 19 and 20, apply to cable trays and supports in containment

atmosphere and inside air environments. Note C was used because cable trays were evaluated

with the cable tray supports. With these clarifications, the staff concluded that these items are

consistent with the GALL Report.

In reference to LRA Table 3.5.2.12, the staff requested the applicant to explain the extent to

which the referenced submerged structures are inspected for the effects of freeze-thaw under

the Inspection of Water-Control Structures Program. By letter dated October 8, 2004, the

applicant submitted its formal response to the staff, stating that the referenced submerged

structure will be inspected for the effects of freeze-thaw at the waterline where icing conditions

could occur. The staff concluded that the applicant’s approach to the management of this aging

effect is consistent with the GALL Report. 

On the basis of its audit, 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
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acceptable, that the line items are consistent with the GALL Report, 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 concluded 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 concluded 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 CFR54.21(a)(3).

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

Evaluation is Recommended

Summary of Technical Information in the Application. In LRA Section 3.5.2.2, the applicant

provided further evaluation of aging management as recommended by the GALL Report for the

containments, structures, and component supports. The applicant provided information

concerning how it will manage the following aging effects:

 • aging of inaccessible concrete areas

 • cracking, distortion, and increase in component stress level due to settlement; reduction

of foundation strength due to erosion of porous concrete subfoundations, if not covered

by Structures Monitoring Program

 • 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

 • cracking due to cyclic loading and stress corrosion cracking

 • aging of structures not covered by Structures Monitoring Program

 • aging management of inaccessible areas

 • aging of supports not covered by Structures Monitoring Program

 • cumulative fatigue damage due to cyclic loading

 • quality assurance for aging management of non-safety-related components

Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant

claimed consistency with the GALL Report, and for which the GALL Report recommends further

evaluation, the staff audited and reviewed the applicant’s evaluation to determine whether it had

adequately addressed the issues that were further evaluated. In addition, the staff reviewed the

applicant’s further evaluations against the criteria contained in SRP-LR Section 3.5.2.2. Details

of the staff’s audit are documented in the staff’s BFN audit and review report. The staff’s

evaluation of the aging effects is discussed in the following sections.
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3.5.2.2.1 Aging of Inaccessible Concrete Areas

The discussion in SRP-LR Section 3.5.2.2.1.1 is not applicable to BFN since BFN is a BWR

with a Mark I steel containment.

3.5.2.2.2 Cracking, Distortion, and Increase in Component Stress Level Due to Settlement;

Reduction of Foundation Strength due to Erosion of Porous Concrete Subfoundations, if Not

Covered by Structures Monitoring Program

The discussion in SRP-LR Section 3.5.2.2.1.2 is not applicable to BFN since BFN is a BWR

with a Mark I steel containment.

3.5.2.2.3 Reduction of Strength and Modulus of Concrete Structures due to Elevated

Temperature

The discussion in SRP-LR Section 3.5.2.2.1.3 is not applicable to BFN since BFN is a BWR

with a Mark steel containment.

3.5.2.2.4 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 steel containment elements.

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

and BWR containments. The GALL Report recommends further evaluation of plant-specific

programs to manage this aging effect for inaccessible areas if the following specific criteria

defined in the GALL Report cannot be satisfied: (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 accessible concrete is monitored to ensure

that it is free of penetrating cracks that provide a path for water seepage to the surface of the

containment shell or liner; (3) the accessible portion of the moisture barrier, at the junction

where the shell or liner becomes embedded, is subject to aging management activities in

accordance with IWE requirements; (4) borated water spills and water ponding on the

containment concrete floor are not common and when detected are cleaned up in a timely

manner.

In the LRA, the applicant stated that loss of material due to corrosion in inaccessible areas of

steel containment elements is not significant. The drywell steel containment vessel is

inaccessible (except for the drywell head) for visual examination from the outside surface.

There has been evidence of water leaking from the sand bed drains on both Units 2 and 3.

Since there is a horizontal weld connecting the first and second course of drywell liner plates

approximately eight inches above the drywell concrete floor, ultrasonic testing (UT) thickness

measurements from the drywell floor up to this weld, around the drywell circumference, would

conservatively bound the sand pocket area. UT thickness measurements of this area were

obtained during the U2C10 and U3C8 refueling outages for Units 2 and 3 respectively and in
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1999 and 2002 for Unit 1. The data indicated that the condition of the drywell steel liner plate in

this area is good and that this area did not require augmented examination.

The applicant further stated in the LRA that concrete structures and concrete components are

designed in accordance with ACI 318-63 and ACI 318-71 and constructed using materials

conforming to ACI and ASTM standards. The Structures Monitoring Program monitors the

concrete to ensure that it is free of penetrating cracks that provide a path for water seepage to

the surface of the containment shell. Research of plant history did not reveal any instances of

borated water spills or water ponding on the containment concrete floor. A general visual

inspection of the moisture barrier at the junction of the steel drywell shell and the concrete floor

is performed once each inspection interval in accordance with the ASME Code Section XI,

Subsection IWE Program.

The applicant concluded in the LRA that, since all of the GALL Report further evaluation

conditions are satisfied, a plant-specific AMP for corrosion in inaccessible areas (embedded

containment steel shell and drywell support skirt) is not required.

During the audit, the staff requested the applicant to provide details of the UT measurements in

the sand pocket region for all three units, including comparisons with the original wall

thicknesses and trending results. The staff also requested the applicant to discuss future

planned inspections of steel containment corrosion in the sand pocket region for all three units

and the basis for not inspecting other regions of the drywell for all three units in light of the

evidence of water leaking from the sand bed drains. It is noted that there is expansion foam in

the air gap between the drywell shell and the surrounding concrete that can become wet as a

result of the leaking water. Thus, other areas of the drywell shell could be susceptible to

corrosion.

By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that in response to GL 87-05, which addressed the potential for corrosion of BWR Mark I steel

drywells in the “sand pocket region,” it had provided the staff with the results of the ultrasonic

testing for corrosion degradation of drywell liner plate on Aug. 30, 1988. The results of the

ultrasonic testing show that each unit's drywell had been ultrasonically tested near the sand

cushion area during 1987. The tests showed that the nominal thickness was maintained on

each drywell. Below, are the results of each unit’s drywell ultrasonic testing. (Note: the following

results are quoted from the applicant’s letter to the staff dated August 30, 1988.)

 • Unit 1- No reading below the nominal thickness of one inch was measured, indicating

that the integrity of the drywell liner plate is maintained. Periodic leakage from the sand

cushion area has been observed. Corrosive species in the drainage are bases to

suspect a higher rate of corrosion on Unit 1 drywell liner plate than on Unit 2 and 3.

However, objective evidence of serious corrosion damage was not noted. 

 • Unit 2 - No reading below the nominal thickness of one inch was measured, indicating

that no damage to the integrity of the drywell liner plate has occurred.

 • Unit 3 - No reading below the nominal thickness of one inch was measured, indicating

that no damage to the integrity of the drywell liner plate has occurred. 

The applicant further stated that Procedure SPP-9.1, “ASME Section XI,” is the applicant’s

standard to establish administrative controls and provide requirements, standard methods,
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guidance, and interfaces for preparation of ASME Code Section XI and augmented inservice

inspection and testing programs at each nuclear site. In addition, this procedure allows for the

control and dissemination of the site programs as stand alone documents, as it is required to

meet the individual site-specific requirements resulting from the physical plant differences. 

BFN Technical Instruction 0-TI-376, “ASME Section XI Containment Inservice Inspection

Program Units 1, 2, and 3,” is an administrative technical instruction employed to implement the

inservice inspection provisions of SPP-9.1 relative to Class MC components at BFN.

Appendix 9.7 to BFN Technical Instruction 0-TI-376 documents the Units 2 and 3 evaluation of

Class MC components to determine augmented examination requirements in accordance with

Table IWE-2500-1, Category E-C, Containment Surfaces Requiring Augmented Examination.

Included as one of the areas to evaluate for augmented inspections was the “Drywell SCV at

the sand bed region.” The evaluation considered the potential degradation mechanisms of each

area; the adequacy of existing programs and maintenance practices with respect to the

monitoring, prevention, and correction of degradation; and industry experience applicable to the

area; and provided a conclusion with respect to augmented examination requirements.

The applicant also stated that the drywell SCV at the sand bed region evaluation summarized

the response to GL 87-05 and the need to obtain more data to conclude whether augmented

inspections were warranted. UT thickness measurements of this area, in accordance with

IWE-2500 (c)(2), (c)(3), and (c)(4), were obtained during the U3C8 and U2C10 refueling

outages. The data indicate that the condition of the drywell steel liner plate in this area is good,

and that this area should not be categorized for augmented examination for Units 2 and 3.

As part of the re-start activities for Unit 1, the applicant stated that a similar evaluation will be

performed to determine if augmented inspections would be required. This evaluation and

conclusion will be included in BFN Technical Instruction 0-TI-376 prior to Unit 1 re-start.

In its response, the applicant also noted that aging management of drywell corrosion will be

addressed in its response to RAI 3.5-4. This issue is dispositioned in the staff evaluation of the

applicant’s response to RAI 3.5-4. 

3.5.2.2.5 Loss of Prestress due to Relaxation, Shrinkage, Creep, and Elevated Temperature

The discussion in SRP-LR Section 3.5.2.2.1.5 is not applicable to BFN since BFN is a BWR

with a Mark I steel containment.

3.5.2.2.6 Cumulative Fatigue Damage

In LRA Section 3.5.2.2.1.6, the applicant stated that fatigue analysis of BWR Mark I and Mark II

containment steel elements, penetration sleeves, and penetration bellows are TLAAs as

defined in 10 CFR 54.3. The TLAA evaluation of cumulative fatigue damage is addressed in

LRA Section 4.6. The staff evaluated TLAAs in SER Section 4.

3.5.2.2.7 Cracking due to Cyclic Loading and Stress Corrosion Cracking

The staff reviewed LRA Section 3.5.2.2.1.7 against the criteria in SRP-LR Section 3.5.2.2.1.7. 

In LRA Section 3.5.2.2.1.7, the applicant addressed aging mechanisms that can lead to

cracking of penetration sleeves and penetration bellows such as cyclic loads and SCC. 
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SRP-LR Section 3.5.2.2.1.7 states that cracking of containment penetrations (including

penetration sleeves, penetration bellows, and dissimilar metal welds) due to cyclic loading or

SCC could occur in all types of containments. Cracking could also occur in vent line bellows,

vent headers and downcomers due to SCC for BWR containments. Further evaluation of

inspection methods is recommended to detect cracking due to cyclic loading and SCC since

visual VT-3 examinations may be unable to detect this aging effect.

Cracking Due to SCC. The GALL AMP XI.S1, “ASME Section XI Subsection IWE,” covers

inspection of these items under examination categories E-B, E-F, and E-P (10 CFR Part 50

Appendix J pressure tests). In 10 CFR 50.55a, examination categories E-B and E-F are

identified as optional during the current term of operation. For the extended period of operation,

examination categories E-B and E-F, and additional appropriate examinations to detect SCC in

bellows assemblies and dissimilar metal welds, are warranted to address this issue. 

In the LRA, the applicant stated that SCC of stainless steel exposed to atmospheric conditions

and contaminants is considered plausible only if the material temperature is above 140 °F. In

general, SCC very rarely occurs in austenitic stainless steels below 140 °F. Although stress

corrosion cracking has been observed in systems at temperatures lower than this 140 °F

threshold, all of these instances have identified a significant presence of contaminants

(halogens, specifically chlorides) in the failed components. This material is at a relatively low

temperature, in a sheltered environment, and not exposed to a corrosive environment.

The applicant further stated in the LRA that industry experience, detailed in NRC information

notice (IN) 92-20, described instances of the failure of the 10 CFR Part 50 Appendix J local leak

rate test (LLRT) to detect cracking in stainless steel containment penetration bellows. The

LLRT was inadequate due to the type of penetration bellows utilized at the nuclear power plant

that is the subject of the IN. The type of bellows used on the containment penetrations at BFN

is not the type described in IN 92-20. The vent line bellows are a single-ply bellows design. Pipe

penetration bellows for high-energy lines are two-ply bellows with a mesh. The design of the

penetration bellows allows full pressure to be transmitted to all portions of the bellows during

Appendix J testing. Containment penetrations bellows are not susceptible to failure of the

10 CFR Part 50 Appendix J LLRT to detect cracking, as described in IN 92-20. A review of the

operating history for the past five years did not indicate any failures associated with vent line

and penetration bellows. This issue was pursued in staff RAI 3.5-1 (see SER Section 3.5.2.3.1)

The applicant also stated in the LRA that the reinstatement of Examination Categories E-B and

E-F would result in hardship or unusual difficulty for BFN without a compensating increase in

the level of quality and safety. Therefore, existing requirements for 10 CFR Part 50 Appendix J

Program leak rate testing and visual examinations, in accordance with ASME Code Section XI,

Subsection IWE, Examination Category E-A, should be adequate to detect cracking due to

SCC. The reinstatement of ASME Code Section XI, Subsection IWE, Weld Examination

Categories E-B and E-F would not be required. Weld Examination Categories E-B and E-F

have been removed from the ASME Code Section XI, 1998 Edition.

During the audit, the staff asked the applicant if there was any operating history at BFN beyond

the past five years regarding signs of cracking and/or failures associated with the vent line and

penetration bellows. The staff also requested the applicant to discuss the hardship or unusual

difficulty for the applicant regarding reinstatement of Examination Categories E-B and E-F.
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By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that during the last nine years there has been no operating experience to indicate that cracking

or other aging effects resulted in a loss of intended function of the vent line bellows or

penetration bellows.

The applicant further stated that, in accordance with 10 CFR 50.55a, the performance of

examinations required by examination categories E-B and E-F are optional and that the staff

found no evidence of industry problems with these welds. 

The applicant also stated that specific weld locations on the containment would be required to

be located and identified on weld maps in order to perform examinations for examination

categories E-B and E-F. These weld locations have not been identified for the ASME Code

Section XI Subsection IWE ISI Program. The hardship associated with performing the weld

examinations associated with examination categories E-B and E-F is attributed to radiation

exposure received while performing examinations of welds that have no industry experience of

problems. Since specific weld locations have not been identified for the ASME Code

Section XI Subsection IWE ISI Program, it is not possible to provide an estimated radiation

exposure for performance of the examinations.

The applicant’s response also noted that the Summary of SECY-96-080, "Issuance Of Final

Amendment To 10 CFR 50.55a To Incorporate By Reference The ASME Boiler And Pressure

Vessel Code (ASME Code), Section XI, Division 1, Subsection IWE And Subsection IWL,"

states the following:

The third modification, 50.55a(b)(2)(x)(C), makes the Subsection IWE pressure retaining

welds and Subsection IWE pressure retaining dissimilar metal welds inspection

optional. The staff concluded that requiring these inspections is not appropriate. There

is no evidence of problems associated with welds of this type in operating plants. 

Therefore, the occupational radiation exposure that would be incurred while performing

these inspections cannot be justified. It is estimated that the total occupational

exposure that would be incurred yearly in the performance of the containment weld

inspections would be 440 person-rems.

The staff found the applicant’s response to be acceptable. 

Cracking Due to Cyclic Loading. Cracking of the containment shell and penetrations due to

cyclic loading is a TLAA. The staff evaluated TLAAs in SER Section 4.

3.5.2.2.8 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.

LRA Section 3.5.2.2.2.1 addresses 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 increases in porosity and permeability due to leaching of calcium hydroxide and
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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. 

SRP-LR Section 3.5.2.2.2.1 references SRP-LR Subsection 3.5.2.2.1.2 for the technical details

of the aging management issue for Items (5) and (6), above, and references SRP-LR

Section 3.5.2.2.1.3 for the technical details of the aging management issue for Item (8), above.

In LRA Section 3.5.2.2.2.1, the applicant stated that the further evaluations are also applied to

Group 6 structures, when applicable; and that the technical details of the AMRs associated with

SRP-LR Section 3.5.2.2.1.2, “Cracking, Distortion, and Increase in Components Stress Level

due to Settlement; Reduction of Foundation Strength due to Erosion of Porous Concrete

Subfoundations, if Not Covered by Structures Monitoring Program,” and SRP-LR

Section 3.5.2.2.1.3, “Reduction of Strength and Modulus of Elasticity due to Elevated

Temperature,” are also incorporated in this further evaluation.

The staff’s evaluation for Items (1) through (9) is presented below:

 (1) Freeze-thaw

The GALL Report, as updated by ISG-3, recommends that for accessible areas

inspections performed in accordance with the Structures Monitoring Program will

indicate the presence of loss of material (spalling, scaling) and cracking due to

freeze-thaw. For inaccessible areas, evaluation is needed for plants that are located in

moderate to severe weathering conditions (weathering index >100 day-inch/yr)

(NUREG-1557). Documented evidence to confirm that the in-place concrete had the air

content of three to six percent and that subsequent inspections performed did not detect

degradation related to freeze-thaw should be considered a part of the evaluation. The

weathering index for the continental US is shown in ASTM C33-90, Figure 1.

In LRA Section 3.5.2.2.2.1, the applicant stated that BFN is located in an area with

moderate weathering conditions, as noted on Figure 1 of ASTM C33-99. Freeze-thaw is

not considered an aging mechanism for concrete components below the frost line. The

concrete structures and concrete are designed in accordance with ACI 318-63 and ACI

318-71 and constructed using ingredients conforming to ACI and ASTM standards. TVA

specifications require all concrete to contain an air-entraining agent in sufficient quantity

to maintain specified percentages based on nominal maximum size aggregate. For

severe weather exposures (as defined in TVA-Specifications), the air content identified

varies from 4 to 10 percent, depending on aggregate size. Severe weather exposure (as

described in TVA-Specifications), is defined as “all exterior surfaces of concrete which

will be exposed to alternate wetting and drying.”
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The applicant further stated in the LRA that specified air content for reinforced concrete

is greater than the three to six percent for air content identified in ISG-03. Therefore,

loss of material (spalling, scaling) and cracking due to freeze-thaw are aging effects that

require aging management in accordance with ISG-03 for below-grade (above the frost

line) reinforced concrete structures and components. Below-grade reinforced concrete

will be inspected by the Structures Monitoring Program when excavated for any reason.

Accessible exterior above-grade concrete will be monitored by the Structures Monitoring

Program to manage loss of material and cracking due to freeze-thaw.

The staff concluded that the applicant’s AMR for loss of material and cracking due to

freeze-thaw is consistent with the GALL Report, and that the aging effects will be

adequately managed by the Structures Monitoring Program.

 (2)(a) Leaching of Calcium Hydroxide

The GALL Report, as updated by ISG-3, recommends that for accessible areas

inspections performed in accordance with the Structures Monitoring Program will

indicate the presence of increase in porosity and permeability due to leaching of calcium

hydroxide. For inaccessible areas, a plant-specific AMP is required for below-grade

inaccessible areas (basemat and concrete wall) if the concrete is exposed to flowing

water (NUREG-1557). An AMP is not required, even if reinforced concrete is exposed to

flowing water, if there is documented evidence that confirms the in-place concrete was

constructed in accordance with the recommendations in ACI 201.2R-77.

In LRA Section 3.5.2.2.2.1, the applicant stated that concrete structures and concrete

components are designed in accordance with ACI 318-63 and ACI 318-71 and

constructed using ingredients conforming to ACI and ASTM standards, which provide for

a good quality, dense, well cured, and low permeability concrete. Cracking is controlled

through proper arrangement and distribution of reinforcing steel. Concrete structures

and concrete components are constructed of a dense, well-cured concrete with an

amount of cement suitable for strength development, and achievement of a

water-to-cement ratio which is characteristic of concrete having low permeability. This is

consistent with the recommendations and guidance provided by ACI 201.2R-77. In

addition, concrete components must be exposed to flowing water through the concrete

component. Leaching of calcium hydroxide is readily noticeable as white deposits that

remain on the concrete surface after a solution of water-free lime from the concrete and

carbon dioxide from the air is absorbed and dries. The Structures Monitoring Program

inspects concrete areas for signs of leaching. No significant signs of leaching have been

documented during these inspection walkdowns. Therefore, the conditions identified in

the GALL Report as revised by ISG-03 are satisfied, and aging management of an

increase in porosity and permeability and a loss of strength due to leaching of calcium

hydroxide for below-grade inaccessible concrete is not required. However, the

Structures Monitoring Program will be used to manage aging effects caused by an

increase in porosity and permeability and loss of strength due to leaching of calcium

hydroxide of concrete.

The staff concluded that the applicant’s AMR for scaling, cracking, spalling and increase

in porosity and permeability due to leaching of calcium hydroxide is consistent with the

GALL Report, and that the aging effects will be adequately managed by the Structures

Monitoring Program.
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 (2)(b) Aggressive Chemical Attack

The GALL Report, as updated by ISG-3, recommends that for accessible areas,

inspections performed in accordance with the Structures Monitoring Program will

indicate the presence of increase in porosity and permeability, cracking, or loss of

material (spalling, scaling) due to aggressive chemical attack. For inaccessible areas, a

plant-specific AMP is required (may be a part of Structures Monitoring Program) if the

below-grade environment is aggressive (pH < 5.5; chlorides >500 ppm; or sulfates

>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. The

GALL Report notes that periodic monitoring of below-grade water chemistry (including

consideration of potential seasonal variations) is an acceptable approach to

demonstrate that the below-grade environment is nonaggressive.

In LRA Section 3.5.2.2.2.1, the applicant stated that the Structures Monitoring Program

will be used to inspect accessible concrete areas for aging effects caused by scaling,

cracking, spalling and increase in porosity and permeability due to aggressive chemical

attack.

The staff concluded that the applicant’s AMR for scaling, cracking, spalling and increase

in porosity and permeability due to aggressive chemical attack is consistent with the

GALL Report for accessible areas, and that the aging effects will be adequately

managed by the Structures Monitoring Program. The staff’s evaluation for inaccessible

areas is in SER Section 3.5.2.2.9.

 (3) Reaction with Aggregates 

The GALL Report, as updated by ISG-3, recommends that for accessible areas,

inspections/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, 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 3.5.2.2.2.1, the applicant stated that the aggregate used in the concrete of the

BFN components did not come from a region known to yield aggregates suspected of,

or known to cause, aggregate reactions. Materials for concrete used in BFN structures

and components were specifically investigated, tested, and examined in accordance

with pertinent ASTM standards. All aggregates used at BFN conform to the

requirements of ASTM C33 "Standard Specification of Concrete Aggregates."

Appendix XI of ASTM C33 identifies methods for evaluating potential reactivity of

aggregates including ASTM C295, ASTM C289, ASTM C227, and ASTM C342. If

potentially reactive aggregates were used, then use of a low alkali Portland Cement

(ASTM C150 Type II) containing less than 0.60 percent alkali calculated as sodium

oxide equivalent was required by TVA-Specifications and will prevent harmful expansion

due to alkali aggregate reaction. Therefore, the conditions identified in the GALL Report

as revised by ISG-03 are satisfied, and aging management of expansion and cracking

due to reaction with aggregates for below-grade inaccessible concrete is not required.

However, the Structures Monitoring Program will be used to inspect accessible concrete

areas for aging effects caused by reaction with aggregates.
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The staff concluded that the applicant’s AMR for expansion and cracking due to reaction

with aggregates is consistent with the GALL Report, and that the aging effects will be

adequately managed by the Structures Monitoring Program.

 (4) Corrosion of embedded steel

The GALL Report, as updated by ISG-3, recommends that for accessible areas,

inspections performed in accordance with the Structures Monitoring Program will

indicate the presence of cracking, loss of bond, and loss of material (spalling, scaling)

due to corrosion of embedded steel. For inaccessible areas, a plant-specific AMP is

required (may be a part of Structures Monitoring Program) if the below-grade

environment is aggressive (pH < 5.5, chlorides > 500ppm, or sulfates > 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. The GALL Report

notes that periodic monitoring of below-grade water chemistry (including consideration

of potential seasonal variations) is an acceptable approach to demonstrate that the

below-grade environment is aggressive or nonaggressive.

In LRA 3.5.2.2.2.1, the applicant stated that BFN will use the Structures Monitoring

Program to inspect accessible concrete areas for aging effects caused by corrosion of

embedded steel.

The staff concluded that the applicant’s AMR for cracking, spalling, loss of bond, and

loss of material due to corrosion of embedded steel is consistent with the GALL Report

for accessible areas, and that the aging effects will be adequately managed by the

Structures Monitoring Program. The staff’s evaluation for inaccessible areas is in SER

Section 3.5.2.2.9.

 (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 I structures. Some plants

may rely on a de-watering system to lower the site ground water level. If the plant's CLB

credits a de-watering system, the GALL Report recommends verification of the

continued functionality of the de-watering system during the period of extended

operation. The GALL Report recommends no further evaluation if this activity is included

in the scope of the applicant's Structures Monitoring Program. 

In LRA Section 3.5.2.2.2.1, the applicant stated that cracks, distortion, and increase in

component stress level due to settlement are not considered AERM for structures

founded on rock or bearing piles. The following BFN structures are founded on rock or

bearing piles: reactor buildings, primary containments, intake pumping station,

reinforced concrete chimney, off-gas treatment building, equipment access lock, turbine

buildings, gate structure number 3, diesel HPFP house, transformer yard, and RHRSW

tunnel. Based on industry experience, settlement of Class I structures founded on

bedrock or bearing piles have not been noted to cause AERM.

For concrete structures founded on dense soil or backfill, the applicant stated that it can

be concluded that cracking due to settlement is not significant if in the past 20 years of

operating experience for a structure the total differential settlement experienced is well

within the permissible limits for this type of structure and no settlement has manifested
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itself via cracked walls or cracked foundations. In this case, aging management for

settlement would not be applicable for the structure during the period of extended

operation. Prior settlement monitoring programs have revealed that soil settlement has

stabilized and the structures will continue to perform their intended functions. However,

due to prior operating history of settlement in the 1980s at BFN, cracking and distortion

due to settlement of structures founded on soil or backfill will be monitored by the

Structures Monitoring Program.

The staff concluded that the applicant’s AMR for cracks, distortion, and increase in

component stress level due to settlement is consistent with the GALL Report, and that

the aging effects will be adequately managed by the Structures Monitoring Program.

 (6) Erosion of porous concrete subfoundation

The GALL Report states that erosion of cement from porous concrete subfoundations

beneath containment basemats is described in IN 97-11. IN 98-26 proposes

Maintenance Rule structures monitoring for managing this aging effect, if applicable. If a

dewatering system is relied upon for control of erosion of cement from porous concrete

subfoundations, then the applicant is to ensure proper functioning of the dewatering

system through the period of extended operation.

In LRA 3.5.2.2.2.1, the applicant stated that the evaluation of Information Notice 98-26

concluded that porous concrete subfoundations were not used at BFN. A dewatering

system is not relied upon for control of erosion of cement from porous concrete

subfoundations. Therefore, reduction in foundation strength, cracking, and differential

settlement due to erosion of porous concrete subfoundation are not applicable.

The staff concluded that the applicant’s AMR for reduction in foundation strength,

cracking, and differential settlement due to erosion of porous concrete subfoundation is

consistent with the GALL Report, and that these aging effects are not applicable.

 (7) Corrosion of structural steel components

The GALL Report states that further evaluation is necessary only for structure/aging

effect combinations not covered by the Structures Monitoring Program. If protective

coatings are relied upon to manage the effects of aging, the Structures Monitoring

Program is to include requirements to address monitoring and maintenance of protective

coatings.

In LRA Section 3.5.2.2.2.1, the applicant stated that the Structures Monitoring Program

will manage loss of material due to corrosion of structural steel components. The

Structures Monitoring Program procedures specify visual inspections of structural

conditions as the method used to detect degradation.

The applicant further stated that, for the steel that is embedded/encased within the

concrete, corrosion is not an applicable aging mechanism. The concrete must first be

degraded by other aging mechanisms, which reduce the protective cover and allow for

the intrusion of aggressive ions causing a reduction in concrete pH. Aging management

of previously noted concrete aging effects will manage loss of material for steel that is

embedded/encased within concrete.

The applicant also makes note that NUREG-1557, Table B9, states that steel piles

driven in undisturbed soil have been unaffected by corrosion and those driven in
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disturbed soil experience minor to moderate corrosion to a small area of metal. Loss of

material for steel piles driven in undisturbed or disturbed soil does not require aging

management.

The applicant also stated that the protective coating monitoring and maintenance

program is not credited for aging management of loss of material for structural steel

components.

The staff concluded that the applicant’s AMR for loss of material due to corrosion of

structural steel components is consistent with the GALL Report, and that the aging

effects will be adequately managed by the Structures Monitoring Program. The staff

also concurred with the applicant’s AMR for steel piles, because it is based on a

documented staff technical assessment.

 (8) Elevated temperatures

The GALL Report calls for a plant-specific AMP and recommends further evaluation if

any portion of the concrete components exceeds specified temperature limits, (i.e.,

general area temperature 66 °C (150 °F) and local area temperature 93 °C (200 °F)).

In LRA Section 3.5.2.2.2.1, the applicant stated that with the exception of the main

steam tunnels in the reactor building BFN reinforced concrete structures have general

area temperatures less than 150 °F during normal operation. General area temperatures

have been conservatively evaluated using maximum normal space ambient

temperatures noted on the harsh environmental drawing series and associated

calculations. The main steam tunnels have a maximum normal space ambient

temperature of 160 °F, as noted in the harsh environmental drawing series and

associated calculations. This is a maximum normal space ambient temperature. The

harsh environmental drawing series and associated calculations identify the space

average normal ambient temperature as 135 °F. This is judged to be acceptable by the

applicant, because when concrete is subjected to prolonged exposure to elevated

temperatures reductions in excess of 10 percent of the compressive strength, tensile

strength, and the modulus of elasticity begin to occur in the range of 180 °F to 200 °F.

The applicant further stated that each drywell is cooled during normal plant operation by

a closed-loop ventilation system designed to keep the average temperature in the

drywell less than 150 °F. The general area temperature inside the drywell (primary

containment) is maintained below 150 °F as required by Technical Specifications.

Elevated temperatures on internal concrete components such as the reactor support

pedestal, where the temperature could approach 150 °F, are addressed as appropriate

by BFN civil design criteria. The drywell concrete structure surrounding the drywell

vessel was evaluated for thermal effects from the general area temperature of the

drywell. The upper elevations of the sacrificial shield wall may exceed 150 °F briefly and

infrequently, during abnormal operations; this is not considered to affect its function.

The applicant concluded that the conditions identified in the GALL Report are satisfied

and aging management for reduction of strength and modulus due to elevated

temperature for concrete components is not required.
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During the audit, the staff requested the applicant to:

 (1) Explain how the elevated temperature on internal concrete components, where

the temperature could approach 150 °F, are addressed by BFN civil design

criteria.

 (2) Discuss the evaluation of the drywell concrete structure for thermal effects.

 (3) Discuss the technical basis for concluding that “the upper elevations of the

sacrificial shield wall may exceed 150 °F briefly and infrequently, during abnormal

operations and is not considered to affect its functions.” 

 (4) Discuss the local temperatures that can be expected in the concrete surrounding

hot piping penetrations and what provisions exist for maintaining these

temperatures within acceptable limits.

By letter dated October 8, 2004, the applicant submitted its formal response to the staff,

stating that the GDC document, BFN-50-C-7100 “Design of Civil Structures” (DC),

provides the design basis requirements for all BFN structures, including the primary

containment. In DC Section 3.2.5, Appendix C, the temperature requirements are

defined for the drywell concrete, with an operating temperature of 150 °F specified for

the drywell.

DC Appendix C, Table 15-10, “Reactor Support Pedestal Design Data,” provides the

principal design cases for the reactor support pedestal and includes the requirement to

consider thermal effects for each principal design case. DC Appendix C, Table 15-12,

“Reactor Building Concrete Structure Fuel Pool Storage Pool and Dryer/Separator

Storage Pool Design Data,” requires the consideration of drywell thermal rise for the

appropriate principal design cases for the spent fuel storage pool and dryer/separator

storage pool of the reactor building. Both these pools have structural elements that form

portions of the outer structural concrete shell of the primary containment steel shell. DC

Appendix C, Table 15-15(a), “Drywell Concrete Structure,” provides the principal design

cases for the drywell concrete and requires the consideration of thermal effects in the

principal loading combinations for the drywell concrete structure.

The applicant further stated that the sacrificial shield wall provides a biological shield for

protection of personnel from gamma radiation, a neutron shield to prevent activation of

the drywell components during operation, and a means of supporting the drywell pipe

hangers and access platform. It also provides protection against damage to the nuclear

system process barrier due to seismic loading, against further damage due to vessel

pipe penetration rupture jet forces, and a limit stop and support for pipe restraints in the

event of a drywell pipe rupture. It consists of a 24-foot diameter circular cylinder

attached to the vessel support pedestal and extending upward approximately 45 feet.

The sacrificial shield wall is 27 inches thick and is constructed from 26-inch vertical WF

beam columns, tied together by horizontal WF beams and 1/4-inch plates. 

The applicant stated that the 1⁄4-inch plates are welded to the column flanges, both

inside and outside, thereby forming a double-walled shell. This shell is filled with

concrete to provide biological shielding capability. The concrete was assumed to have

no structural purpose, except for the lowest 10 feet 6 inches of the wall. Based on the

design criterion that the concrete has no structural purpose except for the lowest 10.5

feet, the applicant concluded that “the upper elevations of the sacrificial shield wall may
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exceed the 150 °F briefly and infrequently during abnormal operation and is not

considered to affect its function,” as stated in LRA 3.5.2.2.2.1, Item 8.

In its response, the applicant also noted that degradation of drywell concrete due to

elevated temperature would be addressed in its response to RAI 3.5-5. This issue will be

dispositioned in the staff evaluation of the applicant’s response to RAI 3.5-5. 

 (9) Aging Effects for Stainless Steel Liners for Tanks

In LRA Section 3.5.2.2.2.1, the applicant stated that BFN does not have any Group 7

structures or in-scope stainless steel liners in an exposed-to-fluid environment for any

Group 8 structures. The staff concluded that further evaluation of this aging effect is not

applicable.

In summary, the staff found that the applicant had demonstrated that the effects of

aging, with the exception of elevated temperatures, will be adequately managed by the

Structures Monitoring Program, so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3).

3.5.2.2.9 Aging Management of Inaccessible Areas

The staff reviewed LRA Section 3.5.2.2.2.2 against the criteria in SRP-LR Section 3.5.2.2.2.2.

In LRA Section 3.5.2.2.2.2, the applicant addressed aging of inaccessible areas of Class 1

structures.

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. ISG-3 identifies additional requirements.

The GALL Report, as updated by ISG-3, states that for inaccessible areas, a plant-specific

AMP is required (may be part of Structures Monitoring Program) if the below-grade environment

is aggressive (pH < 5.5; chlorides > 500 ppm; or sulfates > 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. The GALL Report also notes that periodic

monitoring of below-grade water chemistry (including consideration of potential seasonal

variations) is an acceptable approach to demonstrate that the below-grade environment is

nonaggressive.

In LRA Section 3.5.2.2.2.2, the applicant stated that design and construction of reinforced

concrete provides dense, well cured, and low permeability concrete with an acceptable degree

of protection for the embedded steel against exposure to an aggressive environment. Cracking

of concrete is controlled through proper arrangement and distribution of reinforcing steel.
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The applicant further stated that continued or frequent cyclic exposure to the following

aggressive environments is necessary for aggressive chemicals to cause significant aggressive

chemical attack or corrosion of embedded steel:

 • acidic solutions with pH less than 5.5

 • chloride solutions greater than 500 ppm

 • sulfate solutions greater than 1500 ppm

The applicant stated that aggressive chemicals are present at plant sites, system leakage is

leakage that could cause aggressive chemical attack is possible. However, leaks are not

expected to continue for the extensive periods required for degradation, and repairs would be

completed prior to loss of intended function. An aggressive environment may also occur where

concrete is exposed to aggressive aqueous solutions such as groundwater or aggressive water

flow. Groundwater sample measurements confirm that parameters are below threshold limits

that could cause aggressive chemical attack for below-grade inaccessible concrete. Natural

groundwater movement in this area is from the plant site to Wheeler Reservoir. Wheeler

Reservoir water samples also confirm that an aggressive environment does not exist.

Therefore, the applicant concludes that the conditions identified in the GALL Report, as revised

by ISG-03, are satisfied and aging management of 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 is not required for below-grade inaccessible

concrete.

The applicant concluded that Browns Ferry groundwater and Wheeler Reservoir sample

measurements have confirmed that parameters are well below threshold limits that could cause

concrete degradation (an aggressive environment does not exist) and that the rate of

groundwater flow is not considered aggressive. 

The applicant stated that BFN does not commit to periodic groundwater monitoring over the

period of license extension, since it is not credible to postulate that some environmental event

will occur in the future that would affect the quality of groundwater in the vicinity of Browns

Ferry. A change in the environment due to a chemical release would be considered an

abnormal event. SRP-LR states that aging effects from abnormal events need not be

postulated specifically for license renewal.

The staff found that the applicant’s response is not consistent with the GALL Report

recommendation for periodic monitoring of groundwater. This issue was dispositioned by the

staff, based on the applicant’s responses to RAIs 3.5-7 and 3.5-8 and is discussed in SER

Section 3.5.2.3.2.

3.5.2.2.10 Aging of Supports Not Covered by Structures Monitoring Program

The staff reviewed LRA Section 3.5.2.2.3.1 against the criteria in SRP-LR Section 3.5.2.2.3.1.

In LRA Section 3.5.2.2.3.1, the applicant addressed aging of component supports that are not

managed by the Structures Monitoring Program. 

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
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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.

 (1) Reduction in concrete anchor capacity due to degradation of the surrounding concrete

for Groups B1 through B5 supports. 

In LRA Section 3.5.2.2.3.1, the applicant stated that reduction in concrete anchor

capacity due to local concrete degradation for Groups B1 – B5 supports will be

managed by the Structures Monitoring Program.

 (2) Loss of material due to environmental corrosion, for Groups B2-B5 supports. 

In LRA Section 3.5.2.2.3.1, the applicant stated that loss of material due to

environmental corrosion for Groups B2 – B5 Supports will be managed by the

Structures Monitoring Program.

 (3) Reduction/loss of isolation function due to degradation of vibration isolation elements for

Group B4 supports.

In LRA Section 3.5.2.2.3.1, the applicant stated that there are no vibration elements

within the scope of license renewal.

The staff found that the applicant had appropriately evaluated AMR results involving

management of aging of component supports, as recommended 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).

3.5.2.2.11 Cumulative Fatigue Damage due to Cyclic Loading

Cumulative fatigue damage is a TLAA. TLAAs are evaluated in SER Section 4.

3.5.2.2.12 Quality Assurance for Aging Management of Non-Safety-Related Components

SER Section 3.0.4 provides a separate 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).
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3.5.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report

Summary of Technical Information in the Application. In LRA Tables 3.5.2.1 through 3.5.2.26,

the staff reviewed additional details of the results of the AMRs for MEAP combinations that are

not consistent with the GALL Report, or that are not addressed in the GALL Report.

In LRA Tables 3.5.2.1 through 3.5.2.26, the applicant indicated, via Notes F through J, that the

combination of component type, material, environment, and AERM does not correspond to a

line item in the GALL Report, and provided information concerning how the aging effect will be

managed. Specifically, Note F indicated that the material for the AMR line item component is

not evaluated in the GALL Report. Note G indicated that the environment for the AMR line item

component and material is not evaluated in the GALL Report. Note H indicated that the aging

effect for the AMR line item component, material, and environment combination is not evaluated

in the GALL Report. Note I indicated that the aging effect identified in the GALL Report for the

line item component, material, and environment combination is not applicable. Note J indicated

that neither the component nor the material and environment combination for the line item is

evaluated in the GALL Report.

Staff Evaluation. During the onsite audit, the staff reviewed selected items in all applicable LRA

Table 3.5 items for MEAP combinations that are not consistent with the GALL Report. The staff

requested clarifications for the following material/environment combinations and the

corresponding LRA Table 2 items:

Carbon Steel in an Embedded/Encased Environment - It is recognized that all metals

embedded/encased in concrete are inaccessible; however, they could be susceptible to aging

degradation. The staff requested that the applicant provide an AMR for further evaluation of

embedded/encased components if aging of components in accessible areas is identified that

may indicate aging of the inaccessible components.

By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that the BFN concrete structures and concrete components are designed in accordance with

ACI 318-63 and 71 and constructed using ingredients conforming to ACI and ASTM Code

standards, which provide for a good quality, dense, well cured, and low permeability concrete.

Cracking is controlled through proper arrangement and distribution of reinforcing bars.

The applicant further stated that concrete structures and concrete components are constructed

of a dense, well-cured concrete with an amount of cement suitable for strength development,

and achievement of a water-to-cement ratio that is characteristic of concrete having low 

permeability. This is consistent with the recommendations and guidance provided by

ACI 201.2R-77.

The applicant also stated that, as a minimum, all exposed portions of embedded/encased

carbon steel structural components are inspected by the Structures Monitoring Program for the

following aging effects:

 • outside air environments: loss of material due to general and pitting corrosion

 • inside air environments: loss of material due to general corrosion

 • containment air environments: loss of material due to general corrosion
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The applicant concluded that the condition of the exposed portion of the embedded/encased

carbon steel will provide an indication of the condition of the embedded/encased portion of the

carbon steel. If a deficient condition were identified for the exposed portion of the

embedded/encased carbon steel material, the Corrective Action Program (SPP-3.1) would

document the deficient condition. Resolution of the deficient condition would require the

development of a corrective action plan and consideration would be given to the extent of the

deficient condition in the development of the corrective actions, which would include the

embedded/encased portion of the material as warranted by the deficient condition.

The applicant also stated that a review of BFN operating history did not reveal any loss of

intended function due to aging effects for carbon steel components embedded/encased in

concrete. 

The staff found that the applicant had identified an appropriate course of action, through its

Corrective Action Program, to manage aging of carbon steel components embedded/encased

in concrete, if a deficient condition is identified for the exposed portion of the

embedded/encased carbon steel material. On this basis, the staff accepts the applicant’s AMR

results for carbon steel in an embedded/encased environment.

Stainless Steel in Containment Air, Inside Air and Outside Air Environments - The staff

requested that the applicant provide the technical basis for concluding that the BFN stainless

steel components do not require aging management for any aging effects/mechanisms in

containment atmosphere, inside air, and outside air environments.

By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that the AMR evaluation for stainless steel in a containment atmosphere, inside air, and outside

air is not susceptible to loss of material in for these environments. Stainless steels form a

passive film that prevents corrosion. Only a corrosive wetted environment is conducive to

promoting aging degradation of stainless steel. Alternate wetting and drying in an outside air

environment has shown a tendency to ‘wash’ the exterior surfaces, cleaning the surface rather

than concentrating any corrosive contaminants (ref EPRI 1003056 Mechanical Tools). SCC of

stainless steel, which is only considered plausible in wetted corrosive environments greater

than 140 °F, will not occur in the containment atmosphere environment, inside air environment,

or outside air environment. 

The staff found the applicant’s AMR results to be acceptable for stainless steel structural

components and stainless steel non-ASME supports. In the absence of corrosive contaminants

and temperatures greater than 140 °F, stainless steel material is not susceptible to loss of

material due to corrosion and cracking due to SCC. Therefore, aging management for loss of

material and cracking in the containment atmosphere environment, an inside air environment,

or an outside air environment is not required. 

In its response, the applicant also stated that ASME stainless steel equivalent supports are

subject to the requirements of ASME Code Section XI, Subsection IWF during the period of

extended operation. However, the staff determined that the applicant had not credited IWF for

aging management of ASME stainless steel equivalent supports during the extended period of

operation, because the applicant’s AMR had not identified any applicable aging effects. The

staff requested additional information to resolve this issue and related issues. The disposition is

discussed in SER 3.5.2.3.26, as part of the review of LRA Table 3.5.2.26 AMRs.
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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.

The staff’s evaluation is discussed in the following sections.

3.5.2.3.1 Primary Containment Structures – Summary of Aging Management Evaluation –

Table 3.5.2.1

The staff reviewed LRA Table 3.5.2.1, which summarizes the results of AMR evaluations for the

primary containment structures component groups.

During the onsite audit, the staff reviewed selected items in LRA Table 3.5.2.1, for MEAP

combinations that are not consistent with the GALL Report. The staff requested clarifications for

the following material/environment combinations and the corresponding LRA Table 2 items:

Lubrite in a Containment Air Environment – The staff requested that the applicant describe

where the referenced items are used and provide the technical basis for concluding that no

aging management of the lubrite plates used in BFN is required in a containment atmosphere.

By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that Table 3.5.2.1, row 37 applies to the lubrite plates used for the drywell floor beam seats.

EPRI 1002950, “Aging Effects for Structures and Structural Components (Structural Tools),

Revision 1,” states that lubrite material resists deformation, has a low coefficient of friction,

resists softening at elevated temperatures, absorbs grit and abrasive particles, is not

susceptible to corrosion, withstands high intensities of radiation, and will not score or mar.

Lubrite products are solid, permanent, completely self lubricating, and require no maintenance.

The containment atmosphere at the location of the drywell floor beam seats is not an

aggressive or wetted environment. 

The applicant also stated that a search of BFN and industry operating experience did not

identify any instances of lubrite plate degradation or failure to perform its intended function due

to aging effects. NUREG-1759, “Safety Evaluation Report Related to the License Renewal of

Turkey Point Nuclear Plant, Units 3 and 4” and NUREG-1769, “Safety Evaluation Report

Related to the License Renewal of Peach Bottom Atomic Power Station, Units 2 and 3,” concur

that there are no lubrite plate aging effects that require aging management.

Based on the additional information provided by the applicant, the staff finds the applicant’s

AMR results for lubrite plates to be acceptable. Prior staff evaluations of this issue have

concluded that there are no aging effects requiring aging management.

The staff’s review of LRA Table 3.5.2.1 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 RAI 3.5-1, dated December 10, 2004, the staff inquired about the leakage rate testing of

containment penetration bellows by pointing out that LRA Table 3.5.1, Item Numbers 3.5.1.3

and 3.5.1.17, indicate that the AMR results are consistent with the GALL Report, with the

exceptions described in ASME Code Section XI Subsection IWE Program. The GALL Report,
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Item B.1.1.1-d recommends further evaluation regarding the SCC of containment bellows. In

the discussion of these items in LRA Section 3.5.2.2.1.7, the applicant asserted that

Appendix J, Type B testing was effective in detecting leakages through the vent line bellows, as

well as through other pressure boundary bellows. The staff requested the applicant to provide

additional information regarding the frequency of Type B testing (performance-based intervals,

in accordance with Option B, Appendix J) of containment pressure boundary bellows at Units 2

and 3, and the status of these bellows for Unit 1.

In its response, by letter dated January 31, 2005, the applicant quoted the content of LRA

Section 3.5.2.2.1.7 and then stated:

BFN pipe penetration bellows are 10 CFR 50, Appendix J, Type B tested. BFN vent line

bellows are 10 CFR 50, Appendix J, Type A tested. 

Type B and C tests are performed prior to initial reactor operation. Subsequent Type B

and C tests are performed at a frequency of at least once per 30 months until

performance data are collected for evaluation for extended test interval in accordance

with RG 1.163. Type B tests may use an extended interval of up to 120 months

(excluding airlocks). Unit 2 and 3 bellows are tested at a 60-month test interval. There

have been no bellows failures on either Unit 2 or 3 bellows. Prior to the restart of Unit 1,

Appendix J, Type B testing of containment pipe penetration bellows will be performed.

Unit 1 bellows will be tested at least once per 30 months until test performance data is

available to justify an extended test interval under Option B.

The staff noted that the vent line bellows are single-ply, and their leakage rates and aging

degradation are managed by Appendix J, Type A testing. As Appendix J, Type A testing is

generally performed at 10-year intervals or greater, it was not clear to the staff how the

leaktightness and structural integrity of the vent line bellows were maintained. The applicant

was requested to provide the frequency at which the Type A testing is performed in each unit,

and the process by which the integrity of the vent line bellows is maintained, including

corresponding operating experience.

In its letter dated May 31, 2005, the applicant stated that it has been granted a one-time 5-year

extension by the staff for performing the Type A test, and emphasized that there had been no

performance-based Type A test failure on Units 2 or 3. The applicant plans to perform an

Appendix J, Type A integrated leak rate test (ILRT) on Unit 1 prior to restart. The Unit 1

Appendix J, Type A test will be performed at least once every 48 months until test performance

data are available to justify an extended test interval under Option B. Moreover, the applicant

provided a detailed description of the history of the visual examinations performed under its

plant procedures 2-TI-173 and 3-TI-173 which performs a general visual examination each

inspection period (three periods per 10 year interval). Different from other BWR Mark I

containments, the single-ply vent line bellows at the three BFN units are accessible for

examination from the torus interior. A VT-3, visual examination is performed each inspection

interval in accordance with plant procedure 0-TI-376. The applicant emphasized that these

examinations are thorough as they are performed by NDE-certified personnel with specific

lighting and visual acuity requirements. Additionally, plant procedure 0-SI-4.7.A.2.K, “Primary

Containment Drywell Surface Visual Examination,” is performed each operating cycle.
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Based on the detailed response regarding the detection of flaws in vent line bellows provided by

the applicant, the staff found the applicant’s process for ensuring the integrity of the vent line

bellows acceptable. Therefore, the staff’s concern described in RAI 3.5-1 is resolved. 

In RAI 3.5-2, dated December 10, 2004, the staff stated that, for seals and gaskets related to

containment penetration, LRA Table 3.5.1, Item Number 3.5.1.6 and component type,

"Compressible Joints and Seals," in LRA Table 3.5.2.1, the ASME Code Section XI Subsection

IWE Program and the 10 CFR 50 Appendix J Program have been identified as AMPs. Based on

Exception 1 in the ASME Code Section XI Subsection IWE Program, the AMP will not be

applicable for aging management of containment seals and gaskets. For equipment hatches

and air-locks, the assumption is that the leak rate testing program will monitor aging

degradation of seals and gaskets, as they are leak rate tested after each opening. Therefore,

the staff requested that the applicant clarify whether these assumptions are correct. For other

penetrations (mechanical and electrical) with seals and gaskets, the applicant was requested to

provide information regarding the adequacy of Type B leak rate testing frequency to monitor

aging degradation of seals and gaskets of containment drywells. The applicant was also

requested to provide the status of seals and gaskets of these penetrations at Unit 1.

In its response, by letter dated January 31, 2005, the applicant stated:

ASME Section XI, 1992 Edition, 1992 Addenda, Category E-D, Item Numbers E5.10

(Seals), and E5.20 (Gaskets) requires a visual examination, VT-3, of containment seals

and gaskets. Examination of most seals and gaskets requires the joints to be

disassembled. When the airlocks, hatches, electrical penetrations, and flanged

connections are tested in accordance with 10 CFR 50, Appendix J, degradation of the

seal or gasket material would be revealed by an increase in the leakage rate. Corrective

measures would be applied and the component retested.

For Units 1, 2, and 3, Relief Request CISI-1 was granted to perform Appendix J test in

lieu of the visual examination, VT-3, on the containment seals and gaskets. The

moisture barriers continue to receive a visual VT-3 examination in accordance with

Category E-D for Units 1, 2, and 3. The scope of the 10 CFR 50 Appendix J Program

includes all pressure-retaining components, the containment shell (drywell and torus)

and penetrations. The following components are included in the scope of the program:

 • containment penetration seals on airlocks, hatches, spare penetrations with

flange connections, electrical penetrations and other devices required to assure

containment leak-tight integrity;

 • containment penetration gaskets on airlocks, spare penetrations with flange

connections, and other devices required to assure containment leak-tight

integrity;

 • pressure retaining bolted connections;

 • containment penetration bellows; and

 • airlocks.

Units 2 and 3 O-ring seals (flanges, hatches, etc.) are tested on either a 30 or 60-month

interval. Seal failures have occurred sporadically since restart. The Unit 2 and Unit 3
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drywell heads have experienced failures and are currently classified as Maintenance

Rule (a)(1) for corrective actions. There are currently no electrical penetration

performance problems on Unit 2. All electrical penetrations on Unit 2 are currently on a

120-month test interval. Testing has identified only minor problems such as gauge,

tubing, and root valve leaks. Unit 3 electrical penetrations are on 30, 60, or 72-month

test intervals. In general, testing has identified only minor problems such as gauge,

tubing, and root valve leaks. However, one electrical penetration (3-EPEN-100-0101C)

on Unit 3 experienced a failure, was repaired, and is being tested on a 30-month test

interval. Other electrical penetrations are being tested at a 60-month interval. The

remainder of the Unit 3 electrical penetrations are on a 72-month interval.

Type B testing will be performed as part of the Unit 1 restart effort and will continue at

least once per 30 months until test performance data is available to justify an extended

test interval under Option B.

The applicant described the existing process used in identifying degradation of the primary

containment penetration seals and gaskets and plans to continue with the testing and corrective

action process during the period of extended operation. Therefore, the staff found the

applicant’s process for managing the aging of the pressure-retaining seals and gaskets of

primary containments acceptable. The staff’s concerns described in RAI 3.5-2 are resolved.

In RAI 3.5-3, dated December 10, 2004, the staff stated that the containment drywell-head to

drywell joint consists of a pressure unseating containment boundary with pre-loaded bolts.

Loosened bolts and deteriorated gasket and/or seals can breach containment pressure

boundary. Exceptions 1 and 2 taken in the ASME Section XI Subsection IWE Program will

preclude examinations of seals and bolts of this joint. Only Type A leak rate testing and

associated visual examination requirements of the 10 CFR 50 Appendix J Program can be

relied upon to detect defects and degradation of this joint. The test interval for Type A leak rate

testing can be 10 to 15 years. Therefore, the staff requested the applicant to provide (1)

information regarding the plans and programs that are used to ensure the integrity of this joint

for each containment and (2) the status of the components (O-rings and bolts) at this joint for

Unit 1.

In its response, by letter dated January 31, 2005, the applicant stated:

These containment pressure boundary components will continue to be inspected

consistent with the Browns Ferry CLB for 10 CFR Part 50, Appendix J requirements. On

Units 2 and Unit 3 the Type A test frequency is currently on a 10-year interval. There

have been no performance based Type A test failures on Unit 2 or Unit 3. A Type A

Integrated Leak Rate Test will be performed as part of the Unit 1 restart effort. Type B

testing is also performed on the drywell-head seal every refueling outage for all three

units. Therefore, in combination of the Type A tests and Type B tests, integrity for this

joint for each containment is assured. Exception 2 pertains to bolt torque or tension

testing. Pressure retaining bolting associated with the Containment drywell-head to

drywell joint is examined in accordance with ASME Section XI Subsection IWE.

The applicant performs Type B testing of the drywell-head seal every outage, and examines the

pressure retaining bolts of the drywell head in accordance with Subsection IWE of the ASME

Section XI Code. The staff accepts that these two activities together with periodic Type A
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testing will ensure the integrity of this joint. Therefore, the staff found the applicant’s practice of

ensuring the integrity of this joint acceptable. The staff’s concern described in RAI 3.5-3 is

resolved.

In RAI 3.5-4, dated December 10, 2004, the staff stated that the water leakages from the sand

drains have been found in Units 2 and 3, and the results of the UT examinations performed

from the accessible areas of the drywells have indicated that the condition of the drywell shells

was good, and these areas did not require augmented examination. Therefore, the staff

requested that the applicant provide the following additional information related to the drywell

shell corrosion in this area for each containment drywell:

 a. In other Mark I containments, the cause of water leakage from the sand-bed drains has

been found to be water leaking from the refueling cavity (see IN 86-99, "Degradation of

Steel Containments).” As no water leakage has been indicated from Unit 1 (having no

refueling activities during its long layup), it would appear that the cause of the water

leakage in Units 2 and 3 could be the same as that described in the information notice.

Provide a discussion of the root cause in this context.

 b. If the water leakage is related to refueling operation, provide information regarding the

corrosion susceptibility of the cylindrical part of the drywell shell on the insulation

(inaccessible) side.

 c. Item No. E4.12 of Examination Category E-C of Subsection IWE requires the owner to

establish grid and measurement locations in the suspect areas identified for augmented

examinations. Provide information regarding the methods used to establish a confidence

level that no drywell shell corrosion exists in the sand-pocket areas.

 d. Unless preventive actions are taken and conditions verified that no leakage and shell

corrosion exists in the suspect areas, IWE will require continuation of UT measurements

in the augmented examination areas. Provide justification for excluding the suspect

areas from augmented examinations.

 e. Based on the results of the UT examinations performed from the accessible areas of the

drywells, BFN asserted that the condition of the drywell shells is good. Provide a

discussion of BFN’s criteria for judging that the condition of the drywell steel liner plate is

good and the rationale for the criteria.

 f. Provide a discussion of any degradation observed and/or repair work implemented as a

result of past general visual inspection of the moisture barrier located at the junction of

the steel drywell and the concrete floor.

In its response, by letter dated January, 31, 2005, the applicant stated:

 a. See response to item "b."

 b. A postulated failure of the drywell-to-reactor building refueling seal can result in water

intrusion into the annulus space around the drywell. This leakage can occur only during

refueling outages when the reactor cavity is flooded to allow movement of fuel between

the reactor and the fuel pool. However, water intrusion does not cause failure of the

drywell’s intended function. Any water leakage resulting from a postulated failure of the

drywell-to-reactor building refueling seal could not remain suspended in the annulus

region for an indefinite period of time and would eventually be routed to the sandpocket
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area drains or would evaporate due to the heat generated in the drywell during

operation. In TVA’s response to NRC Generic Letter 87-05 dated August 30, 1988,

which addressed the potential for corrosion of boiling water reactor (BWR) Mark I steel

drywells in the "sand pocket region," TVA provided the NRC with the results of the

ultrasonic testing for corrosion degradation of drywell liner plate. The results of the

ultrasonic testing states: Each unit's drywell was ultrasonically tested near the sand

cushion area during 1987. The results from these tests showed that the nominal

thickness was maintained on each drywell. Below are the results of each unit’s drywell

ultrasonic testing:

 • Unit 1 - No reading below the nominal thickness of one inch was measured

indicating that the integrity of the drywell liner plate is maintained. Periodic

leakage from the sand cushion area has been observed. Corrosive species in

the drainage are bases to suspect a higher rate of corrosion on Unit 1 drywell

liner plate than on Unit 2 and 3. However, objective evidence of serious

corrosion damage was not noted.

 • Unit 2 - No reading below the nominal thickness of one inch was measured

indicating that no damage to the integrity of the drywell liner plate has occurred.

 • Unit 3 - No reading below the nominal thickness of one inch was measured

indicating that no damage to the integrity of the drywell liner plate has occurred.

 c. In response to NRC Generic Letter 87-05, TVA provided the NRC with the results of the

ultrasonic testing for corrosion degradation of BFN Units 1, 2, and 3 drywell liner plates

near the sand cushion area during 1987. The results from these tests showed that the

nominal thickness was maintained on each drywell. Paragraph IWE-1242 of ASME

Section XI requires the Owner to determine containment surface areas requiring

augmented examination, in accordance with Paragraph IWE-1241. UT thickness

measurements of this area were obtained during the U2C10 and U3C8 refueling

outages for Units 2 and 3 respectively and in 1999 and 2002 for Unit 1 (0-TI-376

Appendix 9.7 page 4). The data indicate that the condition of the drywell steel liner plate

in this area meets code requirements, and that this area should not be categorized for

augmented examination.

 d. See response to Item c.

 e. See response to Item c.

 f. The internal drywell steel containment vessel (SCV) embedment zone is subject to

corrosion if the drywell floor-to containment vessel moisture barrier fails, allowing

moisture intrusion, or if the concrete floor of the drywell cracks, allowing moisture

seepage through to the steel liner. During the Unit 2 Cycle 9 outage, a portion of the

moisture barrier was replaced (Problem Evaluation Report (PER) BFPER971516).

Engineering personnel performed an examination of the exposed drywell SCV area

below the moisture seal. This inspection indicated some minor pitting and localized rust,

but nothing approximating a challenge to nominal wall thickness. No propagation of iron

oxide to the concrete surface was noted, which would be indicative of steel containment

vessel corrosion below the concrete. Inspections conducted by the Containment ISI

Program during Unit 2 Cycle 10 refueling outage and Unit 3 Cycle 9 refueling outage

also identified some damaged areas of the moisture barrier (gaps, cracks, low

areas/spots, or other surface irregularities) that were evaluated by engineering and
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replaced or repaired. (PER 99-005254-000 for Unit 2 Drywell moisture seal barrier and

PER 00-004163-000 for Unit 3 Drywell moisture seal barrier).

In Unit 1, the moisture barrier in areas that would be made inaccessible due to ductwork

installation have been replaced. Visual examination of exposed drywell SCV area below

the moisture barrier identified some minor pitting. Ultrasonic thickness and pit depth

measurements were taken and evaluated by engineering which confirmed nominal wall

thickness was not encroached. The entire Unit 1 moisture barrier will be replaced before

restart. 

The Structures Monitoring Program also monitors the concrete to ensure that it is free of

penetrating cracks that provide a path for water seepage to the surface of the

containment shell. Research of plant history did not reveal any instances of water spills

and water ponding on the containment concrete floor. A general visual inspection of the

moisture barrier at the junction of the steel drywell shell and the concrete floor is

performed once each inspection interval in accordance with the ASME Section XI,

Subsection IWE aging management program.

Based on the responses, the staff understood that for each unit the applicant has taken actions

to monitor corrosion of the outside surface of the drywell shell and the inside surface at the

junction of the concrete floor and the drywell shell. However, the extent of monitoring the

parameters associated with the degradation and the root cause(s) of the corrosion problems

are not clear.

The response to RAI 3.5-4 emphasizes that the existing degradation of the drywell shells

(inside and outside) has not reached the minimum required thickness of one inch. However, the

response does not address a number of parameters that are pertinent to the period of extended

operation. In a follow-up to RAI 3.5-4, dated April 5, 2005, the applicant was requested to

provide (1) a description of the type of degradation (e.g, a cluster of pits or general corrosion),

(2) a description of preventive actions (e.g. stopping the leaks from the refueling cavity seals or

monitoring of sand drains), (3) a description of corrective actions (repairing/cleaning and

recoating degraded areas), (4) a description of the extent of degradation, and (5) when

IWE-1240 requirement for augmented inspection will be implemented. 

In its letter dated May 31, 2005, the applicant stated that during each refueling outage since the

mid-1980s, a visual inspection of the interior surface of the drywell, and the interior and exterior

surface of the drywell head and torus (suppression chamber) was performed to verify structural

integrity. These inspections are performed per SI 0-SI-4.7.A.2.K, “Primary Containment Drywell

Surface Visual Inspection,” and BFN Technical Instruction 0-TI-417, “Inspection of Service

Level I, II, III Protective Coatings.” SI 0-SI-4.7.A.2.K originally included the exam requirements

for the visual inspections of the protective coatings but was revised in March 2001 to remove

those requirements and add the reference to BFN Technical Instruction 0-TI-417 for coating

inspections. BFN Technical Instruction 0-TI-417 was written to incorporate the information for

performing visual inspections of Service Level I protective coatings (design-basis accident

(DBA) and non-DBA qualified). This procedure was implemented in March 2001. The scope of

SI 0-SI-4.7.A.2.K, as defined in the procedure, is as follows: 

 (1) Includes provisions for the visual verification of the structural components of the drywell,

drywell head, torus (suppression chamber), and the exterior surfaces of the drywell head
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and torus (suppression chamber) (i.e., piping, connections, structural supports,

penetrations, platform steel, duct supports, concrete walls, and steel shell) by visually

inspecting for deterioration and/or structural damage.

 (2) Provides visual inspection of the moisture seal barrier located on drywell elevation 550

feet.

 (3) Provides for visual inspection of the interior surfaces of the drywell and torus

(suppression chamber) above the level one foot below the normal water line and exterior

surface of the torus (suppression chamber) below the water line each operating cycle for

deterioration and any signs of structural damage with particular attention to piping

connections and supports and for signs of distress or displacement. In its response, the

applicant provided the results of the earlier inspections of the drywell internal

components for each unit.

Based on the detailed response, the staff found that the applicant has in place detailed

procedures for examining the concrete and steel components inside the drywell, and systematic

acceptance criteria. The applicant plans to continue this process during the extended period of

operation. Therefore, the staff found the applicant’s process of detecting degradation of these

components adequate and acceptable, and the staff’s concern described in RAI 3.5-4 is

resolved.

In RAI 3.5-5, dated December 10, 2004, the staff stated that a number of load-bearing

reinforced concrete structures within the drywell shell were subjected to temperatures higher

than the established threshold of 150 °F, as discussed in LRA Section 3.5.2.2.2.1. The

effectiveness of the closed cooling ventilation system is paramount in preventing large

temperature excursions in the drywells. Therefore, the staff requested that the applicant provide

the following information related to the concrete structures within the drywells of each unit. 

 a. Provide a summary of the operating experience related to the reliability of the closed

cooling ventilation system.

 b. Provide a summary of the results of the last inspections performed on (1) reactor

pressure vessel (RPV) pedestal supports, (2) the foundation and floor slab, and (3) the

sacrificial shield wall under the existing Structural Monitoring Program.

 c. LRA Section 3.5.2.2.2.1, Item 8, states that the main steam tunnels in the reactor

building at Units 1, 2, and 3 have a maximum normal space ambient temperature of

160 °F. Provide a discussion, including a summary of the results of the engineering

analysis performed, to support the conclusion that the conditions identified in the GALL

Report are satisfied and that aging management of reduction of strength and modulus

due to elevated temperature for the affected concrete components is not required.

In its response, by letter dated January 31, 2005, the applicant stated:

Note that LRA Section 3.5.2.2.2.1, Item 8 states in part: "The upper elevations of the

sacrificial shield wall may exceed 150 °F briefly and infrequently, during abnormal

operations and is not considered to affect its function.” The upper elevation of the

sacrificial shield wall inside the drywell shell is not a load bearing reinforced concrete

structure.
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 a. The drywell closed cooling ventilation system is a non-safety related system and

not in scope for License Renewal. This function is not required for Safe

Shutdown of the plant. If this cooling system function is lost, operator action will

be required when the Technical Specifications for drywell temperature limits

exceeds 150 °F.

 b. A review of Browns Ferry Structures Monitoring Baseline inspection and the

results for the first Structures Monitoring inspection period did not reveal any loss

of intended function due to aging effects of the RPV pedestal supports, the

foundation and floor slab, and the sacrificial shield wall. 

 c. Appendix A of ACI 349-85 specifies that the concrete temperature limits for

normal operation or any other long term period shall not exceed 150 °F except

for local areas, which are allowed to have increased temperatures not to exceed

200 °F. With the exception of the main steam tunnels in the Reactor Building,

BFN reinforced concrete structures have general area temperatures less than

150 oF during normal operation. The general area temperatures have been

conservatively evaluated using maximum normal space ambient temperatures

noted on the Harsh Environmental drawing series and associated calculations.

The Unit 1, 2, and 3 main steam tunnels at BFN have a maximum normal space

ambient temperature of 160 oF as noted in the Harsh Environmental drawing

series and associated calculations. Note however, that this is a maximum normal

space ambient temperature. The TVA Harsh Environmental drawing series and

associated calculations identify the average normal space ambient temperature

as 135 oF. This is judged to be acceptable because when concrete is subjected

to prolonged exposure to elevated temperatures, reductions in excess of 10

percent of the compressive strength, tensile strength, and the modulus of

elasticity only begin to occur in the range of 180 oF to 200 oF. (Reference EPRI

TR-103842, July 1994). 

Therefore, the conditions identified in NUREG-1801 are satisfied and aging

management of reduction of strength and modulus due to elevated temperature

for concrete components at BFN is not required.

The staff recognizes the temperature thresholds, and accepts the EPRI TR position. However,

at these temperatures, the concrete structures go through additional shrinkage cracking, and

spalling. The staff’s basic concern was related to the degradation of pedestals supporting the

reactor vessels and that of the seismic restraints anchored to the sacrificial shields and the

drywell. The staff expected more description regarding the concerns in response to item "b." In

this context, in a follow up letter, April 5, 2005, the applicant was requested to provide (1) the

type and extent of degradation observed in the reactor pedestals and at the seismic restraint

anchorage areas, and (2) the acceptance standards established (e.g., ACI 349-3R, ASME

Code Subsection IWE) for corrective actions. 

In its response, by letter May 24, 2005, the applicant stated that the inspection of concrete

within the drywell is conducted per BFN “Procedure Walkdown of Structures for Maintenance

Rule” (LCEI-CI-C9). This LCEI provides the basis for monitoring/inspection tasks, examination

criteria, evaluation requirements, and acceptance criteria in compliance with the Maintenance

Rule. A baseline inspection was established in 1997 and subsequent inspections are performed

on a five-year frequency. LCEI-CI-C9 Section 7.2 provides inspection guidelines, and visual
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inspections of structural conditions are used to detect degradation. Visual inspection is an

acceptable technique and is consistent with techniques identified in industry codes and

standards such as ACI 349.3R-96. Inspection checklists (LCEI-CI-C9 Attachment 1) are used to

document inspection results/defects.

LCEI-CI-C9 Section 7.3 provides guidance for evaluation of the results documented on the

inspection checklists. The acceptance criteria are defined in LCEI-CI-C9 Section 7.3 as: (1)

acceptable, (2) acceptable with deficiencies, and (3) unacceptable. The latest inspection of the

concrete of the reactor vessel support pedestal, biological or sacrificial shield wall, and other

structural concrete within the primary containment structure had been completed by 2002 for

Units 2 and 3. All concrete elements within the primary containment structure for Units 2 and 3

were found to be acceptable.

The staff found the inspection procedure used to detect deterioration of the concrete structures

inside drywell adequate and acceptable, as its continued use during the period of extended

operation will ensure the intended functions of these components. Therefore, the staff’s

concern described in RAI 3.5-5 is resolved. 

In RAI 3.5-6, dated December 10, 2004, the staff stated that LRA Table 3.5.2.26 is silent on the

AMR related to Class MC supports. ASME Section XI Subsection IWE Program takes exception

to NUREG-1801 Section XI.S3, and states that the aging effects for supports of MC

components will be managed by the Structures Monitoring Program or Chemistry Control

Program with associated One-Time Inspection Program for submerged supports during the

extended period of operation. Therefore, the staff requested that the applicant provide the

following information related to the aging management of Class MC supports:

 • Provide the results of the AMR for (1) MC component supports within the BFN

containments, (2) MC component supports outside the containments, and (3) supports

for piping penetrating through the containments and designated as MC piping (if any).

Also, summarize the program (sample size, inspection frequency, personnel

qualification, etc.) used to arrive at the AMR results.

 • Section 50.55a(g)(4) of 10 CFR requires the inservice inspections of Class MC pressure

retaining components and their integral attachments, in accordance with the

requirements of ASME Code Section XI. ASME Code Section XI Subsection IWF sets

the examination requirements for Class MC supports, other than those for the MC piping

supports. Therefore, provide justification for the exception taken in ASME Code

Section XI Subsection IWF Program regarding the aging management of Class MC

component supports.

 • Subsections IWE and IWF do not incorporate explicit requirements for inservice

inspection of supports of pipes designated as Class MC; therefore, the applicant was

requested to provide a description of a proposed AMP (could be part of the Structural

Monitoring Program), including sample size, the extent of examination, frequency of

examination, and qualification of personnel who perform and evaluate the inspection

results.

In its response, by letter dated January 31, 2005, the applicant noted that the information

requests made in RAI 3.5-6 are addressed in the responses to RAIs 2.4-2, 2.4-13(a) & (b) and

B.2.1.33, dated January 24, 2005. Finally, by letter dated May 31, 2005, the applicant agreed to
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bring the inspection and inspector qualification with regards to Class MC supports into the

scope of ASME Section XI Subsection IWF Program (see SER Section 3.0.3.2.21 for staff

evaluation of the ASME Section XI Subsection IWF Program). After comprehensively reviewing

all responses to the indicated RAIs, above, the staff concluded that the applicant had

successfully resolved all of the staff issues with regard to this and the other RAIs indicated.

The staff also reviewed the information provided in LRA Section 3.5.2.1.1 and determined that

the applicant had adequately identified applicable aging effects, and the AMPs credited for

managing the aging effects, for the primary containment structures components that are not

addressed by the GALL Report. The staff found the applicant’s AMR results for the primary

containment structures components acceptable.

3.5.2.3.2 Reactor Buildings – Summary of Aging Management Evaluation – Table 3.5.2.2

The staff reviewed LRA Table 3.5.2.2, which summarizes the results of AMR evaluations for the

reactor buildings component groups.

During the onsite audit, the staff reviewed selected items in LRA Table 3.5.2.2, for MEAP

combinations that are not consistent with the GALL Report. The staff requested clarifications for

the following material/environment combinations and the corresponding LRA Table 2 items:

Ceramic Fiber in an Inside Air Environment - The staff requested that the applicant provide the

BFN technical basis for concluding that no aging management is required for ceramic fiber fire

barriers in an inside air environment.

The following list identifies the ceramic fiber components in an inside air environment:

 • reactor building fire barriers

 • diesel generator building fire barriers

By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that ceramic and glass fiber used to seal fire barrier penetrations do not have any applicable

aging effects requiring aging management. This is consistent with previous staff positions in

that there are no applicable aging effects for glass used in a metal fire barrier penetration. This

is also consistent with the NUREG-1769 "Safety Evaluation Report Related to License Renewal

of Peach Bottom Atomic Power Station, Units 2 and 3," dated January 31, 2003,which

concurred that insulation made of aluminum, stainless steel (mirror), calcium silicate, ceramic

fiber, or fiberglass in a sheltered environment does not have any aging effects requiring aging

management. 

The applicant further stated that a review of BFN operating history did not reveal any loss of

intended function due to aging effects for the following ceramic fiber components.

 • reactor building fire barriers

 • diesel generator building fire barriers

The staff concluded that the applicant had not credited an existing AMP (structures monitoring

and/or fire protection) that already includes fire barriers in its scope, on the basis that its AMR

did not identify any applicable aging effects. 
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Earthfill & Rock in a Buried Environment - This item indicates that the equipment supports and

foundations are earth fill (rock and sand). The staff requested that the applicant explain the

technical bases for concluding that there are no aging effects requiring management.

By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that the foundation for the condensate water storage tank (CWST) is comprised of a concrete

ring foundation with the interior portion of the ring foundation filled with crushed rock and sand.

The earthen materials (rock and sand) of the CWST foundation interior base are protected from

environmental weathering conditions by the concrete perimeter ring and CWST tank bottom.

There are no aging effects for the earthen materials of the CWST foundation interior base that

require aging management. Aging management of the CWST concrete foundation ring is

managed by the Structures Monitoring Program. Aging management of the CWST bottom will

be performed by the One-Time Inspection Program. 

The applicant also stated that a review of BFN operating history did not reveal any loss of

intended function due to aging effects for earthen materials of the CWST foundation interior

base. 

Based on the additional information provided by the applicant, the staff concurred with the

applicant’s AMR results for the crushed rock and sand base of the CWST. The staff concluded

that aging management is not required because these materials are adequately protected by

the concrete perimeter ring and the CWST tank bottom.

Elastomers in an Embedded/Encased Environment - The staff requested the applicant to clarify

whether the compressible joints and seals that are embedded/encased in concrete are

accessible for monitoring. If not, the staff requested the applicant to explain how the Structures

Monitoring Program is utilized to manage aging effects in inaccessible areas.

By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that LRA Table 3.5.2.2, rows 4 and 5, apply to the seal around the reactor building access

doors. Row 4 applies to the portion of the seal that is embedded/encased, and row 5 applies to

the portion of the seal that is exposed to the inside air environment of the reactor building. An

embedded/encased environment will minimize aging effects due to elastomer degradation

caused by inside air environment (ambient conditions of ultraviolet radiation, ozone,

temperature, etc.). The Structures Monitoring Program will periodically inspect the portion of the

seal that is exposed to the inside air environment of the reactor building for aging effects due to

elastomer degradation. The condition of the exposed portion of the seal will provide an

indication of the condition of the embedded/encased portion of the seal. The inaccessible

portions of the embedded/encased seal for the reactor building access door will be monitored

with the periodic inspections of the seal that are exposed to the air environment of the reactor

building.

Based on the additional information provided by the applicant, the staff finds the applicant’s

AMR results for the embedded/encased portion of the seal around the reactor building access

doors to be acceptable. The condition of the exposed portion of the seal will be periodically

inspected by the Structures Monitoring Program, which will provide an indication of the

condition of the embedded/encased portion of the seal. 
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Stainless Steel in an Embedded/Encased Environment – All metals embedded/encased in

concrete are inaccessible; however, they could be susceptible to aging degradation. The staff

requested that the applicant provide an AMR to further evaluate embedded/encased

components if aging of components in accessible areas is identified that may indicate aging of

the inaccessible components.

The following list identifies stainless steel components that are embedded/encased:

 • mechanical penetrations

 • spent fuel pool liners

By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that the BFN concrete structures and concrete components are designed in accordance with

ACI 318-63 and 71 and constructed using ingredients conforming to ACI and ASTM standards,

which provide for a good quality, dense, well-cured, and low permeability concrete. Cracking is

controlled through proper arrangement and distribution of reinforcing bars. Concrete structures

and concrete components are constructed of a dense, well-cured concrete with an amount of

cement suitable for strength development, and achievement of a water-to-cement ratio that is

characteristic of concrete having low permeability. This is consistent with the recommendations

and guidance provided by ACI 201.2R-77.

The applicant also stated that the AMR for the material and environment combination of

stainless steel in an embedded/encased environment was performed and concluded that no

aging mechanism was identified that requires management. The applicant noted that the

submerged surfaces of spent fuel pool liners are managed by the Chemistry Control Program

and monitoring of the spent fuel pool level is managed by plant operations.

The applicant further stated that a review of BFN operating history did not reveal any loss of

intended function due to aging effects for stainless steel mechanical penetrations or spent fuel

pool liners that are embedded/encased in concrete. 

The staff found that the applicant had identified an appropriate course of action to manage

aging of stainless steel submerged surfaces of spent fuel pool liners because it is consistent

with the guidance in the GALL Report. For other stainless steel structural components

embedded/encased in concrete, the staff accepted the applicant’s AMR results that aging

management is not required, because stainless steel structural components in general are not

susceptible to degradation, and concrete provides protection for embedded/encased steel. 

The staff’s review of LRA Table 3.5.2.2 identified areas in which additional information was

necessary to complete the review of the applicant’s results. The applicant responded to the

staff’s RAIs as discussed below. 

In RAI 3.5-7, dated December 10, 2004, the staff stated that the buried environment item in

LRA Table 3.0.2 states that ground water is non-aggressive. Therefore, the staff requested that

the applicant provide historical site ground water chemistry test results together with a

discussion of the extent of past ground water sampling and testing frequency, as well as the

extent of fluctuation of the test results to support the above assertion.
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In its response, by letter dated January 31, 2005, the applicant stated:

Since BFN did not have data available from the construction period or since plant

start-up, baseline sampling was performed over the past year of groundwater and the

Wheeler Reservoir. The baseline sampling was to establish if BFN had aggressive or

non-aggressive water as defined by the following criteria: pH <5.5, Chlorides > 500 ppm

and Sulfates > 1500 ppm. The samples were taken at intervals to take into

consideration seasonal variations. The samples were taken from the existing site

radiological monitoring wells and from the Wheeler Reservoir in close proximity to the

Intake Pumping Station structure. Samples were taken at various depths in the

monitoring well and the Reservoir by the site environment staff and analyzed by an

off-site laboratory for the site environment group. Results of Browns Ferry groundwater

and Wheeler Reservoir water sampling are as follows:

 a. Groundwater:

 • pH ranges from 6.33 to 8.77 which are well above <5.5 (Note in the well

that the value 6.33 was obtained, the remaining pH readings ranged from

7.16 to 7.60 during the time period of sampling. Only one other well had a

pH value below 7 and its pH was 6.92 with the remaining readings

ranging between 7.12 and 7.6)

 • Chlorides – maximum reading of 18.3 ppm which is well below the

threshold of 500 ppm

 • Sulfates–maximum reading of 30.3 ppm which is well below the threshold

of 1500 ppm

 b. Wheeler Reservoir:

 • pH ranges from 7.28 to 8.64 which are well above < 5.5

 • Chlorides – maximum reading of 13.9 ppm which is well below the

threshold of 500 ppm

 • Sulfates – maximum reading of 15.5 ppm which is well below the

threshold of 1500 ppm

Browns Ferry groundwater and Wheeler Reservoir sample measurements have

confirmed that parameters are well below threshold limits that could cause concrete

degradation (i.e., an aggressive environment does not exist).

Based on the above test data, the staff found that both the Browns Ferry groundwater and the

Wheeler Reservoir water are non-aggressive. Therefore, the staff’s concern described in

RAI 3.5-7 is resolved.

In RAI 3.5-8, dated December 10, 2004, the staff stated that the AMR discussion provided in

LRA Section 3.5.2.2.2.2 is rather general and brief, and requires more detailed elaboration to

support BFN’s conclusion that the conditions identified in the GALL Report, as revised by

ISG-03, are satisfied and no aging management for below-grade inaccessible concrete is

needed. Therefore, the staff requested that the applicant provide additional specific information,

including: (1) concrete quality and test data for inaccessible concrete, (2) past operating

experience regarding exposure of inaccessible concrete to aggressive chemical/fluid
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environment, and (3) past inaccessible concrete inspection findings and data related to

concrete degradation and repairs.

In its response, by letter dated January 31, 2005, the applicant stated:

 (1) The BFN concrete structures and concrete components are designed in accordance

with ACI 318-63 and 71 and constructed using ingredients conforming to ACI and ASTM

standards, which provide for a good quality, dense, well cured, and low permeability

concrete. Cracking is controlled through proper arrangement and distribution of

reinforcing bars. Concrete structures and concrete components are constructed of a

dense, well-cured concrete with an amount of cement suitable for strength development,

and achievement of a water-to-cement ratio that is characteristic of concrete having low

permeability. This is consistent with the recommendations and guidance provided by

ACI 201.2R-77. 

 (2) As noted in the response to RAI 3.5-7, Browns Ferry groundwater water and Wheeler

Reservoir sample measurements have confirmed that parameters are well below

threshold limits that could cause concrete degradation (an aggressive environment does

not exist).

 (3) A review of Browns Ferry operating history, the Browns Ferry Structures Monitoring

Baseline inspection, and the results for the first Structures Monitoring inspection period

did not reveal any loss of intended function due to aging effects when below-grade

inaccessible concrete was excavated for other reasons.

Based on the plant-specific operating experience reported in item 3 and the fact that the

applicant complied with applicable provisions of the GALL Report, the staff found the applicant’s

response acceptable, and the staff’s concern described in RAI 3.5-8 is resolved.

In RAI 3.5-9, dated December 10, 2004, the staff stated that in LRA Table 3.5.2.2, no AERM

and AMPs are identified for hatches/plugs, and electrical and instrumentation and control (I&C)

penetrations made of carbon and low-alloy steel that are embedded or encased in concrete;

whereas, GALL Report Item III.A2.2-a calls for a Structures Monitoring Program to manage the

loss of material and corrosion aging effects for steel components exposed to various

environments. Additionally, the mechanical penetrations listed in Table 3.5.2.2 and the

structural steel beams, columns, plates, and trusses that are embedded or encased in concrete

are also identified as having no applicable aging effect that requires aging management;

therefore, no AMP is designated for the components. This same BFN position is shown

throughout the remainder of LRA Table 3.5.2.2. Therefore, the staff requested the applicant to

discuss past operating experience and inspection results related to aging degradation of

embedded or encased hatches, plugs, duct banks, manholes, mechanical penetrations, and

electrical and I&C penetrations in order to provide an operating experience-based rationale to

justify its assertion that these components require no AMP to manage their aging.

In its response, by letter dated January 31, 2005, the applicant stated:

The BFN concrete structures and concrete components are designed in accordance

with ACI 318-63 and 71 and constructed using materials conforming to ACI and ASTM

standards, which provide for a good quality, dense, well cured, and low permeability
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concrete. Cracking is controlled through proper arrangement and distribution of

reinforcing bars. 

Concrete structures and concrete components are constructed of a dense, well-cured

concrete with an amount of cement suitable for strength development, and achievement

of a water-to-cement ratio that is characteristic of concrete having low permeability. This

is consistent with the recommendations and guidance provided by ACI 201.2R-77. As a

minimum, all exposed portions of embedded carbon steel structural components are

inspected for the following aging effects:

 • Outside Air Environments: Loss of material due to general and pitting corrosion 

 • Inside Air Environments: Loss of material due to general corrosion 

 • Containment Air Environments: Loss of material due to general corrosion

A review of Browns Ferry operating history, the Browns Ferry Structures Monitoring

Baseline inspection, and the results for the first Structures Monitoring inspection period

did not reveal any loss of intended function due to aging effects for carbon steel

components embedded/encased in concrete.

Based on the above plant-specific operating experience and the fact that concrete structures

and concrete components are designed in accordance with ACI 318-63 and 71 and constructed

using materials conforming to ACI and ASTM standards, which provide for a good quality,

dense, well-cured, and low permeability concrete, the staff found that the applicant had

adequately justified its AMR results regarding the concrete elements listed in LRA

Table 3.5.2.2. Therefore, the staff’s concern described in RAI 3.5-9 is resolved.

In RAI 3.5-10, dated December 10, 2004, the staff noted that non-ferrous aluminum electrical

and I&C penetrations embedded or encased in concrete are listed in the second item of LRA

Table 3.5.2.2 as components requiring no AMP to manage any aging effect. Therefore, the

staff requested the applicant to provide a discussion of past and applicable industry operating

experience to justify this AMR finding. Additionally, referring to embedded or encased stainless

steel spent fuel pool liners listed in LRA Table 3.5.2.2, the applicant was requested to discuss

applicable operating experience of these liners to justify its AMR results that no AMP is needed

to manage any aging effect.

In its response, by letter dated January 31, 2005, the applicant stated:

The BFN concrete structures and concrete components are designed in accordance

with ACI 318-63 and 71 and constructed using materials conforming to ACI and ASTM

standards, which provide for a good quality, dense, well cured, and low permeability

concrete. Cracking is controlled through proper arrangement and distribution of

reinforcing bars. 

Concrete structures and concrete components are constructed of a dense, well-cured

concrete with an amount of cement suitable for strength development, and achievement

of a water-to-cement ratio that is characteristic of concrete having low permeability. This

is consistent with the recommendations and guidance provided by ACI 201.2R-77. 

Embedded or Encased Aluminum Response: Aluminum is a reactive metal, but it

develops an aluminum oxide film that protects it from further corrosion in an indoor
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environment. The specific aluminum alloy (6063-T42) used at BFN for conduit and

raceways is resistant to general corrosion, pitting, and SCC during testing in outdoor,

and saltwater environments. For the aluminum that is embedded/encased within the

concrete, corrosion is not considered an applicable aging mechanism. The concrete

must first be degraded by other aging mechanisms, which reduce the protective cover

and potentially allow for the intrusion of aggressive ions causing a reduction in concrete

pH. Aging management of concrete aging effects will manage the corrosion of the

embedded/encased aluminum’s concrete protective cover. A review of Browns Ferry

operating history, the Browns Ferry Structures Monitoring Baseline inspection, and the

results for the first Structures Monitoring inspection period did not reveal any loss of

intended function due to aging effects for aluminum components embedded/encased in

concrete.

Embedded or Encased Stainless Steel Response: For the stainless steel that is

embedded/encased within the concrete, corrosion is similarly not considered an

applicable aging mechanism. The concrete must first be degraded by other aging

mechanisms, which reduce the protective cover and allow for the intrusion of aggressive

ions causing a reduction in concrete pH. Adequate management of other concrete aging

effects will in effect manage the aging of the embedded/encased stainless steel. After a

review of the Browns Ferry operating history, the Browns Ferry Structures Monitoring

Baseline inspection, and the results for the first Structures Monitoring inspection period

did not reveal any loss of intended function due to aging effects for stainless steel that is

embedded/encased within concrete. Operating history did show a small leak in the

Unit 1 fuel pool liner. The Unit 1 fuel pool has remained in service during the extended

outage since spent fuel is stored in the pool. This leak in the Unit 1 fuel pool was

documented in accordance with the site’s Corrective Action Program, SPP-3.1,

Tennessee Valley Authority Nuclear (TVAN) Standard Program and Processes,

“Corrective Action Program” as PER 00- 011982-000 (electronic corrective action

program number 35486. This leak is contained within the leak channel beneath the fuel

pool liner). The fuel pool liners are monitored on a monthly basis per operation

instruction 1-OI-78. The leak is small (~0.06 gpm) and has been steady over time

without an increasing trend over the last ten years.

The staff found the above applicant’s justification reasonable and adequate because it was

supported by the fact that the operating history, structures monitoring baseline inspection, and

results from the first structures monitoring inspection period did not reveal any loss of intended

function due to aging effects for aluminum and stainless steel embedded or encased within

concrete. Therefore, the staff’s concerns described in RAI 3.5-10 are resolved.

In RAI 3.5-14, dated December 10, 2004, the staff stated that, with respect to the

neutron-absorbing sheets in spent fuel storage racks, as described in LRA Section 3.3.2.2, the

applicant stated that the Chemistry Control Program manages general corrosion and that an

inspection of Boral coupon test specimens was performed at BFN that confirmed that no

significant aging degradation had occurred and that the neutron-absorbing capacity of the Boral

had not been reduced. Since it is implied that some Boral aging degradations had occurred at

the time of inspection of the test specimens, the staff requested the applicant to discuss the

basis for the above assertion that the neutron-absorbing capacity of the Boral will be maintained

at an adequate level during the extended period of plant operation.
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In its response, by letter dated January 31, 2005, the applicant stated:

A total of 16 boral coupons were placed in the Unit 3 spent fuel storage pool (SFSP) in

October 1983. The coupons supplied by the rack manufacturer are of the same

metallurgical condition as the high density fuel storage racks (HDFSR) in thickness,

chemistry, finish, and temper. For the first six years of the planned fifteen year

surveillance program, examination was to have taken place at two-year intervals.

Accordingly, two coupons were removed in October 1985. Blisters were found upon

examination, and because of this unexpected anomaly, three additional coupons were

analyzed not finding any blisters. As a result of blisters found on the coupons removed

in 1985, the surveillance program has been expanded to include monitoring the

formation and behavior of these blisters. These boral coupons are periodically removed

from the fuel pool for testing and are evaluated for corrosion or other degradation of the

neutron absorber plates by comparing various physical characteristics of the test

coupons to baseline measurements taken when the coupons were installed. Also, a

metallurgical engineer examines the coupons for general corrosion, local pitting, and

bonding. No further blisters, corrosion, or degradation has been identified in coupons

evaluated through 2003.

The above response states that these Boral coupons are periodically removed from the fuel

pool for testing and are evaluated for corrosion or other degradation of the neutron absorber

plates by comparing various physical characteristics of the test coupons to baseline

measurements taken when the coupons were installed. The response also implies that a

metallurgical engineer periodically examines the coupons for general corrosion, local pitting,

and bonding. Also, no further blisters, corrosion, or degradation have been identified in coupons

evaluated through 2003; however, it was not clear to the staff whether these periodic

inspections are ongoing activities that are an extension of the 1983 Boral Coupon Inspection

Program covering Boral coupon test specimens or a separate AMP in addition to the Chemistry

Control Program mentioned above. The applicant was requested to clarify the key parameters

of this periodic inspection program or activity including the objective, scope, frequency, and

inspection approach of the program.

In its response, by letter May 24, 2005, the applicant stated that:

The Boral coupon inspection program was initiated in 1983 to implement the inspection

and testing requirements of UFSAR Section 10.3.6; this checks the long-term behavior

of the material of the high density spent fuel racks. The inspection is performed per BFN

Technical Instruction (TI) TI-116, “High Density Fuel Storage System Surveillance

Program.” When the TI is performed, Boral coupons are removed from the spent fuel

storage pool and examined by the Metallurgical Engineer in their original condition to

determine if sampling of surface corrosion products is appropriate. Thickness

measurements are obtained of each coupon and documented in accordance with the TI.

If degradation is such that further investigation is warranted, a minimum of one coupon

is selected to be unsheathed or opened. Prior to the unsheathing process, a dye

penetrant test for indications on the outer surfaces of the coupon will be performed and

is examined by the Metallurgical Engineer. The Metallurgical Engineer decides if further

unsheathing of the coupons is required. The visual examination by the Metallurgical

Engineer is documented on the appropriate forms of the TI. The current frequency for
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performing this TI is two years. The surveillance frequency is re-evaluated each time the

surveillance is performed and can be changed based on the trend of the historical data

results. The inspection of the Boral coupons will continue until such time as the trend of

the historical data results collected provides a basis to discontinue the inspections.

Based on its review, the staff found the applicant’s response to RAI 3.5-14 acceptable.

Therefore, the staff’s concern described in RAI 3.5-14 is resolved.

In RAI 4.7.4-1, dated December 10, 2004, LRA Table 3.5.2.2 lists the AMR results of expansion

joint (elastomer, polyurethane foam) as a TLAA and refers the TLAA to LRA Section 4.7. LRA

Section 4.7.4, "Radiation Degradation of Drywell Expansion Gap Foam," states that an analysis

of the effect of dose on the foam showed the material properties will remain within the limits

assumed by the original design analysis for the additional 20 years of extended operation.

Therefore, the staff requested the applicant to provide a more detailed discussion of the

analysis including a discussion of the assumptions adopted in the analysis, the type of data

extrapolation applied, and the quantitative results obtained to justify the assertion that the

requirements of 10 CFR 54.21(c)(1)(i) are fully met.

By letter dated January 31, 2005, the applicant provided its response to RAI 4.7.4-1. The staff

evaluation of the applicant’s response is provided in SER Section 4.7.4.

In RAI 3.5-17, dated March 25, 2005, the staff stated that LRA Table 3.5.2.29, Radwaste

Building, has three separate rows of component type listings (i.e., reinforced concrete, beams,

column, walls, and slabs) which make references to note I,1 (last column of the table) and are

shown to be associated with NUREG-1801 Section III.A3.1-h, Volume 2. Note I,1 of the table

implies that the radwaste building is founded on rock or bearing piles. The note also refers to

LRA Section 3.5.2.2.2.1 for further evaluation. Item 5 of the section does not clearly indicate

that the radwaste building is founded on rock or bearing piles. Therefore, the staff requested

that the applicant provide the type of foundation medium that supports the building; and if the

structure is not founded on rock or piles, to discuss the basis for asserting that the cracking,

distortion, and increase in component stress level due to settlement are not aging effects

requiring management. The applicant was also asked, as appropriate, to revise LRA

Sections 3.5.2.1 and 3.5.2.2.2.1 to include the radwaste building within the scope of its

discussion.

In its response, by letter April 14, 2005, the applicant stated:

The Radwaste Building is founded on piles as noted by the entry under “Component

Type” - “Piles” in Table 2.4.7.8.

LRA Section 3.5.2.2.2.1, Item 5, paragraph 1 on page 3.5-43 should be revised to read:

“Cracks, distortion, increase in component stress level due to settlement are not

considered as aging effects requiring management for BFN structures founded

on rock or bearing piles. The following BFN structures are founded on rock or

bearing piles: Reactor Buildings, Primary Containments, Intake Pumping Station,

Reinforced Concrete Chimney, Off-Gas Treatment Building, Equipment Access

Lock, Turbine Buildings, Gate Structure Number 3, Diesel HPFP House,

Transformer Yard, RHRSW Tunnel and Radwaste Building. Based on industry
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experience, settlement of Class 1 structures founded on bedrock or bearing piles

have not been noted to cause aging effects requiring management.” 

Based on its review, the staff found the applicant’s response to RAI 3.5-17 acceptable.

Therefore, the staff’s concern described in RAI 3.5-17 is resolved.

In RAI 3.5-18, dated March 25, 2005, the staff stated that in its review of LRA Table 3.5.2.30, it

was not clear as to whether the Group 5 category referred to includes the service building.

Therefore, the staff requested that the applicant confirm that the service building, or portion of

the service building, is clearly included within the scope addressed by LRA Section 3.5.2.2.2.1

and make any necessary revision to the LRA section to clarify its position. 

In its response, by letter dated April 14, 2005, the applicant stated:

The aging management review of the Service Building was performed to the

requirements for Group 3 Structures of NUREG-1801, Vol. 2, Chapter III.A3. The

Service Building is included within the scope addressed by LRA Section 3.5.2.2.2.1,

Item 8 since it was considered as a Group 3 Structure and that section is applicable to

Group 1 through Group 5 Structures of NUREG-1801, Vol. 2 Chapter 3.

The staff found the above response acceptable. Therefore, the staff’s concern described in

RAI 3.5-18 is resolved. 

The staff also reviewed the information provided in LRA Section 3.5.2.1.2 and determined that

the applicant had adequately identified applicable aging effects, and the AMPs credited for

managing the aging effects, for the reactor buildings’ components that are not addressed by the

GALL Report. The staff found the applicant’s AMR results for the service building components

acceptable.

3.5.2.3.3 Equipment Access Lock – Summary of Aging Management Evaluation –

Table 3.5.2.3

The staff reviewed LRA Table 3.5.2.3, which summarizes the results of AMR evaluations for the

equipment access lock component groups.

The staff also reviewed the information provided in LRA Section 3.5.2.1.3 and determined that

the applicant had adequately identified applicable aging effects, and the AMPs credited for

managing the aging effects, for the equipment access lock components that are not addressed

by the GALL Report. The staff found the applicant’s AMR results for the equipment access lock

components acceptable.

3.5.2.3.4 Earth Berm – Summary of Aging Management Evaluation – Table 3.5.2.4

The staff reviewed LRA Table 3.5.2.4, which summarizes the results of AMR evaluations for the

earth berm component groups.

The staff also reviewed the information provided in LRA Section 3.5.2.1.4 and determined that

the applicant had adequately identified applicable aging effects, and the AMPs credited for

managing the aging effects, for the earth berm components that are not addressed by the
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GALL Report. The staff found the applicant’s AMR results for the earth berm components

acceptable.

3.5.2.3.5 Diesel Generator Buildings – Summary of Aging Management Evaluation –

Table 3.5.2.5

The staff reviewed LRA Table 3.5.2.5, which summarizes the results of AMR evaluations for the

diesel generator buildings component groups.

During the onsite audit, the staff reviewed selected items in LRA Table 3.5.2.25, for MEAP

combinations that are not consistent with the GALL Report. The staff requested clarifications for

the following material/environment combinations and the corresponding LRA Table 2 items:

Ceramic Fiber in an Inside Air Environment - The staff requested that the applicant provide the

BFN technical basis for concluding that no aging management is required for ceramic fiber fire

barriers in an inside air environment.

The following list identifies ceramic fiber components in an inside air environment:

 • reactor building fire barriers

 • diesel generator building fire barriers

By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that ceramic and glass fiber used to seal fire barrier penetrations do not have any applicable

aging effects requiring aging management. This is consistent with previous staff positions in

LRA SER concurrences that there are no applicable aging effects for glass used in a metal fire

barrier penetration. This is also consistent with the NUREG-1769 SER related to the license

renewal of another plant which concurred that insulation made of aluminum, stainless steel

(mirror), calcium silicate, ceramic fiber, or fiberglass in a sheltered environment does not have

any aging effects requiring aging management. 

The applicant further stated that a review of BFN operating history did not reveal any loss of

intended function due to aging effects for the following ceramic fiber components.

 • reactor building fire barriers

 • diesel generator building fire barriers

The staff concluded that the applicant had not credited an existing AMP (structures monitoring

and/or fire protection) that already included fire barriers in its scope on the basis that its AMR

did not identify any applicable aging effects.

The staff’s review of LRA Table 3.5.2.5 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.
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In RAI 3.5-11, dated December 10, 2004, the staff stated that, with respect to the fire barriers

consisting of ceramic fiber listed in LRA Table 3.5.2.5, the applicant’s AMR identified neither

AERM nor AMP for the ceramic fiber fire barriers. Therefore, the staff requested that the

applicant discuss past plant-specific inspection results of these fire barriers in order to provide

an operating experience-based justification for the above AMR finding.

In its response, by letter dated January 31, 2005, the applicant stated:

This same RAI was asked as RAI 3.3-2 for the Reactor Building. In the response to that

RAI, the same material was also addressed for the Diesel Generator Building

(Table 3.5.2.5, item number 10 on page 3.5-74). Refer to the TVA response to RAI 3.3-2

(TVA letter to NRC dated September 30, 2004).

The staff found the response to RAI 3.5-11 provided in SER Section 3.3 acceptable; therefore,

the staff’s concern expressed in RAI 3.5-11 is resolved.

The staff also reviewed the information provided in LRA Section 3.5.2.1.5 and determined that

the applicant had adequately identified applicable aging effects, and the AMPs credited for

managing the aging effects for the diesel generator buildings’ components that are not

addressed by the GALL Report. The staff found the applicant’s AMR results for diesel generator

buildings’ components acceptable.

3.5.2.3.6 Standby Gas Treatment Building – Summary of Aging Management Evaluation –

Table 3.5.2.6

The staff reviewed LRA Table 3.5.2.6, which summarizes the results of AMR evaluations for the

standby gas treatment building component groups.

The staff also reviewed the information provided in LRA Section 3.5.2.1.6 and determined that

the applicant had adequately identified applicable aging effects, and the AMPs credited for

managing the aging effects for the standby gas treatment building components that are not

addressed by the GALL Report. The staff found the applicant’s AMR results for the standby gas

treatment building components acceptable.

3.5.2.3.7 Off-Gas Treatment Building – Summary of Aging Management Evaluation –

Table 3.5.2.7

The staff reviewed LRA Table 3.5.2.7, which summarizes the results of AMR evaluations for the

off-gas treatment building component groups.

The staff also reviewed the information provided in LRA Section 3.5.2.1.7 and determined that

the applicant had adequately identified applicable aging effects, and the AMPs credited for

managing the aging effects for the off-gas treatment building components that are not

addressed by the GALL Report. The staff found the applicant’s AMR results for the off-gas

treatment building components acceptable.
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3.5.2.3.8 Vacuum Pipe Building – Summary of Aging Management Evaluation – Table 3.5.2.8

The staff reviewed LRA Table 3.5.2.8, which summarizes the results of AMR evaluations for the

vacuum pipe building component groups.

The staff also reviewed the information provided in LRA Section 3.5.2.1.8 and determined that

the applicant had adequately identified applicable aging effects, and the AMPs credited for

managing the aging effects for the vacuum pipe building components that are not addressed by

the GALL Report. The staff found the applicant’s AMR results for the vacuum pipe building

components acceptable.

3.5.2.3.9 Residual Heat Removal Service Water Tunnels – Summary of Aging Management

Evaluation – Table 3.5.2.9

The staff reviewed LRA Table 3.5.2.9, which summarizes the results of AMR evaluations for the

RHRSW tunnels’ component groups.

The staff also reviewed the information provided in LRA Section 3.5.2.1.9 and determined that

the applicant had adequately identified applicable aging effects, and the AMPs credited for

managing the aging effects for the RHRSW tunnel components that are not addressed by the

GALL Report. The staff found the applicant’s AMR results for the RHRSW tunnel components

acceptable.

3.5.2.3.10 Electrical Cable Tunnel from Intake Pumping Station to the Powerhouse – Summary

of Aging Management Evaluation – Table 3.5.2.10

The staff reviewed LRA Table 3.5.2.10, which summarizes the results of AMR evaluations for

the electrical cable tunnel from intake pumping station to the powerhouse component groups.

The staff also reviewed the information provided in LRA Section 3.5.2.1.10 and determined that

the applicant had adequately identified applicable aging effects, and the AMPs credited for

managing the aging effects for the electrical cable tunnel from the intake pumping station to the

powerhouse components that are not addressed by the GALL Report. The staff found the

applicant’s AMR results for the electrical cable tunnel from the intake pumping station to the

powerhouse components acceptable.

3.5.2.3.11 Underground Concrete Encased Structures – Summary of 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 underground concrete-encased structures component groups.

The staff also reviewed the information provided in LRA Section 3.5.2.1.11 and determined that

the applicant had adequately identified applicable aging effects and the AMPs credited for

managing the aging effects for the underground concrete-encased structures components that

are not addressed by the GALL Report. The staff found the applicant’s AMR results for the

underground concrete encased structures’ components acceptable.
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3.5.2.3.12 Intake Pumping Station – Summary of Aging Management Evaluation –

Table 3.5.2.12

The staff reviewed LRA Table 3.5.2.12, which summarizes the results of AMR evaluations for

the intake pumping station component groups.

In LRA Table 3.5.2.12, the applicant stated that no aging management is required for

submerged reinforced concrete. Plant-specific Note 5 states that for cracking, loss of bond, loss

of material (spalling, scaling) due to corrosion of embedded steel in concrete for inaccessible

areas, no plant-specific aging management is required. Plant-specific Note 6 states that, for

increase in porosity and permeability, cracking, loss of material (spalling, scaling) due to

aggressive chemical attack of concrete for inaccessible areas, no plant-specific aging

management is required. 

During the onsite audit, the staff reviewed other selected items in LRA Table 3.5.2.12, for

MEAP combinations that are not consistent with the GALL Report. The staff requested

clarifications for the following material/environment combinations and the corresponding LRA

Table 2 items:

Reinforced Concrete in a Submerged Environment - In LRA Table 3.5.2.12 (Intake Pumping

Station - Summary of Aging Management Evaluation), rows 37 and 38, the applicant stated that

no aging management is required for submerged reinforced concrete. Note 5 for row 37 states

that for cracking, loss of bond, loss of material (spalling, scaling) due to corrosion of embedded

steel in concrete for inaccessible areas, no plant-specific aging management is required. Note 6

for row 38 states that for increase in porosity and permeability, cracking, loss of material

(spalling, scaling) due to aggressive chemical attack of concrete for inaccessible areas, no

plant-specific aging is required. 

The staff noted that a submerged component is not necessarily inaccessible. If the submerged

component is accessible, it is expected that the component will be managed by the Inspection

of Water Control Structures Program. The staff requested that the applicant identify all the

submerged concrete components in the intake pumping station, and provide the technical basis

for designating these components as being inaccessible. The staff also requested that the

applicant identify all the submerged concrete structures that will be inspected under Water

Control Structures Program, and describe the implementing details of the inspection of

submerged structures included in the Water Control Structures Program.

By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that:

Browns Ferry groundwater water and Wheeler Reservoir water sample measurements

presented in the response to question 297 have confirmed that parameters are well

below threshold limits that could cause concrete degradation (an aggressive

environment does not exist). It is not credible to postulate that some environmental

event will occur in the future that would affect the quality of groundwater in the vicinity of

Browns Ferry. A change in the environment due to a chemical release would be

considered as an “abnormal event”. NUREG-1800, “Standard Review Plan for the

Review of License Renewal Applications for Nuclear Power Plants,” states that aging

effects from abnormal events need not be postulated specifically for license renewal.
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In-scope submerged concrete exposed to Wheeler Reservoir water is not readily

accessible for inspection. Several in-scope submerged concrete common areas outside

of individual pump bays where continuous flow make diver entry unsafe would require a

multiple unit outage to inspect. Browns Ferry will perform a one time inspection of the

in-scope submerged concrete in one individual pump bay to confirm the absence of

aggressive environmental aging effects and that a loss of intended function has not

occurred due to aggressive environment aging effects.

Browns Ferry will also continue to perform periodic inspections of accessible concrete in

an inside air environment and outside air environment for in-scope structures with the

Structures Monitoring Program.

The staff concluded that the applicant’s AMR is not consistent with the GALL Report and is not

acceptable, because there is no commitment to conduct periodic inspection of accessible,

submerged water control concrete structures. This issue was addressed in RAI 3.5-16 and is

discussed below.

In RAI 3.5-16, dated March 11, 2005, the staff requested the applicant to demonstrate that the

groundwater is not an aggressive environment, although the facts show that an aggressive

environment does not exist for groundwater, and continuous water flow in several in-scope

submerged concrete common areas outside of individual pump bays makes diver entry unsafe.

Therefore, the staff requested that the applicant provide the following additional information and

a plant-specific commitment, as needed, in order to expedite staff closure of the issue raised by

the audit team:

 (1) A discussion of past inspection findings, and repairs and maintenance experience for

submerged, reinforced concrete structures (e.g., intake structure).

 (2) A discussion of the pertinent submerged, reinforced concrete test data (as available)

which demonstrate that the conditions stated in the discussion columns of items III

A6.1-b and III A6.1-d in GALL Report, Volume II, are fully met. 

 (3) A detailed description of the one-time inspection by the applicant, cited above, of the

in-scope submerged concrete in one individual pump bay, including method of

inspection; concrete elements and parameters or types of degradation to be inspected;

criteria for judging the observed types, extent, and severity of reinforced concrete

degradation that would trigger BFN’s commitment to an AMP for submerged concrete

with a periodic inspection provision, inspection frequency, and schedule for

implementing the One-Time Inspection Program. 

 (4) A discussion of the methods (e.g., regular monitoring of the raw water for pH, chloride

concentration, sulfate concentration, abrasive particulates, detrimental organic agents)

that will be employed to ensure that the raw service water in close proximity to the intake

structure remains non-aggressive to the submerged concrete during the extended

period of operation.

In its response, by letter dated April 5, 2005, the applicant stated:

 (1) BFN’s submerged concrete operating experience: 
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A baseline inspection for the BFN Structures Monitoring Program was

established in 1997 and included the Intake Pumping Station and Gate Structure

No. 3. Baseline inspections and subsequent BFN Structures Monitoring Program

inspections included accessible interior and exterior concrete surfaces of the

Intake Pumping Station and Gate Structure No. 3. Only the Intake Pumping

Station has submerged concrete that is in the scope of license renewal. Although

the Intake Pumping Station submerged concrete was not inspected, there is

reasonable assurance that the submerged concrete results would be consistent

due to a lack of an aggressive environment and use of the same concrete

specifications for the construction as the accessible portions of the Intake

Pumping Station. 

Defect evaluations performed since the baseline inspection and subsequent

inspections are documented in the 2002 Structures Monitoring Program results.

Below is a highlight of plant-specific operating experience for concrete elements

at the Intake Pumping Station and Gate Structure No. 3. None of the identified

indications were considered significant or affected the function of the structure. 

 • Intake Pumping Station: Very minor concrete surface cracks

 • Gate Structure No. 3: Very minor concrete surface cracks and spalling

Additionally, to capture plant operating experience for these structures, work

orders (WOs), the site Correction Action Program and site Licensing Event

Reports (LERs) were reviewed for various operating periods:

 • Work Orders between 1991 and 2004 were reviewed to determine if any

corrective maintenance or repairs were performed on the Intake Pumping

Station (IPS). A total of 2633 WOs were reviewed for that period and no

work activities were found involving the submerged concrete for this

structure.

 • The site’s Correction Action Program was reviewed for the IPS to identify

any adverse conditions of the structure, with emphasis on the submerged

concrete. A total of 1790 reports were reviewed for a time period between

1994 and 2004, with none being identified for the IPS submerged

concrete.

 • Licensing Event Reports were reviewed for a period between 1985 and

2004 and none were identified affecting the IPS.

 (2) GALL conditions for III A6.1-b (increase in porosity and permeability, loss of

strength due to leaching of calcium hydroxide)& III A6.1-d (cracking, loss of

bond, loss of material (spalling, scaling) due to corrosion of embedded steel):

See further evaluations in LRA Section 3.5.2.2.2.1, item 2 and LRA

Section 3.5.2.2.2.2 for discussion on these issues.
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 (3) Submerged concrete one-time inspection:

The following elements apply to the one-time inspection for submerged concrete:

 a. Scope of One-Time Inspection: 

In-scope submerged concrete in one individual pump bay of the Intake

Pumping Station. The submerged concrete surfaces will be inspected.

 b. Preventative Measures: 

The one-time inspection specifies no preventive actions.

 c. Parameters Monitored or Inspected: 

The following concrete aging effects will be inspected during the one-time

inspection of submerged concrete at the intake pumping station (IPS).

 ! Increase in porosity and permeability, and loss of strength due to

leaching of calcium hydroxide

 ! Expansion and cracking due to reaction with aggregates

 ! Cracking, loss of bond, and loss of material (spalling, scaling) due

to corrosion of embedded steel

 ! Increase in porosity and permeability, cracking, loss of material

(spalling, scaling) due to aggressive chemical attack

The Intake Pumping Station will be periodically inspected for loss of

material (spalling, scaling)and cracking due to the effects of freeze-thaw

at the waterline where icing conditions could occur(see GALL audit

question 368). The periodic inspection for aging effects due to freeze

thaw will be included in the BFN Structures Monitoring Program.

 d. Detection of Aging Effects: 

Visual inspections of structural conditions will be used as the method

used to detect aging effects. An inspection checklist consistent with those

used for Structures Monitoring Program will be used. All defects will be

required to be identified and documented on the inspection checklists for

review and evaluation by the Responsible Engineer (BFN Structures

Monitoring Program Engineer). Individuals trained and experienced with

the BFN Structures Monitoring Program will perform the inspections.

 e. Monitoring and Trending:

The submerged concrete at the Intake Pumping Station will be inspected

prior to the extended period of operation.

 f. The acceptance criteria of the BFN Structures Monitoring Program will be

used. BFN Structures Monitoring Program acceptance criteria are based

upon Responsible Engineer (BFN Structures Monitoring Program

Engineer) review and classification of the results as acceptable,

acceptable with deficiencies, and unacceptable respectively. These

performance criteria ensure that the structure:
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 ! remains capable of meeting its design basis and performing its

intended function; and

 ! will not result in a loss of intended function due to a degraded

condition or aging effect.

If the submerged concrete fails to meet the acceptance criteria, a cause

determination evaluation will be performed. If acceptance criteria are not

meet, two additional pump bays will be inspected prior to the extended

period of operation. If one or more of the additional pump bays fails to

meet its acceptance criteria, then submerged concrete at the intake

pump station will be inspected periodically consistent with the Structures

Monitoring Program requirements.

 (4) Periodic monitoring of raw service water: 

Prior to entering the period of extended operation, BFN will initiate periodic

monitoring of the raw service water in close proximity to the Intake Pumping

Station for the requirements of an aggressive environment as described in

NUREG-1557. Periodic monitoring will be consistent with the BFN Structures

Monitoring Program inspection frequency.

The staff reviewed the above response and found that the applicant fully had responded to

RAI 3.5-16 with reasonable plant operation-based justifications. Therefore, the staff’s concern

described in RAI 3.5-16 is resolved.

Aluminum in an Outside Air Environment – The staff requested the applicant to provide the

technical basis for concluding that no aging management of aluminum components is required

for an outside environment.

The following list identifies aluminum components in an outside air environment:

 • electrical and I&C penetrations

 • conduits and supports

 • non-ASME equivalent supports

By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that aluminum alloys containing zinc are susceptible to corrosion in wetted, aggressive

environments. The outside air environment does not have contaminants that would cause an

aggressive environment. Additionally, rain would periodically wash any contaminant(s) from the

material. The aluminum penetration sleeves and conduit at BFN are also constructed of

6063-T42 alloy material that is resistant to pitting, crevice corrosion, and SCC (Metals

Handbook, Ninth Edition, Volume 13, "Corrosion," ASM International, 1987). Therefore, the

potential for concentration of contaminates is not significant for aluminum components in an

outside air environment and loss of function due to corrosion is not considered plausible.

The applicant also stated that EPRI structural tools document, “Aging Effects for Structures and

Structural Components (Structural Tools),” EPRI 1002950 revision 1, August 2003, states that

aging management is not required for structural aluminum and aluminum alloys in a
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non-aggressive ambient outside environment (general, galvanic, crevice and pitting corrosion,

and SCC).

The applicant further stated that a review of BFN operating history did not reveal any loss of

intended function due to aging effects for the following aluminum components: 

 • electrical and I&C penetrations

 • conduits and supports

 • non-ASME equivalent supports

The staff accepts the applicant’s AMR results, that aging management is not required for these

aluminum components in an outside environment, on the basis that (1) the material used is

resistant to corrosion and SCC, and (2) concentration of contaminates in a non-aggressive

ambient outside environment is not plausible

The staff also reviewed the information provided in LRA Section 3.5.2.1.12 and determined that

the applicant had adequately identified applicable aging effects, and the AMPs credited for

managing the aging effects, for the intake pumping station components that are not addressed

by the GALL Report. The staff found the applicant’s AMR results for the intake pumping station

components acceptable.

3.5.2.3.13 Gate Structure No. 3 – Summary of Aging Management Evaluation – Table 3.5.2.13

The staff reviewed LRA Table 3.5.2.13, which summarizes the results of AMR evaluations for

the gate structure No. 3 component groups.

The staff also reviewed the information provided in LRA Section 3.5.2.1.13 and determined that

the applicant had adequately identified applicable aging effects and the AMPs credited for

managing the aging effects for the gate structure No. 3 components that are not addressed by

the GALL Report. The staff found the applicant’s AMR results for the gate structure No. 3

components acceptable.

3.5.2.3.14 Intake Channel – Summary of Aging Management Evaluation – Table 3.5.2.14

The staff reviewed LRA Table 3.5.2.14, which summarizes the results of AMR evaluations for

the intake channel component groups.

The staff also reviewed the information provided in LRA Section 3.5.2.1.14 and determined that

the applicant had adequately identified applicable aging effects, and the AMPs credited for

managing the aging effects for the intake channel components that are not addressed by the

GALL Report. The staff found the applicant’s AMR results for the intake channel components

acceptable.

3.5.2.3.15 North Bank of Cool Water Channel East of Gate Structure No. 2 – Summary of

Aging Management Evaluation – Table 3.5.2.15

The staff reviewed LRA Table 3.5.2.15, which summarizes the results of AMR evaluations for

the north bank of cool water channel east of gate structure No. 2 component groups.
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The staff also reviewed the information provided in LRA Section 3.5.2.1.15 and determined that

the applicant had adequately identified applicable aging effects, and the AMPs credited for

managing the aging effects for the north bank of cool water channel east of gate structure No. 2

components that are not addressed by the GALL Report. The staff found the applicant’s AMR

results for the north bank of cool water channel east of gate structure No. 2 components

acceptable.

3.5.2.3.16 South Dike of Cool Water Channel Between Gate Structure Nos. 2 and 3 –

Summary of Aging Management Evaluation – Table 3.5.2.16

The staff reviewed LRA Table 3.5.2.16, which summarizes the results of AMR evaluations for

the south dike of cool water channel between gate structure Nos. 2 and 3 component groups.

The staff also reviewed the information provided in LRA Section 3.5.2.1.16 and determined that

the applicant had adequately identified applicable aging effects and the AMPs credited for

managing the aging effects for the south dike of the cool water channel between gate structure

Nos. 2 and 3 components that are not addressed by the GALL Report. The staff found the

applicant’s AMR results for the south dike of the cool water channel between gate structure

Nos. 2 and 3 components acceptable.

3.5.2.3.17 Condensate Water Storage Tanks’ Foundations and Trenches – Summary of Aging

Management Evaluation – Table 3.5.2.17

The staff reviewed LRA Table 3.5.2.17, which summarizes the results of AMR evaluations for

the condensate water storage tanks’ foundations and trenches component groups.

During the onsite audit, the staff reviewed selected items in LRA Table 3.5.2.17, for MEAP

combinations that are not consistent with the GALL Report. The staff requested clarifications for

the following material/environment combinations and the corresponding LRA Table 2 item:

Earthfill & Rock in a Buried Environment - This item indicates that the equipment supports and

foundations are earth fill (rock and sand). The staff requested that the applicant explain the

technical bases for concluding that there are no aging effects requiring management.

By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that the foundation for the CWST is comprised of a concrete ring foundation with the interior

portion of the ring foundation filled with crushed rock and sand. The earthen materials (rock and

sand) of the CWST foundation interior base are protected from environmental weathering

conditions by the concrete perimeter ring and CWST tank bottom. There are no aging effects

for the earthen materials of the CWST foundation interior base that require aging management.

Aging management of the CWST concrete foundation ring is managed by the Structures

Monitoring Program. Aging management of the CWST bottom will be performed by the 

One-Time Inspection Program. 

The applicant also stated that a review of BFN operating history did not reveal any loss of

intended function due to aging effects for earthen materials of the CWST foundation interior

base. 
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Based on the additional information provided by the applicant, the staff concurs with the

applicant’s AMR results for the crushed rock and sand base of the CWST. The staff concluded

that aging management is not required because these materials are adequately protected by

the concrete perimeter ring and the CWST tank bottom.

The staff also reviewed the information provided in LRA Section 3.5.2.1.17 and determined that

the applicant had adequately identified applicable aging effects, and the AMPs credited for

managing the aging effects for the condensate water storage tanks’ foundations and trenches

components that are not addressed by the GALL Report. The staff found the applicant’s AMR

results for the condensate water storage tanks’ foundations and trenches components

acceptable.

3.5.2.3.18 Containment Atmosphere Dilution Storage Tanks’ Foundations – Summary of Aging

Management Evaluation – Table 3.5.2.18

The staff reviewed LRA Table 3.5.2.18, which summarizes the results of AMR evaluations for

the containment atmosphere dilution storage tanks’ foundations component groups.

The staff also reviewed the information provided in LRA Section 3.5.2.1.18 and determined that

the applicant had adequately identified applicable aging effects, and the AMPs credited for

managing the aging effects for the containment atmosphere dilution storage tanks’ foundations

components that are not addressed by the GALL Report. The staff found the applicant’s AMR

results for the containment atmosphere dilution storage tanks’ foundations components

acceptable.

3.5.2.3.19 Reinforced Concrete Chimney – Summary of Aging Management Evaluation –

Table 3.5.2.19

The staff reviewed LRA Table 3.5.2.19, which summarizes the results of AMR evaluations for

the reinforced concrete chimney component groups.

During the onsite audit, the staff reviewed selected items in LRA Table 3.5.2.19 for MEAP

combinations that are not consistent with the GALL Report. The staff requested clarifications for

the following material/environment combinations and the corresponding LRA Table 2 items:

Carbon Steel in a Buried Environment- The applicant stated that the Structures Monitoring

Program relies on visual inspections whenever the components are uncovered during station

yard area excavations. The staff requested that the applicant confirm that this applies to buried

mechanical penetrations, clarify what other components are included in this provision, and

explain whether this is an enhancement to the existing program or whether this provision is

covered in the current program.

By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that LCEI-CI-C9 will be enhanced to include inspection of mechanical penetrations when

accessible. There are no other buried carbon steel components included with the program;

however, LCEI-CI-C9 will also be enhanced to include the inspection of buried concrete when

accessible. With enhancements, LCEI-CI-C9 will be consistent with GALL AMP XI.S6. 
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The applicant also stated that the Buried Piping and Tanks Inspections Program provides the

inspection requirements of buried piping when accessible. The Buried Piping and Tanks

Inspections Program is consistent with GALL AMP XI.M34. Section 7.2.9.2 of LCEI-CI-C9

currently provides the inspection attributes of buried piping, which includes pipe connections

and joints, and is credited as the Buried Piping and Tanks Inspections Program. 

The staff concluded that the applicant’s commitment to enhance the Structures Monitoring

Program to include inspection of buried mechanical penetrations when accessible, provides a

level of aging management for buried mechanical penetrations that is comparable to the GALL

Report recommendations for buried concrete, piping and tanks. Therefore, the staff found this

acceptable.

The staff also reviewed the information provided in LRA Section 3.5.2.1.19 and determined that

the applicant had adequately identified applicable aging effects and the AMPs credited for

managing the aging effects for the reinforced concrete chimney components that are not

addressed by the GALL Report. The staff found the applicant’s AMR results for the reinforced

concrete chimney components acceptable.

3.5.2.3.20 Turbine Buildings – Summary of Aging Management Evaluation – Table 3.5.2.20

The staff reviewed LRA Table 3.5.2.20, which summarizes the results of AMR evaluations for

the turbine buildings component groups.

The staff also reviewed the information provided in LRA Section 3.5.2.1.20 and determined that

the applicant had adequately identified applicable aging effects, and the AMPs credited for

managing the aging effects, for the turbine buildings components that are not addressed by the

GALL Report. The staff found the applicant’s AMR results for the turbine buildings components

acceptable.

3.5.2.3.21 Diesel High Pressure Fire Pump House – Summary of Aging Management

Evaluation – Table 3.5.2.21

The staff reviewed LRA Table 3.5.2.21, which summarizes the results of AMR evaluations for

the diesel high-pressure fire pump house component groups.

During the onsite audit, the staff reviewed selected items in LRA Table 3.5.2.21 for MEAP

combinations that are not consistent with the GALL Report. The staff requested clarifications for

the following material/environment combinations and the corresponding LRA Table 2 item:

Stainless Steel in a Submerged Environment - This item credits the Structures Monitoring

Program for managing the effects of loss of material due to crevice corrosion and pitting

corrosion for stainless steel beams, columns, plates, and trusses in a submerged environment.

The staff requested the applicant to identify (1) the components included in this item and (2)

where they are located, and (3) the submerged environment. A description of the types of

inspections that will be performed under the Structures Monitoring Program for these

components and clarification on whether these inspections are included in the current scope of

the Structures Monitoring Program was also requested. The staff also requested the applicant

to provide the technical basis for not monitoring water chemistry.
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By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that LRA Table 3.5.2.21 row 28 applies to submerged portions of the stainless steel debris

screen under the diesel high pressure fire pump house. The intended functions of the debris

screen are debris protection and NSR structural support. The applicant also stated that the

miscellaneous components portion of the Structures Monitoring Program will be enhanced to

visually inspect the submerged portions of the debris screen for loss of material due to crevice

and pitting corrosion. The applicant noted that portions of the diesel high-pressure fire pump

house debris screen are submerged in a raw water environment; therefore, monitoring of water

chemistry is not applicable as an AMP.

The staff accepts the applicant’s commitment to enhance the Structures Monitoring Program to

visually inspect the submerged portions of the stainless steel debris screen for loss of material

due to crevice and pitting corrosion. The staff considered this to be analogous to submerged

portions of water control structures for which visual inspection conducted as part of the

Structures Monitoring Program has been previously accepted.

The staff also reviewed the information provided in LRA Section 3.5.2.1.21 and determined that

the applicant had adequately identified applicable aging effects and the AMPs credited for

managing the aging effects for the diesel high-pressure fire pump house components that are

not addressed by the GALL Report. The staff found the applicant’s AMR results for the diesel 

high-pressure fire pump house components acceptable.

3.5.2.3.22 Vent Vaults – Summary of Aging Management Evaluation – Table 3.5.2.22

The staff reviewed LRA Table 3.5.2.22, which summarizes the results of AMR evaluations for

the vent vaults component groups.

The staff also reviewed the information provided in LRA Section 3.5.2.1.22 and determined that

the applicant had adequately identified applicable aging effects and the AMPs credited for

managing the aging effects for the vent vaults components that are not addressed by the GALL

Report. The staff found the applicant’s AMR results for the vent vaults components acceptable.

3.5.2.3.23 Transformer Yard – Summary of Aging Management Evaluation – Table 3.5.2.23

The staff reviewed LRA Table 3.5.2.23, which summarizes the results of AMR evaluations for

the transformer yard component groups.

The staff also reviewed the information provided in LRA Section 3.5.2.1.23 and determined that

the applicant had adequately identified applicable aging effects, and the AMPs credited for

managing the aging effects for the transformer yard components that are not addressed by the

GALL Report. The staff found the applicant’s AMR results for the transformer yard components

acceptable.

3.5.2.3.24 161 kV Switchyard – Summary of Aging Management Evaluation – Table 3.5.2.24

The staff reviewed LRA Table 3.5.2.24, which summarizes the results of AMR evaluations for

the 161 kV switchyard component groups.
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The staff also reviewed the information provided in LRA Section 3.5.2.1.24 and determined that

the applicant had adequately identified applicable aging effects, and the AMPs credited for

managing the aging effects for the 161 kV switchyard components that are not addressed by

the GALL Report. The staff found the applicant’s AMR results for the 161 kV switchyard

components acceptable.

3.5.2.3.25 500 kV Switchyard – Summary of Aging Management Evaluation – Table 3.5.2.25

The staff reviewed LRA Table 3.5.2.25, which summarizes the results of AMR evaluations for

the 500 kV Switchyard component groups.

The staff also reviewed the information provided in LRA Section 3.5.2.1.25 and determined that

the applicant had adequately identified applicable aging effects, and the AMPs credited for

managing the aging effects for the 500 kV switchyard components that are not addressed by

the GALL Report. The staff found the applicant’s AMR results for the 500 kV switchyard

components acceptable.

3.5.2.3.26 Structures and Component Supports – Summary of Aging Management Evaluation

– Table 3.5.2.26

The staff reviewed LRA Table 3.5.2.26, which summarizes the results of AMR evaluations for

the structures and component supports component groups.

During the onsite audit, the staff reviewed selected items in LRA Table 3.5.2.26 for MEAP

combinations that are not consistent with the GALL Report. The staff requested clarifications for

the following material/environment combinations and the corresponding LRA Table 2 items:

Aluminum in an Inside Air Environment - The staff requested the applicant to provide the

technical basis for concluding that no aging management of aluminum supports is required for

loss of mechanical function in an inside air environment.

By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that aluminum in an inside air environment applies to aluminum pipe lugs for equivalent ASME

Class 2 or 3 piping in the reactor buildings (inside air environment). Aluminum external surfaces

are not susceptible to corrosion unless their surfaces are wetted and there is a potential for

concentration of contaminants. The aluminum pipe lugs in the reactor building are not exposed

to a wetted aggressive/corrosive environment. Therefore, the potential for concentration of

contaminants is not significant for aluminum components in an inside air environment and loss

of mechanical function due to corrosion is not considered plausible. 

The applicant further stated that EPRI structural tools document, “Aging Effects for Structures

and Structural Components (Structural Tools)” EPRI 1002950 Revision 1, August 2003, states

that aging management is not required for structural aluminum and aluminum alloys in an inside

environment (general, galvanic, crevice, pitting corrosion, and SCC).

The applicant also stated that a review of BFN operating history did not reveal any loss of

intended function due to aging effects for aluminum pipe lugs for equivalent ASME Code

Class 2 or 3 piping in the reactor buildings for an inside air environment. 
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The staff found that the applicant had not considered loss of mechanical function due to aging

mechanisms other than corrosion. This omission is not consistent with the GALL Report. The

applicant also failed to credit an existing AMP (IWF) that includes the subject components in its

scope.The staff requested additional information to resolve this issue, and related issues. The

disposition is discussed at the end of this section, as part of the review of LRA Table 3.5.2.26

AMRs.

The staff also reviewed the information provided in LRA Section 3.5.2.1.26 and determined that

the applicant had adequately identified applicable aging effects, and the AMPs credited for

managing the aging effects for the structures and component supports commodities

components that are not addressed by the GALL Report. The staff found the applicant’s AMR

results for the structures and component supports commodities components acceptable. 

Aluminum in an Outside Air Environment – The staff requested the applicant to provide the

technical basis for concluding that no aging management of aluminum components is required

for an outside environment.

The following list identifies aluminum components in an outside air environment:

 • electrical and I&C penetrations

 • conduits and supports

 • non-ASME equivalent supports

By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that aluminum alloys containing zinc are susceptible to corrosion in wetted aggressive

environments. The outside air environment does not have contaminants that would cause an

aggressive environment. Additionally, rain would periodically wash any contaminant(s) from the

material. The aluminum penetration sleeves and conduit at BFN are also constructed of

6063-T42 alloy material that is resistant to pitting, crevice corrosion, and SCC (Metals

Handbook, Ninth Edition, Volume 13, "Corrosion," ASM International, 1987). Therefore, the

potential for concentration of contaminates is not significant for aluminum components in an

outside air environment and loss of function due to corrosion is not considered plausible.

The applicant also stated that EPRI structural tools document, “Aging Effects for Structures and

Structural Components (Structural Tools)” EPRI 1002950 Revision 1, August 2003, states that

aging management is not required for structural aluminum and aluminum alloys in a

non-aggressive ambient outside environment (general, galvanic, crevice and pitting corrosion,

and SCC).

The applicant further stated that a review of Browns Ferry operating history did not reveal any

loss of intended function due to aging effects for the following aluminum components: 

 • electrical and I&C penetrations

 • conduits and supports

 • non-ASME equivalent supports

The staff accepts the applicant’s AMR results, that aging management is not required for these

aluminum components in an outside environment, on the basis that (1) the material used is
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resistant to corrosion and SCC, and (2) concentration of contaminates in a non-aggressive

ambient outside environment is not plausible

Carbon Steel in a Containment Air Environment – For the high-strength bolts included under

this item, the staff requested that the applicant describe the bolting material, the nominal and

as-built yield strengths, and the hardness of the material. The applicant was also requested to

discuss the disposition of the recommendations for a comprehensive Bolting Integrity Program,

as delineated in NUREG-1339, and industry recommendations, as delineated in EPRI NP-5769.

By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating:

The only high strength structural bolting (ultimate tensile strength [UTS] > 150 ksi)

material specified for use at BFN is ASTM A-490 (Ref. General Engineering

Specification G-29BS01, PS 4.M.4.4, “ASME Section III and Non-ASME Section III

(including AISC, ANSI B31.1, and ANSI B31.5) Bolting Material”). The ultimate tensile

strength for A-490 bolting 1⁄2” to 1 1⁄2” may vary between 150 to 170 ksi, a minimum yield

strength of 130 ksi is specified and hardness may vary from 33 to 38 Rockwell C (ASTM

A-490 Standard).

The Bolting Integrity Program manages loss of material of mechanical component steel

bolting within the scope of License Renewal. ASME Section XI manages aging of

structural bolting (encompassed by ‘Support members; welds; bolted connections;

support anchorage to building structure’) for ASME equivalent supports. Structures

Monitoring Program manages aging of structural bolting for the remaining structural

supports within the scope of License Renewal. The support components, including the

bolting, are periodically inspected for loss of material by these programs.

High strength bolting (UTS >150 ksi) is not considered susceptible to cracking due to

stress corrosion cracking at BFN. For SCC to manifest in high strength bolting, an

aggressive chemical or wetted environment is required in addition to susceptible

material and high tensile stresses. High strength bolting (UTS >150 ksi) used in ASME

equivalent supports at BFN are installed in indoor air environments that are not exposed

to aggressive chemicals, periodic wetting, or splash zones. Additionally, high strength

bolting is used for Unit 1 drywell floor steel framing and other structural purposes to

connect the RPV skirt flange to the top flange of the ring girder in the drywell and these

bolts are exposed to a containment atmosphere environment in the drywell not subject

to aggressive chemicals, periodic wetting or splash zones. As noted below, thread

lubricants are also controlled to eliminate corrosive environmental effects. Therefore an

aggressive chemical or wetted environment does not exist.

Per the EPRI Mechanical and Structural Tools and EPRI NP-5769, high strength bolting

is considered susceptible to SCC in a corrosive environment with the use of thread

lubricants containing molybdenum disulfide. Approved thread lubricants for use in bolted

joints at BFN are specified in General Engineering Specification (GES) G-29B-S01 PS

4.M.1.1 and Section 3.9.2 notes that lubricants containing molybdenum disulfide shall

not be used.

Structural bolting procurement activities, receipt inspection and installation (torquing), as

defined in TVA procedure GES G-29B-S01, P.S.4.M.4.4, ‘ASME Section III and Non-
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Section III (Including AISC, ANSI B31.1, and ANSI B31.5) Bolting Material’, are

considered part of TVA’s Bolting Integrity Program and meet the industry

recommendations for these activities as delineated in NUREG-1339 and EPRI NP-5769.

The staff found that the applicant had presented a sufficient technical basis to support its AMR

results that high-strength bolting used in structural applications is not susceptible to SCC. The

staff determined that meeting the recommendations delineated in NUREG-1339 and EPRI

NP-5769 provides reasonable assurance that SCC will not occur.

Carbon Steel in an Inside Air Environment - The applicant indicated that only loss of material

due to general corrosion and loss of mechanical function due to corrosion are considered

applicable aging effects for the subject ASME-equivalent supports. The staff requested the

applicant to provide the technical basis for concluding that other aging mechanisms are not

applicable. 

By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that Table 3.5.2.26 row 2 applies to ASME-equivalent Class 1 supports. The AMR for the

material and environment combination of carbon steel in an inside air environment was

performed and the applicant concluded that the only plausible aging mechanisms needing

managing were:

 • loss of material due to general corrosion

 • loss of mechanical function due to corrosion, distortion, dirt, overload, and fatigue due to

vibratory and cyclic thermal loads 

The applicant further stated that ASME Section XI, Subsection IWF will be used to manage

these aging effects of loss of material and loss of mechanical function identified in

Table 3.5.2.26 row 2. The staff found this acceptable, because it is consistent with GALL.

Carbon Steel in an Outside Air Environment– The applicant indicated that only loss of material

due to general corrosion, crevice corrosion, and pitting corrosion are considered applicable

aging effects for the subject ASME-equivalent supports. The staff requested the applicant to

provide the technical basis for concluding that other aging mechanisms are not applicable.

By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that Table 3.5.2.26, row 9 applies to ASME-equivalent Class 2 and 3 supports. The AMR for the

material/environment combination of carbon steel in an outside air environment was performed

and the applicant concluded that the only plausible aging mechanism that needed to be

managed was loss of material due to general, crevice, and pitting corrosion. 

The applicant further stated that the ASME Code Section XI, Subsection IWF will be used to

manage the aging effect of loss of material identified in Table 3.5.2.26, row 9.

The staff noted that loss of mechanical function is also managed by IWF, even though the

applicant did not identify this aging effect. The staff accepts the applicant’s AMR results solely

on the basis that IWF is credited for license renewal, and IWF will manage loss of mechanical

function in addition to loss of material.
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The applicant also stated that the referenced table row applies to ASME-equivalent Class 2 and

3 supports and is not applicable to Class MC supports, and that the response to RAI-3.5-6 will

address the AMR results for Class MC supports.

Carbon Steel in a Submerged Environment – The staff requested that the applicant identify (1)

the components included in this item, (2) where they are located, and (3) the submerged

environment. The staff also requested the applicant to provide the technical basis for not

including these component types in the One-Time Inspection Program to confirm the

effectiveness of the Chemistry Control Program.

By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that Table 3.5.2.26, row 57 applies to carbon steel non-ASME Code equivalent supports inside

the CWST. Aging of carbon steel supports submerged in the CWST (treated water

environment) will be managed through monitoring CWST water chemistry by the Chemistry

Control Program. Effectiveness of the CWST Chemistry Control Program will be confirmed by

the One-Time Inspection Program of carbon steel mechanical components in a treated water

(condensate water) environment as noted in LRA Table 3.4.2.2 (Condensate and

Demineralized Water System). 

The staff found the use of the Chemistry Control Program and confirmation by the One-Time

Inspection Program acceptable to manage aging of submerged supports inside the condensate

water storage tank, on the basis that the supports are treated as part of the tank in the

applicant’s AMR.

Lubrite in an Inside Air Environment - The staff requested that the applicant describe where the

referenced items are used and provide the technical basis for concluding that no aging

management of the lubrite plates used in BFN is required in an inside air environment.

By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that Table 3.5.2.26, row 35 applies to the lubrite plates used for the core spray and RHR

pump/equipment base supports. EPRI 1002950, “Aging Effects for Structures and Structural

Components (Structural Tools), Revision 1,” August 2003, states that lubrite material resists

deformation, has a low coefficient of friction, resists softening at elevated temperatures,

absorbs grit and abrasive particles, is not susceptible to corrosion, withstands high intensities of

radiation, and will not score or mar. Lubrite products are solid, permanent, completely self

lubricating, and require no maintenance. The reactor building environment at the location of the

core spray and RHR pump equipment base supports is not an aggressive or wetted

environment. 

The applicant also stated that a search of BFN and industry operating experience did not

identify any instances of lubrite plate degradation or failure to perform its intended function due

to aging effects. NUREG-1759, “Safety Evaluation Report Related to the License Renewal of

Turkey Point Nuclear Plant, Units 3 and 4,” and NUREG-1769, “Safety Evaluation Report

Related to the License Renewal of Peach Bottom Atomic Power Station, Units 2 and 3,” concur

that there are no lubrite plate aging effects that require aging management.
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Based on the additional information provided by the applicant, the staff found the applicant’s

AMR results for lubrite plates to be acceptable. Prior staff evaluations of this issue have

concluded that there are no aging effects requiring aging management.

Reinforced Concrete in a Buried Environment - This item applies to buried reinforced concrete

equipment supports and foundations. The staff requested that the applicant explain how the

Structures Monitoring Program is used to manage these buried (presumably inaccessible)

components.

By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that Table 3.5.2.26, row 41 applies to transformer pads/foundations in the transformer yard,

161kV switchyard and 500kV switchyard in a buried environment. The electrical equipment

concrete foundations are exposed to both the outside air environment and the inaccessible

buried environment. The outside air environment is addressed in LRA Table 3.5.2.26, row 44.

Reduction in concrete anchor capacity will manifest itself at the anchor locations which are

located in the outside air environment. The Structures Monitoring Program will manage

reduction of concrete anchor capacity for those portions of the equipment foundations exposed

to the outside air environment. Aging management for below grade inaccessible concrete will

be based on inspection of the accessible concrete in the outside air environment. 

Based on the additional information provided by the applicant, the staff found the applicant’s

AMR results for the buried portions of the concrete transformer pads/foundations to be

acceptable. Periodic inspection of the accessible concrete by the Structures Monitoring

Program will provide an indication of the condition of the buried concrete.

Stainless Steel in a Submerged Environment - The staff requested the applicant to identify (1)

the ASME-equivalent supports and components included in this item, (2) where they are

located, and (3) the submerged environment. The applicant was also requested to provide the

BFN AMR for this item and discuss the technical basis for not crediting ASME Section XI,

Subsection IWF as the AMP.

By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that LRA Table 3.5.2.26, row 11 applies to the stainless steel ASME-equivalent Class 2

supports for the safety-related valve (SRV) discharge lines that are in the submerged

environment of the suppression pool water. The Chemistry Control Program and a one-time

inspection will manage loss of material for stainless steel ASME-equivalent Class 2 supports

exposed in a submerged treated (suppression pool) water environment. These lines are exempt

from inspection per ASME Section XI.

Based on the additional information provided by the applicant, the staff accepts the applicant’s

AMR results for stainless steel ASME Code equivalent Class 2 supports for the SRV discharge

lines that are in the submerged environment of the suppression pool water. The staff concurred

that these supports are exempt from IWF inspection because they are not fluid filled. The

credited AMPs are consistent with the GALL Report recommendations for Class 1 stainless

steel small-bore piping. The staff found this appropriate, in lieu of IWF.

LRA Table 3.5.2.26 - In LRA Table 3.5.2.26, rows 5, 6, 10, 14, 15, 16, and 18, the applicant

indicated that no aging management is required in containment atmosphere, inside air and

outside air environments for stainless steel and non-ferrous aluminum ASME Code equivalent
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supports and components. Note 3 to LRA Table 3.5.2.26, which applies to all of the cited row

numbers, states that there are no applicable aging effects for the material/environment

combinations and that this is consistent with industry guidance. The applicant does not credit

ASME Code AMP for license renewal. 

It was the staff’s understanding that the support components covered by the cited row numbers

are required to be inspected under IWF during the current licensing term. Therefore, the staff

requested that the applicant explain why this CLB commitment would not continue for the

extended period of operation.

By letter dated October 8, 2004, the applicant submitted its formal response to the staff, stating

that these ASME-equivalent supports and components will continue to be inspected consistent

with the commitments contained in the CLB for the ASME Code Section XI Subsection IWF

Program requirements in effect during the extended period of operation. The applicant further

stated that the specific reference to row numbers noted in the audit team’s question all had

material and environmental combinations that, upon performance of the AMR, determined that

there were no aging effects that required managing for license renewal.

The staff noted inconsistencies between the applicant’s AMR for the cited row numbers, all of

which are not susceptible to general corrosion, and the applicant’s AMR for carbon steel ASME

Code equivalent supports and components, which are susceptible to general corrosion. For the

cited row numbers, the applicant considers corrosion to be the only age-related mechanism

leading to loss of mechanical function. The applicant’s position is that the other GALL Report

listed mechanisms leading to loss of mechanical function (distortion, dirt, overload, fatigue due

to vibratory and cyclic thermal loads; elastomer hardening) are not age-related. On this basis,

the applicant has concluded that aging management for loss of mechanical function is not

applicable to the cited row numbers. However, for carbon steel ASME Code equivalent supports

and components, the applicant identified additional GALL Report listed mechanisms as leading

to loss of mechanical function (see LRA Table 3.5.2.26, rows 2, 4, 12, and 13); and credits IWF

as the AMP for license renewal. 

The staff’s review of LRA Table 3.5.2.26 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. 

In RAI 7.2.5-2, dated March 8, 2005, the staff requested the applicant to: (1) submit a detailed

description of all supports covered by LRA Table 3.5.2.26, rows 5, 6, 10, 14, 15, 16, and 18;

and (2) for each support, provide the technical basis for concluding that every GALL Report

listed mechanism (corrosion, distortion, dirt, overload, fatigue due to vibratory and cyclic

thermal loads; elastomer hardening) leading to loss of mechanical function is not applicable. As

an alternative, the applicant may credit IWF as an AMP for license renewal.
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In its response, by letter dated April 5, 2005, the applicant provided its formal response, which

states:

For row numbers 5, 6, 15, and 16 of Table 3.5.2.26, the table will be revised to

credit IWF as the aging management program. 

The supports for row number 10 are the typical pipe supports comprised of steel

structural shapes, welded or bolted together and attached to the concrete

structure/building with base plates or attached to other steel structural shapes of the

building. The aging effect for GALL III.B1.2.1-a is “Loss of Material” and not “Loss of

Mechanical Function” as noted in the question. The AMR is consistent with the

reference to Note 3 of Table 3.5.2.26. Additionally, this is consistent with the proposed

revision to GALL for Item number III.B1.2-5 (TP-5) for this material and environment

combination. The AMR conclusion for the proposed GALL revision to GALL for Item

number III.B1.2-5 (TP-5) is “no aging effects are applicable”; therefore, no AMP is

required. 

The supports in-scope for row number 14 of Table 3.5.2.26 are integral welded

lugs to the process pipe. The lug material is the same as the process pipe

(aluminum). Aluminum external surfaces are not susceptible to corrosion unless

their surfaces are wetted or exposed to an aggressive environment. Since

periodic wetting or exposure to aggressive environments of component external

surfaces in an inside air environment will not occur, loss of mechanical function

due to corrosion is not considered plausible and the other aging mechanisms

(distortion, dirt, overload, fatigue due to vibratory and cyclic thermal loads;

elastomer hardening) do not apply. 

The supports in-scope for row number 18 of Table 3.5.2.26 are integral welded

lugs to the process pipe. The lug material is the same as the process pipe

(stainless steel). The in-scope piping system is located in the Residual Heat

Removal Service Water (RHRSW) Tunnels (LRA Section 2.4.3.5). Since the

piping and supports are located within the RHRSW Tunnels and are exposed to

an inside air environment and are not exposed to an outside air environment as

noted in the AMR table, Row 18 can be deleted. Row number 10 (applicable

GALL item - III.B1.2.1-a) is the applicable AMR line item for the material and

environment combinations of these stainless steel supports in the RHRSW

Tunnel. 

The staff reviewed the applicant’s response and found it acceptable since the AMRs are

consistent with the GALL Report. Therefore, the staff’s concern described in RAI 7.2.5-2 is

resolved.

In RAI 3.5-12, dated December 10, 2004, the staff stated that non-ferrous aluminum conduit

and supports that are exposed to outside air are listed in LRA Table 3.5.2.26 as components

having no applicable AERM; thus, no AMP is designated to manage their aging. Depending on

the severity of the outside air environment to which the components are consistently exposed,

some aluminum conduit and supports may experience loss of material aging effect. Therefore,

the staff requested that the applicant discuss its past plant-specific inspection results of these

supports in order to provide an operating experience-based justification for the above AMR

finding.
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In its response, by letter dated January 31, 2005, the applicant stated:

The following list identifies aluminum components in an outside air environment:

 • electrical and I&C penetrations

 • conduits and supports

 • non-ASME equivalent supports

Aluminum alloys containing zinc are susceptible to corrosion in wetted aggressive

environments. However, the outside air environment does not contain contaminants that

would cause an aggressive environment. In addition, the aluminum conduit and conduit

supports are also constructed of 6063-T42 alloy that is resistant to pitting, crevice

corrosion, and SCC (Metals Handbook, Ninth Edition, Volume 13, "Corrosion," ASM

International, 1987). Since the potential for concentration of contaminates is not

significant, and the specific aluminum grade used in an outside air environment is more

resistant to corrosion, loss of function due to corrosion is not considered plausible. 

A review of BFN operating history, the structures monitoring baseline inspection, and

the results for the first structures monitoring inspection period did not reveal any loss of

intended function due to aging effects for the following aluminum components:

 • electrical and I&C penetrations,

 • conduits and supports

 • non-ASME equivalent supports

Based on the applicant’s additional information provided above and operating experience that

(1) the potential for concentration of contaminates at BFN site is not significant, and the specific

aluminum grade used in an outside air environment is more resistant to corrosion, loss of

function due to corrosion is not considered plausible, and (2) a review of operating history, the

structures monitoring baseline inspection, and the results of the first structures monitoring

inspection period did not reveal any loss of intended function due to aging effects for the

aluminum components. The staff found the AMR results for its aluminum components adequate

and acceptable. Therefore, the staff’s concern described in RAI 3.5-12 is resolved.

In RAI 3.5-13, dated December 10, 2005, the staff stated that LRA Table 3.5.2.26 lists

equipment supports and foundations made of non-ferrous lubrite that are exposed to inside air

environment as components having no AERM; therefore, no AMP is designated for the

components. NUREG-1801, Table III.B1.1.3-a identifies loss of mechanical function, corrosion,

distortion, dirt, overload, fatigue due to vibratory and cyclic thermal loads, and elastomer

hardening as potentially applicable aging effects for the lubrite components, and designates

ASME Code Section XI, Subsection IWF Program as the AMP to manage the listed aging

effects. Therefore, the staff requested the applicant to discuss past plant-specific inspection

and maintenance results of these lubrite supports in order to provide an operating

experience-based justification for the LRA assessment.
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In its response, by letter dated January 31, 2005, the applicant stated:

The Table 3.5.2.26 entry applies to the lubrite plates used for the Core Spray and RHR

pump equipment support plates. EPRI report 1002950, “Aging Effects for Structures and

Structural Components (Structural Tools) Revision 1,” states that lubrite material resists

deformation, has a low coefficient of friction, resists softening at elevated temperatures,

absorbs grit and abrasive particles, is not susceptible to corrosion, withstands high

intensities of radiation, and will not score or mar. lubrite products are solid, permanent,

completely self lubricating, and require no maintenance. The Browns Ferry reactor

building environment at the location of the Core Spray and RHR pump equipment

support plates is not an aggressive or wetted environment. 

A search of Browns Ferry and industry operating experience did not identify any

instances of Lubrite plate degradation or failure to perform its intended function due to

aging effects. NUREG-1759, “Safety Evaluation Report Related to the License Renewal

of Turkey Point Nuclear Plant, Units 3 and 4” and NUREG-1769, “Safety Evaluation

Report Related to the License Renewal of Peach Bottom Atomic Power Station, Units 2

and 3,” concur that there are no aging effects for lubrite plate that require aging

management.

Based on the applicant’s additional information provided above that (1) the reactor building

environment at the location of the core spray and RHR pump equipment support plates is not

an aggressive or wetted environment, (2) lubrite products are solid, permanent, completely self

lubricating, and require no maintenance, (3) a search of BFN and industry operating experience

did not identify any instances of lubrite plate degradation or failure to perform its intended

function due to aging effects, and (4) prior staff positions taken with respect to the aging

management of lubrite plate under similar environmental conditions, as reported in NUREGs

1759 and 1769, the staff found the applicant’s response to RAI 3.5-13 acceptable. Therefore

the staff’s concern described in RAI 3.5-13 is resolved.

Conclusion. On the basis of its review, the staff found that the applicant appropriately evaluated

AMR results involving MEAP combinations that are not evaluated in the GALL Report. The staff

found that the applicant 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).

Sections 3.5.2.3.27 and 3.5.2.3.28. The following AMRs were added as a result of SER

Sections 2.4.3.9 and 2.4.7.7, respectively.

3.5.2.3.27 South Access Retaining Walls – Summary of Aging Management Evaluation –

Table 3.5.2.27

The staff reviewed added LRA Table 3.5.2.27, which summarizes the results of AMR

evaluations for the south access retaining walls component groups.

On the basis of its review of the information provided in added LRA Section 3.5.2.1.27 and

Table 3.5.2.27, the staff determined that the applicant had adequately identified applicable

aging effects, and the AMP credited for managing the aging effects, for the south access
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retaining walls components that are not addressed by the GALL Report. The staff found the

applicant’s AMR results for the south access retaining walls components acceptable. 

3.5.2.3.28 Isolation Valve Pit – Summary of Aging Management Evaluation – Table 3.5.2.28

The staff reviewed added LRA Table 3.5.2.28, which summarizes the results of AMR

evaluations for the isolation valve pit component groups.

On the basis of its review of the information provided in added LRA Section 3.5.2.1.28 and

Table 3.5.2.28, the staff determined that the applicant had adequately identified applicable

aging effects, and the AMP credited for managing the aging effects, for the isolation valve pit

components that are not addressed by the GALL Report. The staff found the applicant’s AMR

results for the isolation valve pit components acceptable.

3.5.3 Conclusion

The staff concluded that the applicant provided sufficient information to demonstrate that the

effects of aging of the containments, structures, and component supports components that are

within the scope of license renewal and subject to an AMR will be adequately managed so that

the intended function(s) will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21(a)(3).

The staff also reviewed the applicable UFSAR 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).
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3.6 Aging Management of Electrical and Instrumentation and Controls

This section of the SER documents the staff’s review of the applicant’s AMR results for the

electrical and I&C components and component groups.

3.6.1 Summary of Technical Information in the Application

In LRA Section 3.6, the applicant provided AMR results for components. In LRA Table 3.6.1,

“Summary of Aging Management Evaluations for Electrical and Instrumentation and Control

Systems Evaluated in Chapter VI of NUREG-1801,” 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

AERMs. These reviews included evaluation of plant-specific and industry operating experience.

The plant-specific evaluation included reviews of condition reports and discussions with

appropriate site personnel to identify AERMs. The applicant’s review of industry operating

experience included a review of the GALL Report and operating experience issues identified

since the issuance of the GALL Report.

3.6.2 Staff Evaluation

The staff reviewed LRA Section 3.6 to determine if the applicant had provided sufficient

information to demonstrate that the effects of aging for the electrical and instrumentation and

control components that are within the scope of license renewal and subject to an AMR will be

adequately managed so that the intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

The staff performed an onsite audit during the weeks of June 21 and July 26, 2004, of AMRs to

confirm the applicant’s claim that certain identified AMRs were consistent with the GALL

Report. The staff did not repeat its review of the matters described in the GALL Report;

however, the staff did verify that the material presented in the LRA was applicable and that the

applicant 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 evaluation are documented in the

BFN audit and review report and are summarized in SER Section 3.6.2.1.

In the onsite audit, the staff also reviewed those selected AMRs that were consistent with the

GALL Report and for which further evaluation is recommended. The staff confirmed that the

applicant’s further evaluations were consistent with the acceptance criteria in SRP-LR

Section 3.6.2.2, dated July 2001. The staff’s audit evaluations are documented in the BFN audit

and review report and are summarized in SER Section 3.6.2.2.

In the onsite audit, the staff also conducted a technical review of the remaining AMRs that were

not consistent with, or not addressed in, the GALL Report. The audit and technical review

included evaluating whether all plausible aging effects were identified and evaluating whether

the aging effects listed were appropriate for the combination of materials and environments

specified. The staff’s audit evaluations are documented in the BFN audit and review report and
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are 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 UFSAR supplement to ensure

that they provided an adequate description of the programs credited with managing or

monitoring aging for the electrical and I&C 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.

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

Report

Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

Electrical

equipment subject

to 10 CFR 50.49

environmental

qualification (EQ)

requirements

[Item Number

3.6.1.1 (F.4)]

Degradation due to

various aging

mechanisms

Environmental

Qualification of

Electrical

Components

Program

TLAA This TLAA is

evaluated in

Section 4.4,

Environmental

Qualification

Electrical cables

and connections not

subject to

10 CFR 50.49 EQ

requirements

(Item Number

3.6.1.2)

Embrittlement,

cracking, melting,

discoloration,

swelling, or loss of

dielectric strength

leading to reduced

insulation

resistance (IR);

electrical failure

caused by thermal/

thermoxidative

degradation of

organics; radiolysis

and photolysis [ultra

violet (UV) sensitive

materials only] of

organics;

radiation-induced

oxidation; moisture

intrusion

Aging Management

Program for

Electrical Cables

and Connections

Not Subject to

10 CFR 50.49 EQ

Requirements

Aging Management

Program for

Electrical Cables

and Connections

Not Subject to

10 CFR 50.49 EQ

Requirements

Consistent with

GALL, which

recommends no

further evaluation

(See Section

3.6.2.1)
Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

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Electrical cables

used in

instrumentation

circuits not subject

to 10 CFR 50.49

EQ requirements

that are sensitive to

reduction in

conductor insulation

resistance

(Item Number

3.6.1.3)

Embrittlement,

cracking, melting,

discoloration,

swelling, or loss of

dielectric strength

leading to reduced

IR; electrical failure

caused by thermal/

thermoxidative

degradation of

organics;

radiation-induced

oxidation; moisture

intrusion

Aging Management

Program for

Electrical Cables

Used in

Instrumentation

Circuits not Subject

to 10 CFR 50.49

EQ Requirements

Aging Management

Program for

Electrical Cables

Used in

Instrumentation

Circuits not Subject

to 10 CFR 50.49

EQ Requirements

Consistent with

GALL, with

exceptions, which

recommends no

further evaluation

(See Section

3.6.2.1)

Inaccessible

medium-votlage

(2kV to 15kV)

cables (e.g.,

installed in conduit

or direct buried) not

subject to

10 CFR 50.49 EQ

requirements

Formation of water

trees; localized

damage leading to

electrical failure

(breakdown of

insulation) caused

by moisture

intrusion and water

trees

Aging Management

Program for

Inaccessible

Medium voltage

Cables not Subject

to 10 CFR 50.49

EQ Requirements

Aging Management

Program for

Inaccessible

Medium voltage

Cables not Subject

to 10 CFR 50.49

EQ Requirements

Consistent with

GALL, which

recommends no

further evaluation

(See Section

3.6.2.1)

The staff’s review of the BFN component groups followed one of several approaches. One

approach, documented in SER Section 3.6.2.1, involves the staff’s review of the AMR results in

the electrical and I&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 I&C 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 3.6.2.3,

involves the staff’s review of the AMR results in the electrical and I&C components that the

applicant indicated are not consistent with, or not addressed in, the GALL Report. The staff’s

review of AMPs that are credited to manage or monitor aging effects of the electrical and I&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 materials, environments, and AERMs. The applicant identified the following

programs that manage the aging effects related to the electrical and I&C components:

 • Accessible Non-EQ Cables and Connections Inspection Program

 • Bus Inspection Program

 • Electrical Cables Not Subject to 10 CFR 50.49 Environmental Qualification

Requirements Used in Instrumentation Circuits Program
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 • EQ Program

 • Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 EQ Requirements

Program

Staff Evaluation. In LRA Table 3.6.2.1, the applicant provided a summary of AMRs for the

electrical and I&C components, and identified which AMRs it considered to be consistent with

the GALL Report.

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 audited those AMRs with

Notes A through E, which indicated that 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 is different from but consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent

with the AMP identified by the GALL Report. This note indicates that the applicant 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 is different from but consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP takes some

exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify

consistency with the GALL Report. The staff verified whether the AMR line item of the different

component is 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
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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 is valid for the site-specific conditions.

The staff conducted an audit and review of the information provided in the LRA and program

bases documents, which are available at the applicant's engineering office. On the basis of its

audit and review, the staff found that the AMR results that the applicant claims to be consistent

with the GALL Report are consistent with the AMRs in the GALL Report. Therefore, the staff

found that the applicable aging effects were identified and are appropriate for the combination

of materials and environments listed.

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 concluded 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 concluded 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 the

electrical components. The applicant provided information concerning how it will manage the

following aging effects:

 • electrical equipment subject to EQ requirements

 • QA for aging management of NSR components

Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant

claimed consistency with the GALL Report, and for which the GALL Report recommends further

evaluation, the staff audited and reviewed the applicant’s evaluation to determine whether it

adequately addressed the issues that were further evaluated. In addition, the staff reviewed the

applicant’s further evaluations against the criteria contained in SRP-LR Section 3.6.2.2. Details

of the staff’s audit are documented in the staff’s BFN audit and review report. The staff’s

evaluation of the aging effects is discussed in the following sections.

3.6.2.2.1 Electrical Equipment Subject to Environmental Qualification Requirements

EQ is a TLAA requiring further evaluation. TLAAs are evaluated in SER Section 4.
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3.6.2.2.2 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).

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

Summary of Technical Information in the Application. In LRA Table 3.6.1, the staff reviewed

additional details of the results of the AMRs for MEAP combinations that are not consistent with

the GALL Report, or that are not addressed in the GALL Report.

In LRA Table 3.6.1, 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.

The applicant’s AMR results that are not consistent with the GALL Report, or not addressed in

the GALL Report, were not reviewed during the onsite audit.

3.6.2.3.1 Aging Management Evaluations - Fuse Holder

Fuse holders (including fuse clips and fuse blocks) are included consistent with Interim Staff

Guidance (ISG)-5, "Identification and Treatment of Electrical Fuse Holders for License

Renewal," dated March 10, 2003. ISG-05 added NRC guidance for the identification and

treatment of electrical fuse holders for license renewal, which stipulates that fuse holders will be

scoped, screened, and included in the AMR in the same manner as terminal blocks and other

types of electrical connections. The guidance also says that an appropriate AMP should be

adopted to manage the effects of aging where necessary.

Consistent with that staff guidance, the applicant identified oxidation, corrosion of connecting

surfaces, moisture or chemical contamination, loosening of connection/thermal cycling, wear,

fatigue, loosening of connection/vibration, deformation, and loosening of connection/mechanical

stresses as the aging mechanism/effects for the fuse holders. 
3-357

In the LRA, the applicant stated that plant installation and maintenance practices provide

appropriate protection for fuse holders from moisture intrusion, such as in enclosures, since

fuse holders are protected by their location within a controlled environment. Therefore,

oxidation/corrosion of connecting surfaces due to exposure to moisture or chemical

contamination is not an AERM. The applicant also stated that fuse holders in use are designed

to withstand the ratings of the fuses they house. Thus, fuse holders are protected from thermal

cycling by their design, which prevents the aging effect of fuse clip/finger loosening, and

requires no AMP. Fuse holders are mounted in their own support structure separated from

sources of vibration; therefore, vibration is not a concern for fuse holders, and an AMP is not

required. The fuses are not routinely pulled and reinserted potentially causing fatigue of the

fuse holder clips.

Based on the above, the applicant concluded that fuse holders at BFN will maintain their

intended function through the period of extended operation with no AMP required.

In RAI 3.6-5, dated November 4, 2004, the staff asked the applicant to justify how a controlled

environment could provide protection for fuse holders, preventing aging from the effects of

temperature, humidity, radiation, and fatigue. The staff also asked the applicant whether the

actual condition of the fuse holders was evaluated to assess the extent of use and whether any

visual inspection was performed on the fuse holders; if so, the applicant was requested to

provide the findings or explain why an assessment of their current condition was not necessary.

In its response, by letter dated December 9, 2004, the applicant stated: 

A controlled environment, as it pertains to fuse holders, is one where the fuse holder is

installed in an enclosure that protects the fuse holder from exposure to moisture and

chemical contamination. Enclosures at BFN are designed and selected for the

environment in which they are installed. National Electrical Manufacturers Association

(NEMA) Standards imposed during the design process ensures the enclosure is suited

for the environment in which it is installed. In addition, conduits entering the enclosure

were sealed, along with unused knockouts. Enclosure tops and non-welded seams are

sealed, along with enclosure and component mounting screws/bolts. Door gaskets

supplied with NEMA enclosures are acceptable, or the enclosure door is sealed utilizing

engineering approved maintenance instructions.

The aging mechanisms of temperature and radiation are not applicable to the fuse clip

portion of fuse holders, but are applicable to the polymeric base material. Polymeric

materials of fuse holders utilized at BFN were evaluated as insulated connections and

are acceptable for the extended period of operation in the environments in which they

are presently installed. None of the polymeric material's 60-year bounding temperature

or radiation values were exceeded in any plant space where fuse holders are installed at

BFN. 

By email dated December 15, 2004, the staff requested additional information on the subject. In

its response, by letter dated January 18, 2005, the applicant stated that polymeric materials of

fuse holders are included in the Accessible Non-EQ Cable and Connections Inspection

Program.
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On the issue of fatigue, mechanical stress due to forces associated with electrical faults and

transients are mitigated by the fast action of circuit protective devices at high currents.

However, mechanical stress due to electrical faults is not considered a credible aging

mechanism since such faults are infrequent and random in nature. Fuse holders in use are

designed to withstand the ratings of the fuses they house and are selected to ensure they are

operated below their rated load. Thus by design, fuse holder clips and connections are

protected from fatigue failure due to thermal cycling.

Industry operating experience as documented in NUREG-1760 "Aging Assessment of

Safety-Related Fuses used in Low- and Medium-Voltage Applications in Nuclear Power Plants,"

identified that fuse failures due to thermal cycling are attributed to the fuse element, not fuse

holder clips. NUREG-1760 documents no instances of fuse holder clip fatigue failures attributed

to thermal cycling. A visual inspection performed on a sample located in outdoor weather

conditions did not reveal visual signs of corrosion or degradation.

On the basis of its review, the staff found that the applicant had addressed the staff's concern

adequately; therefore, the staff's concern described in RAI 3.6-5 is resolved. The staff also

found that no AMP is required to manage the aging effects of fuse holders. 

3.6.2.3.2 Aging Management Evaluations - Insulated Cables and Connections

In LRA Section 3.6.2.3.2, the applicant identified the electrical failures due to moisture intrusion,

which was addressed in SAND 96-0344, "Aging Management Guidelines for Commercial

Nuclear Power Plants - Electrical Cable and Terminations," and TR-103834-P1-2, "Effects of

Moisture on the Life of Power Plant Cables." 

In evaluating these aging effects, the applicant, in the LRA, said that plant installation and

maintenance practices provide appropriate protection for connectors from moisture (such as

connectors in enclosures or covered with Raychem tubing/splices or tape). Therefore, aging

effects related to moisture intrusion for low-voltage cables and connectors do not require aging

management for the period of extended operation. However, this aging effect/mechanism is

prevalent in medium voltage cables (i.e., water treeing) which is managed by the Inaccessible

Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification

Requirements Program.

The staff agreed that the applicant had correctly concluded that no separate AMP is required to

manage aging effects related to moisture intrusion for low-voltage cables and connectors. The

staff found that the GALL Report addressed the aging effect/mechanism in inaccessible

medium voltage cables, which will be adequately managed by the applicant's Inaccessible

Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification

Requirements Program.

3.6.2.3.3 Aging Management Evaluations - High-Voltage Insulators

High-voltage insulators typically used on transmission towers are insulating materials in a form

designed to (a) support the conductor physically and (b) separate the conductor electrically

from another conductor or object. Materials used for the high-voltage insulators are porcelain

and metal.
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In LRA Section 3.6.2.3.3, the applicant identified surface contamination, cracking, and loss of

material due to mechanical wear as the aging effects/mechanism for high-voltage insulators.

In managing these aging effects, the applicant evaluated these effects as follows:

Surface Contamination - the buildup of surface contamination is gradual and in most areas

such contamination is washed away by rain. Contamination buildup on insulators is not a

problem due to rainfall periodically washing the insulators. 

Cracking - Cracking and breaking of porcelain insulators is typically caused by physical

damage, which is not an aging effect and is not subject to an AMR. A review of plant-specific

operating experience revealed no instances of insulator cracking or failure related to cement

growth at the switchyard. Cracks have also been known to occur with insulators when the

cement binds the parts together enough to crack the porcelain. This phenomenon is known as

cement growth, and is caused by improper manufacturing process or materials that makes the

cement more susceptible to moisture penetration. Therefore, cracking of high-voltage insulators

due to cement growth is not an AERM for the period of extended operation

Mechanical Wear - Mechanical wear is an aging mechanism for strain and suspension

insulators in that they are subject to movement. Although this mechanism is possible, industry

experience has shown that transmission conductors do not normally swing, and when they do

swing, as a result of a substantial wind, they do not continue to swing for very long once the

wind subsides. In the applicant’s evaluation, wear has not been identified during maintenance

activities on BFN insulators.

The staff concluded that the applicant had adequately addressed the aging management for

high-voltage insulators and agreed that no AMP was required for high-voltage insulators.

3.6.2.3.4 Aging Management Evaluations - Transmission Conductors and Connections

Transmission conductors are uninsulated, stranded electrical cables used in switchyards,

switching stations, and transmission lines to connect two or more elements of an electrical

power circuit, such as active disconnect switches, power circuit breakers, and transformers, to a

passive switchyard bus. Typical transmission conductor materials are aluminum conductor steel

reinforced (ACSR).

In LRA Section 3.6.2.3.4, the applicant stated that the portions of transmission conductor within

the scope of license renewal for BFN are all aluminum conductors. All aluminum conductors,

unlike ACSR, are not as susceptible to environmental influences, such as sulphur dioxide

concentration in air. When aluminum corrodes, it forms a protective oxide layer which protects

the underlying material from further corrosion. When the steel core of ACSR corrodes due to

losing its galvanized coating, it will continually corrode causing a decrease in ultimate strength.

The two types of aluminum conductors used at BFN are Orchid, 636 mcm, and Coreopsis, 1590

mcm, which have an ASTM rated strength of 11,000 lbs and 27,000 lbs respectively. The

maximum load permitted by TVA design is 3000 lbs for Orchid and 6000 lbs for Coreopsis,

which results in a margin of 73 percent and 77 percent of the rated strength. Using the same

percent decrease in ultimate strength of 33 percent from the Ontario Hydroelectric test, the

aluminum conductors at BFN would undergo a loss of rated strength of 3663 lbs for Orchid and

8910 lbs for Coreopsis. The new rated strength/margin of rated strength would be 7437 lbs/40
3-360

percent and 18090 lbs/44 percent for Orchid and Coreopsis, respectively. The ultimate

strengths are well above TVA’s maximum design load and the National Electrical Safety Code

margin of ultimate load, 6660 lbs for Orchid and 16200 lbs for Coreopsis, for the original

conductors. Although corrosion of aluminum is minimal, a decrease in ultimate strength due to

corrosion similar to that of the ACSR conductor tested by Ontario Hydroelectric shows that the

aluminum conductors at BFN will continue to perform their intended functions for the period of

extended operation. Further, the applicant stated that transmission and power supply personnel

perform normal maintenance activities on all portions of the switchyard, including transmission

conductors. These maintenance activities have not revealed any aging effects/mechanisms

associated with transmission lines to date. In conclusion, there are no applicable aging effects

that could cause loss of the intended function of the transmission conductors. Therefore, loss of

conductor strength due to corrosion of transmission conductors is not an AERM for the period

of extended operation. 

Industry experience has shown that transmission conductors do not normally swing, and that

when they do swing in substantial wind, they do not continue to swing for very long once the

wind subsides. Therefore, loss of material (wear) and fatigue due to wind loading vibration or

sway of transmission conductors are not applicable AERMs for the period of extended

operation.

The applicant concluded that no AMP is required.

In RAI 3.6-8, dated November 4, 2004, the staff raised a concern regarding the torque

relaxation for bolted connections for transmission conductor and switchyard bus connections. 

In its response, by letter dated December 9, 2004, the applicant stated that bolted switchyard

bus and transmission conductor connections at BFN utilize Belleville washers, which have

torque applied until the Belleville washer is flat, not to exceed limits specified by bolt size. In

accordance with industry guidance EPRI TR-104213, "Bolted Joint Maintenance & Application

Guide," (Section 7.2.2), increased temperature difference in electrical bolted joints is due to

high short circuit ratings or increased current duration. The temperature of an electrical bolted

joint will rise and the stress will increase with increasing current duration. If this temperature

increase is not taken into consideration, loose, failure-prone joints will result. Belleville washers

selected to be flat or almost flat at the installation torque will be used to accommodate the

temperature increase. At BFN, connections are routinely surveyed using infrared scan for hot

spots, which are indicative of a degraded connection. If a hot spot at a connection is

discovered, corrective actions are taken to repair the connection. 

In a supplemental letter, dated January 18, 2005, in response to a staff follow-up question, the

applicant stated that the infrared scans are performed using Transmission Power Supply

Routine Test Schedule. This schedule requires that 500 kV and 161 kV switchyard connections

be surveyed after a modification and routinely surveyed every six months. A review of 

plant-specific operating experience did not reveal any age-related issues associated with bolted

switchyard bus or transmission conductor connections; therefore, torque relaxation of bolted

switchyard bus and transmission conductor connections is not a concern for BFN.

On the basis of its review, the staff’s concern described in RAI 3.6-8 is resolved. 
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The staff concluded that although corrosion of aluminum is minimal, a decrease in ultimate

strength due to corrosion similar to that of the ACSR conductor tested by Ontario Hydroelectric

shows that the all aluminum conductors at BFN will continue to perform their intended functions

for the period of extended operation. Also, based on the response to the staff concern

regarding the torque relaxation for bolted connections, the concern raised in RAI 3.6-8 was

resolved. The staff agreed with the applicant's evaluations and concluded that the applicant had

adequately addressed the aging management for transmission conductors and connections.

The staff also agreed that no AMP was required.

3.6.2.3.5 Aging Management Evaluations - Switchyard Bus

Switchyard buses electrically connect specified sections of an electrical circuit to deliver voltage

or current to various equipment and components throughout the plant. The switchyard bus is

used in switchyards to connect two or more elements of an electrical power circuit such as

active disconnect switches and passive transmission conductors.

In LRA Section 3.6.2.3.5, the applicant identified cracking due to vibration and change in

material properties leading to increased resistance and heating as a result of connection

surface oxidation as potential aging effects for the high-voltage switchyard bus. In managing

the aging effects, the applicant stated that switchyard buses connected to circuit breakers via

flexible aluminum conductors, those supported by insulators and by structural supports such as

concrete footing or steel structures, do not vibrate. Also, the design process for switchyard bus

was engineered to dampen any vibrations that might be induced into the buses. Therefore,

cracking due to vibration is not an applicable aging effect for switchyard buses, and an AMP is

not required.

The applicant also identified aging effects due to change in material properties leading to

increased resistance and heating as a result of connection surface oxidation in aluminum

buses. Solid and flexible connectors and ground straps are highly conductive but do not make a

good contact surface since pure aluminum exposed to air forms aluminum oxide on the surface,

which is nonconductive. To prevent the formation of aluminum oxide on bolted connection

surfaces, the connections have a silver plating and are covered with grease to prevent air from

contacting the connection surface. The grease is a consumable item that is applied to the

connection surface each time a bolted connection is made, thereby precluding oxidation of the

connection surface and maintaining good conductivity at the bus connections. Therefore,

change in material properties leading to increased resistance and heating as a result of

connection surface oxidation of aluminum buses is not an AERM for the period of extended

operation.

In RAI 3.6-7, dated November 4, 2004, the staff requested the applicant to provide a discussion

of the grease replacement program including the frequency. 

In its response, by letter December 9, 2004, the applicant stated that grease is a consumable

item that is applied each time a bolted connection is made, and that it precludes oxidation of the

connection surface and maintains good conductivity at the bus connections. Connections are

routinely surveyed using infrared scan for hot spots, which are indicative of a degraded

connection. In its response, the applicant stated that if a hot spot at a connection is discovered,

corrective actions are taken to repair the connection. In a supplemental response, dated

January 18, 2005, to a staff follow up-question, the applicant stated that the infrared scans are
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performed using the Transmission Power Supply Routine Test Schedule. The Transmission

Power Supply Routine Test Schedule states that 500 kV and 161 kV switchyard connections

are surveyed after a modification and routinely surveyed every six months. On the basis of its

review, the staff found that its concern described in RAI 3.6-7 is resolved.

The staff concurred with the applicant’s evaluation and concluded that no AMP is required to

manage these components. The staff also found that the applicant had adequately addressed

why these aging effects are not applicable aging effects at BFN. The staff agrees that there is

reasonable assurance that the switchyard bus will perform its intended function for the period of

extended operation.

Conclusion. On the basis of its review, the staff found that the applicant had appropriately

evaluated AMR results involving MEAP 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).

3.6.3 Conclusion

The staff concluded that the applicant had provided sufficient information to demonstrate that

the effects of aging of the electrical and I&C components that are within the scope of license

renewal and subject to an AMR will be adequately managed so that the intended function(s) will

be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3).

The staff also reviewed the applicable UFSAR supplement program summaries and concludes

that they adequately describe the AMPs credited for managing aging of the electrical and I&C

components, as required by 10 CFR 54.21(d).
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3.7 Aging Management Review of Unit 1 Systems in Layup for Extended Outage

3.7.1 General Technical Concerns

LRA Section 3.0.1 contains a summary of the evaluation of systems and components subjected

to the Unit 1 layup and preservation program. Staff initially reviewed LRA Section 3.0.1 and

determined that additional information was required. By letter dated February 19, 2004, the

applicant submitted a supplement to the LRA dedicated to the Unit 1 systems in layup during

the extended outage. The staff then issued a series of RAIs to obtain additional information on

the aging management of components subjected to layup conditions during the extended

outage. During the staff review, it was determined that license renewal and plant restart were to

be decoupled and, as a result, plant changes to support restart were to be primarily evaluated

independently as part of the restart effort. The staff focused its layup and preservation program

review on consistency with industry guidance, operating experience including restart

inspections, potential latent aging effects, and the adequacy of one-time inspections to manage

systems not in service during the extended outage.

In addition to the layup and preservation program, a combination of factors related to operating

experience contribute to the way aging effects are managed for systems that were not in

service during the extended outage. Those factors are addressed below.

 • Length of Extended Outage - The Unit 1 extended outage lasted for approximately

twenty years. The length of this extended outage was significantly longer than the

extended outage for either Unit 2 or Unit 3 and is unique in the industry. The extended

outage limited the amount of Unit 1 operating experience available for review and

created abnormal internal environments that contributed to aging. 

 • Limited Operating Experience - The length of the Unit 1 extended outage limited the

amount of operating experience and data available for use in aging management

reviews. Unless there is sufficient data available, one-time inspections may not be

appropriate to manage systems that were not in service during the extended outage. In

response to Item 5.B, discussed below, the applicant provided additional information

concerning Units 2 and 3 restart programs and layup operating experience that is

applicable to Unit 1.

 • Replacement of Components - LRA Appendix F identified that large portions of systems

and components were replaced. The basis for material replacement was either the

result of excessive degradation caused by ineffective layup practices or potential

susceptibility to known degradation mechanisms. The primary concern for aging

management is associated with components that were not replaced.

 • Suspension of Maintenance Rule - By letter dated August 9, 1999, the staff issued a

temporary partial exemption from 10 CFR 50.65 for Unit 1. This partial exemption

provided relief from the Maintenance Rule for systems that were not in service to

support Units 2 and 3. 
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Evaluation Findings

SER Section 3.7 contains the staff evaluation of Unit 1 systems subject to layup conditions

during the extended outage. SER Section 3.7 includes an evaluation of general technical

concerns and system-specific concerns relevant to systems and components subjected to layup

conditions. This evaluation determined that, due to a number of factors including (1) service

conditions resulting from potentially ineffective layup practices, (2) the length of the extended

outage period, (3) limited operating experience, (4) replacement of degraded material due to

ineffective layup practices, and (5) suspension of maintenance activities for systems subject to

layup, periodic inspections would be more appropriate than one-time inspections to manage

aging effects in systems that were subject to layup conditions, where latent aging effects may

have existed. The applicant agreed to a periodic inspection program to manage systems that

were not replaced and were not in service during the extended outage. Details of the program

were not available at the time the SER with open items was prepared. The ACRS interim report

dated October 19, 2005, agreed with staff that additional information was required to support

the staff review of the wet layup sections and periodic inspection program versus one-time

inspection program. 

Unresolved Items

By letter dated October 31, 2005, the staff summarized the following unresolved items related

to the layup and preservation program and requested the applicant to provide additional

information to address unresolved items raised in the committee’s interim report:

 • Providing suitable input for the wet layup sections for the SER so that the staff can write

a cohesive safety evaluation on the applicability of Units 2 and 3 experience to Unit 1.

 • Clarification of One-Time Inspection Program versus Unit 1 Periodic Inspection Program

and One-Time Inspection Program consistency with the GALL Report.

The applicant, by letter dated November 16, 2005, submitted additional information, discussed

below, to close out the unresolved items related to systems subject to the layup and

preservation program.

Restart Programs and Unit 2 and 3 Layup Operating Experience Applicable to Unit 1

BFN Unit 1 was licensed and began initial operation in 1973. Unit 2 began operation in 1974.

Units 1 and 2 operated until March 22, 1975, at which time both units were shut down due to a

fire in the Unit 1 reactor building. Units 1 and 2 resumed operation in 1976 and Unit 3 began

initial operation in 1977. All three units were operated until March 1985, at which time the

applicant voluntarily shut them down to address regulatory and management issues.

Following successful resolution of the management issues and the Unit 2 and common

regulatory issues, Unit 2 was restarted on May 23, 1991. Unit 3 remained in a layup/recovery

mode for approximately 10 years and, following resolution of the Unit 3 regulatory issues, it was

restarted on November 19, 1995. Both units have operated with high capacity factors into the

present time. In the early 1990s, the applicant decided to defer restart of BFN Unit 1. 
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On May 16, 2002, the applicant announced the Unit 1 restart project. As part of the Unit 1

restart project, the applicant is performing the same restart programs and implementing the

same modifications that were previously completed on Units 2 and 3. At restart, Unit 1 will be

operationally the same as Units 2 and 3. The current planned Unit 1 restart date is May 2007.

The Unit 1 systems that perform a required function in the defueled condition, or that directly

support Unit 2 or Unit 3 operation, have been continuously operated and maintained under

applicable technical specifications and plant programs since shutdown in 1985. Examples of

these systems are:

 • fuel pool cooling system

 • portions of the control rod drive (CRD) system

 • portions of the raw cooling water (RCW) system

 • portions of the reactor building closed cooling water (RBCCW) system

 • portions of the residual heat removal (RHR) system

 • portions of the residual heat removal service water (RHRSW) system

 • portions of the emergency equipment cooling water (EECW) system

 • portions of the control air system

The applicant maintained the Unit 1 systems in a physical condition during shutdown similar to

that of Units 2 and 3 during their shutdown periods. The internal operating conditions (e.g.,

water chemistry, flow rate, temperature, etc.) for these systems are the same as those found in

the operating units. These systems have experienced the same aging mechanisms and rates

experienced by similar Units 2 and 3 systems for shutdown conditions. The Units 1, 2, and 3

reactor buildings are one continuous structure, and the external operating environments of the

systems are the same. Even though Unit 1 was in an extended outage, the overall

environmental conditions affecting external surfaces in Unit 1 was maintained consistent with

those of Units 2 and 3. Unit 1 had the normal ventilation systems in service and equipment was

maintained to prevent system leakage so that the equipment was not subjected to aggressive

external conditions.

Unit 3 was shut down for approximately 10 years: from 1985 to 1995. The aging effects on Unit

3 were monitored and addressed prior to startup in 1995. Since 1995, Unit 3 has operated with

a high capacity factor and was uprated 5 percent reactor thermal power in 1998. During this

10-year period of operation, no additional aging effects have been identified attributable to the

10 years of shutdown and layup. Since Unit 1 was laid up and maintained using the same

method as Unit 3, the aging effects during the layup and subsequent operation of Unit 3 would

be expected to apply equally to Unit 1. Unit 2 and 3 operations, including power up-rate, have

not resulted in any unexpected aging mechanisms or rates. Unit 1 operation, following the

shutdown and associated replacements/refurbishments, is expected to exhibit the same aging

mechanisms and rates as Units 2 and 3.

Other Unit 1 systems have been in a layup condition, and prior layup experience from Unit 3

has been applied to Unit 1 license renewal. Some piping systems (or portions of piping

systems) were placed in a "wet layup" under the applicant's Unit 1 layup procedure, including:

 • reactor vessel

 • reactor water recirculation system

 • reactor water cleanup system
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 • portions of the RHR system

 • portions of the core spray (CS) system

 • portions of the feedwater (FW) system

The water chemistry within these Unit 1 piping systems was monitored for compliance with the

water quality requirements. Thus, it would not be expected that a different aging mechanism or

rate would exist in wet layup compared to what would have occurred if the system were in

normal operation. The full scope of BWRVIP inspections have been performed on the Unit 1

reactor vessel as part of the restart project. No adverse effects from the layup period were

found and repairs/replacements not related to layup will be performed as required. The reactor

water recirculation system and reactor water cleanup system piping, both large bore and small

bore, have been replaced. The RHR and CS piping that was in wet layup has also been

replaced. The piping was replaced with the same materials that were used in Units 2 and 3.

Ultrasonic inspections of the feedwater piping have confirmed that the piping does not exhibit

adverse effects from the wet layup period.

Some Unit 1 piping systems (or portions of piping systems) were drained and placed in dry

layup, including:

 • reactor core isolation cooling (RCIC) system

 • high pressure coolant injection (HPCI) system

 • main steam (MS) system

 • portions of the RHR system

 • portions of the CS system

 • portions of the FW system

The exterior of the system/component was maintained at nominal reactor or turbine buildings

ambient conditions which would have been the same in Units 1, 2, and 3. Thus, the dry layup

systems would have experienced aging at a rate less than or equal to that of the corresponding

Unit 2 or Unit 3 system.

Some Unit 1 systems were simply drained with no controlled environment. As a result, portions

of two Unit 1 systems experienced accelerated aging. The accelerated aging of these systems

was previously identified as part of the operating experience from the Unit 3 outage between

1985 and 1995. These were portions of the Unit 1 RHRSW piping inside the reactor building

and some small bore raw cooling water piping. As explained below, this prior Unit 2 or Unit 3

operating experience was incorporated into Unit 1 aging management activities.

The RHRSW piping normally contains raw water from the river. Some of the Unit 1 RHRSW

piping inside the reactor building was drained in 1985, but moisture-laden air remained in the

system. The piping enters/exits from the RHRSW tunnels. Inside the tunnels, the piping is

exposed (i.e., not buried) for approximately 100 feet after which it becomes buried pipe out to

the intake pumping station. The buried piping could not be drained since it is below grade.

Water from the buried section of piping vaporized and entered the drained, above-grade piping

in both the tunnels and the reactor building. Inside the RHRSW tunnels, which are

approximately 20 feet under an earthen berm, the ambient temperature was cool and no

adverse reactions occurred inside the RHRSW piping. However, the RHRSW piping inside the

reactor building experienced normal ambient conditions (i.e., 65 °F to 90 °F). In this warm,

moisture-laden environment, severe corrosion occurred necessitating complete replacement of
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the pipe. As shown by ultrasonic measurements of pipe wall thickness and visual observations

of pipe interiors, this aging effect was not experienced by buried pipe or above grade pipe that

was full of water. This aging effect was restricted to the RHRSW system because it is the only

system that was drained but allowed to contain moisture-laden air. This aging was first

identified on Unit 3 during the Unit 3 recovery and necessitated the replacement of all of the

RHRSW piping inside the Unit 3 reactor building. Based on this lesson learned, the required

pipe replacement was performed for the Unit 1 A and C loops of RHRSW piping, which had

been in a similar layup fashion to the Unit 3 piping.

The small bore RCW piping was drained; however, due to valve leakage, some water was

reintroduced into the system. The combination of water and trapped air set up virtually the

same corrosion effects described above for the RHRSW piping. The Unit 1 recovery project has

visually and ultrasonically inspected the small bore raw water piping and is replacing

approximately 3000 feet of degraded piping.

The Unit 1 restart project did not credit the Unit 1 layup program as the sole means of

establishing the acceptability of the associated piping and components for restart. TVA either

replaced the piping and components or performed appropriate visual and/or ultrasonic

inspections to establish the physical condition of systems and components not being replaced,

as discussed in the applicant’s letter to the staff, dated May 18, 2005. For systems, piping, and

components that were replaced, no layup effects are present. The Unit 1 structures, systems,

and components within the scope of license renewal will be subject to the existing BFN aging

management programs. As a compensatory measure for systems and components not being

replaced, the applicant will perform targeted periodic inspections for the Unit 1 systems that

were not replaced as part of the Unit 1 restart project. These inspections will provide

heightened assurance that existing AMPs address relevant aging mechanisms and effects for

Unit 1.

To ensure there are no latent aging effects as a result of the layup program, BFN will implement

a targeted periodic inspection program for Unit 1 system piping that was not replaced as part of

the Unit 1 restart project. The restart inspection will provide baseline measurements for

targeted inspections to be performed after the unit is returned to operation to verify aging

management program effectiveness and to verify the absence of additional latent aging effects.

The selected sample will be examined by the same or equivalent methodology as used during

Unit 1 restart. Systems (or portions of systems) where periodic inspections will be performed

include MS, FW, RHRSW, RCW, EECW, fire protection, reactor building closed cooling water,

RCIC, HPCI, RHR, and CRD.

After restart in 2007, Unit 1 would have six years of operation remaining in the current license

period, prior to the period of extended operation. The first periodic inspection will be performed

during the current license period. An inspection also will be performed during the period of

extended operation. Subsequent inspection frequency will be determined based on the

inspection results. Inspections will continue until the trend of results provides a basis to

discontinue the inspection. There is reasonable confidence that these periodic inspections will

be capable of detecting degradation caused by potential latent aging effects after the systems

are returned to service.

As part of the AMR in support of the LRA, the applicant recognized that due to the layup period

the Unit 1 operating experience may not be the same as the operating experience for Units 2
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and 3. Thus, as a further compensatory action, the applicant performed evaluations to identify

new aging effects that could be applicable to Unit 1 as a result of the layup environment. The

material groupings and aging effects were established using the same approach utilized in the

rest of the LRA. A detailed evaluation was performed for 19 Unit 1 systems. It was concluded

that there were no new AERMs during the renewal term. A summary of these evaluations is

provided in LRA Section 3.0.1. The applicant provided additional details of this evaluation in its

letter to the staff dated February 19, 2004.

As part of its review of the applicant’s LRA, the staff, by letter dated August 23, 2004, identified

areas where additional information was needed to complete its review. The specific staff

questions were from LRA Sections 3.1, 3.2, 3.3, and 3.4 and were related to aging of

mechanical systems during the extended Unit 1 outage. Listed below are the specific staff

requests for additional information, responses to a number of staff follow-ups, and the LRA.

There were no additional aging effects because of the extended outage of Unit 1 and,

consequently, the applicant claimed that there was no need for any additional aging

management. However, in its letter dated August 23, 2004, the staff said that since the aging of

mechanical systems is highly dependent on the environment maintained during the extended

outage, the staff needed additional information to determine whether:

 • Additional or more severe aging occurred during the extended outage. 

 • Additional aging has been properly identified, evaluated, and managed.

 • The proposed aging management can distinguish the aging during the extended outage

from the aging during future operation.

By the initial set of RAIs dated August 23, 2004, the staff issued general and system-specific

RAIs on the aging of mechanical systems during the extended outage of Unit 1. The applicant

responded to the initial RAIs by letter dated October 8, 2004. The staff reviewed the applicant's

RAI responses and, by letter dated December 16, 2004, requested additional information in a

set of follow-up RAIs. The applicant responded to these RAIs by letters dated January 20, and

January 31, 2005. System-specific RAIs are identified by a system-specific LRA prescript and a

subscript “LP” to designate a layup RAI. Finally, the applicant resolved all the staff issues

regarding the Unit 1 layup by its responses dated May 18, and May 27, 2005. RAIs (3.0-1 LP

through 3.0-11 LP) are applicable to all systems. Given below are the safety evaluations of

technical areas in which the staff had specific concerns relative to the Unit 1 system in the

extended layup and its rationale for acceptance.

3.7.1.1 Wet Layup Program Chemistry Control

In the wet layup for Unit 1, the applicant characterized chemistry for the wet layup water as

flowing, air-saturated, and demineralized. Since in the BFN plant only the systems carrying the

reactor cooling water are included in the wet layup program, the chemistry of the demineralized

water has the same chemistry as the cold shutdown reactor cooling water during normal plant

outages. 

The initial set of general RAIs that are referenced in the discussion that follows constitutes the

staff request dated August 23, 2004. The applicant’s responses are in its letter dated

October 8, 2004.
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In its response to RAI 3.0-1 LP by its letter dated October 8, 2004, the applicant stated that the

other plant systems with different plant chemistries were not included in the wet layup program

because during the Unit 1 outage they were maintained at the operating conditions, including

water chemistries, found in Units 2 and 3 during their normal operations. The cold shutdown

chemistry is specified in the BFN CI-13.1 chemistry program. In the response to the staff's

question the applicant stated that the chemistry control limits implemented during wet layup are

1.5 μS/cm for water conductivity, and 15 ppb for the concentration of chloride and sulfate.

These values are the same as the chemistry control limits utilized in Units 2 and 3 operating in

the cold shutdown mode for refueling and maintenance outages. They are more restrictive than

those in the EPRI Water Chemistry Guidelines specified in BWRVIP-79 and, therefore,

introduce conservatism to the values of the CI-13.1 chemistry program used to specify water

chemistry during the wet layup. 

Since water conductivity and concentration of chlorides and sulfates are the main parameters

characterizing water chemistry, as long as they don't differ, the wet layup and cold shutdown

chemistries are comparable. The staff concurred, therefore, with the applicant that the effect of

chemistry on the components in wet layup and cold shutdown will be similar, and the exposure

of the components to the wet layup chemistries will be similar to the effect of the exposure to

reactor water during the cold shutdown mode of operation. 

3.7.1.2 Replaced Components

LRA Appendix F indicates that significant sections of piping and components have been or will

be replaced prior to Unit 1 restart. It was not clear to the staff whether LRA Appendix F included

all piping that had been or would be replaced prior to restart. The applicant's responses to staff

RAI for LRA Section B.2.1.4, developed during the license renewal audit inspection during the

weeks of June 21 and July 26, 2004, state that repaired or replaced components will receive a

preservice examination in accordance with the requirements of IWB, IWC, or IWD of the

component being repaired or replaced, and prior to returning the system to service. In this

response, the applicant also stated that a re-baseline inspection will be performed on the

remaining Class 1, 2, and 3 components that have not been repaired or replaced. 

In RAI 3.0-9 LP (refurbished vs left in place), dated December 16, 2004, the applicant was

requested to provide information to identify the basis, such as inspections or suspected

degradation, to determine which components need to be replaced and those that do not. Also,

the applicant was requested to clarify whether Appendix F includes all piping and components

that will be replaced prior to startup and to identify in a simplified boundary diagram those

specific sections of piping and components that have recently been or will be replaced and

those that have not been replaced. Further, the applicant was requested to clarify appropriate

layup or cleanliness programs (Refer to RAI 3.0-11 LP) and inspections that are in use and

planned for these components. For those systems or portions of systems and components that

have not been recently replaced and were subject to the extended layup, the applicant was

requested to provide the information requested in RAI 3.0-10 LP (inspection information,

concerning inspections). 

In its response, by letter dated January 31, 2005, the applicant stated that the overall

management philosophy for the Unit 1 restart was to return the plant to operation in a condition

that would support long-term safe and reliable operation of the unit, including the 
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20-year period following license renewal. The applicant further stated that, with this

management philosophy as a basis, it had applied lessons learned from the Units 2 and 3

restart programs and operating experience from all three units in its decision to replace large

portions of key piping systems. The RAI 3.0-9 LP response also states that the Unit 1 restart

project did not credit the layup program as the sole means of establishing the acceptability of

the associated piping and components. Rather, the applicant either replaced the piping and

components or performed appropriate inspections to establish the physical condition of systems

and components not being replaced.

The applicant's response to RAI 3.0-9 LP also states that LRA Appendix F did not include all

piping and components that will be replaced prior to startup. 

In summary, the RAI response concluded that the application of the targeted sampling

inspections and the number of inspections performed has established a high level of confidence

that those systems with any question about their integrity have been identified, inspected, and

properly addressed relative to the replacement or non-replacement of the piping system and/or

its components. The combination of piping replacements identified through previously identified

design issues, operating experience, and other inspections identified approximately 16,000 feet

of large bore piping and 26,000 feet of small bore piping to be replaced. The applicant further

stated that the results of the reviews of operating experience, design issues, and inspections is

provided in Table 1 of the RAI response. The systems listed are those in which significant

piping or components were identified for replacement or refurbishment. In its response, the

applicant presented in Table 2 of the submittal dated January 31, 2005, the details and extent

of the RPV vessel inspection project (VIP) inspections and ASME Section XI re-baseline

inspections that will be conducted on Unit 1 piping systems prior to operation. Finally the

applicant stated that the re-baseline effort is equivalent to performing a complete 10-year

interval's quantity of examinations during the Unit 1 restart effort. 

The staff reviewed the applicant's response to RAI 3.0-9 LP and found the response to be

reasonable and acceptable to clarify the general scope of replaced and refurbished

components including the basis for replacing certain components and not others. The

applicant's response and the staff's evaluation of the response is included in the applicable

section for each system.

The applicant's response to RAI 3.0-9 LP states that LRA Appendix F did not include all piping

and components that will be replaced prior to startup. As a result, LRA Appendix F cannot be

used as a means to distinguish between sections of piping systems and components that have

been replaced and those that have not been replaced. Although the response to RAI 3.0-9 LP

identifies examples of piping systems and components that have been replaced, the staff is

unable to identify specific components that have not been replaced that were subject to layup

conditions. Further, the scope and results of sample inspections, including the sampling basis,

have not been identified. To identify the scope and condition of components subject to

Section XI or VIP inspections, the applicant was requested to identify the sampling basis and

inspection results for piping systems and components subject to layup conditions that have not

been replaced. The staff identified this as an unresolved issue (URI). The staff discussed this

issue with the applicant in follow-up teleconferences. The following is a disposition of the

resolution of the issues in the staff follow-ups, as documented in subsequent applicant

submittals.
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The applicant's response, by letter dated May 18, 2005, clarified its response to RAI 3.0-9 by

stating that a large amount of piping in the drywell and reactor building had been replaced, but

the majority of the piping had been inspected and determined to be acceptable without

replacement. The applicant submitted a table to identify the UT examinations performed to

demonstrate that the existing piping has wall thickness in excess of the manufacturer's

minimum nominal wall thickness (>87.5 percent of nominal) and did not require replacement.

The non-replaced piping inspected included the RHRSW, fire protection, emergency equipment

cooling water (EECW), raw cooling water (RCW), CRD, core spray, feedwater, HPCI, main

steam, reactor core isolation cooling (RCIC), RHR, and RBCCW systems. The locations

chosen for thickness examinations were susceptible areas that may have contained moisture

during layup, or where engineering evaluation determined wear may have occurred. By letter

dated May 27, 2005, the applicant submitted an additional clarification that the susceptible

locations were those areas determined to have the highest potential for service-induced wear or

latent aging effects, which include all types of corrosion. The applicant also clarified that the

inspection techniques utilized evaluate internal conditions and are sensitive to the presence of

unacceptable conditions including wear, erosion, corrosion, including crevice corrosion if

present. By letter dated November 16, 2005, the applicant further clarified that visual and/or

ultrasonic inspections establish the physical condition of systems and components not being

replaced.

The staff reviewed the applicant's response and found the response acceptable. The applicant

clarified that, for piping not replaced that was in a layup condition during the extended outage,

UT examinations had been performed at susceptible locations having the highest potential for

service-induced wear or latent aging effects to demonstrate that adequate wall thickness exists.

There is reasonable assurance that a combination of internal visual inspections and UT

inspection techniques applied are adequate to detect wear, erosion, and corrosion, including

crevice corrosion. There is also reasonable assurance that the Corrective Action Program will

continue to be applied to repair or replace degraded material identified in the inspections prior

to adversely affecting the component intended function. Therefore, all issues related to the staff

issue on replaced components are resolved.

3.7.1.3 Inspections Verification Programs for Layup and Chemistry Control

The SER with open items (OIs) issued on August 9, 2005, loosely used the terms “One-Time

Inspection,” “Restart Inspection,” and “Periodic Inspection.” The ACRS, in its 526th committee

meeting and subsequently in its Interim Report dated October 19, 2005, asked the staff to

provide clarity on these inspection terms and for the final SER to correctly reflect the intent of

the inspections to be performed. Accordingly, the staff sought clarifications on these terms. In

its submittal, by letter dated November 16, 2005, the applicant provided the following definitions

of the inspection terms and clarified its interpretation of these inspections in previous submittals

(RAI 3.0-10 LP, responses to URIs 3.0-2 LP, 3.0-3 LP, and 3.0-4 LP). The staff has since

reviewed the SER with OIs and the final SER reflects the use of these definitions as provided

below:

One-Time Inspection - The applicant's One-Time Inspection Program, B.2.1.29, is

consistent with GALL AMP XI.M32, "One-Time Inspection.” These inspections include

measures to verify that unacceptable degradation of any reactor system component is
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not occurring, validating the effectiveness of existing AMPs or confirming that there is no

need to manage aging-related degradation for the period of extended operation.

Restart Inspection - These inspections are used as a means of verifying the material

conditions of the system(s) of interest prior to the Unit 1 restart. These are performed

prior to restart. These inspections are implemented to return Unit 1 to operation for the

remainder of the current licensed operating period. In its submittal, by letter dated

November 16, 2005, the applicant stated that the restart program does not take credit

for the layup in returning a system to operations and instead depends on inspections

and/or replacement to ensure the components are satisfactory for the remainder of the

current licensed operating period.

Unit 1 Periodic Inspections - These inspections are for Unit 1 systems that have been

shutdown during the extended layup and that were not subsequently replaced as a part

of the Unit 1 restart project. These are targeted periodic inspections that will be

performed on chosen systems after Unit 1 is returned to operation. The intent is to verify

the effectiveness of AMPs and to verify that no additional latent aging effects are

occurring. The staff agreed that the results from the Unit 1 restart inspection can be

used as a first set of data points. These inspections are periodic in nature and

performed prior to and during the period of extended operation until the applicant

determines that no unacceptable degradation is occurring. The applicant’s Unit 1

Periodic Inspection Program is described in AMP.B.2.1.42. 

Systems Maintained in Dehumidified Air - The staff reviewed information presented in LRA

Table 1 supplement dated February 19, 2004, on wet layup and determined that additional

information was required. In RAI 3.0-2 LP, dated August 23, 2005, the staff requested the

following additional information on Table 1 components in dry layup.

For the systems covered by Table 1, the applicant stated that during layup, the systems

were maintained in dehumidified air (60 percent relative humidity) and no additional

aging effects were identified for the layup condition.

NRC Inspection Report 50-259/87-45 reported that in 1987 an acceptable program for

monitoring the relative humidity of all pipe environments had not been finalized and the

extent to which all parts of each system was being continually purged with dry air had

not been established. For example, the standby liquid control system contained moisture

in portions of the system and procedures did not require the system to be monitored for

dryness. Although inadequacies in the program were later resolved, it appears that the

moisture concerns existed for an extended period of time.

Also, industry documents such as EPRI NP-5106, "Sourcebook for Plant Lay-up and

Equipment Preservation," revision 1, identify the need to monitor the effectiveness of the

layup practices. This document states that relative humidity (RH) cannot be used alone

as a layup surveillance technique to evaluate layup effectiveness.

Table 1 does not identify any additional inspections prior to Unit 1 restart to assess the

condition of these systems, and it is not clear if inspections were performed in the layup

condition. In light of the above inspection findings, the recommendations in the industry

documents, and the possibility that parts of this system may not have been continually
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purged with dry air (such that the exact dryness of the surrounding air cannot be

ascertained), discuss any inspections planned before startup to address the potential

aging during the extended outage, and whether these inspections target system low

points where condensate and/or chemicals could accumulate. If inspections have been

performed recently, discuss the results of the inspections. If no inspections to verify the

aging during the extended outage are planned, provide justification for not performing

such inspections. Describe the process that was used to maintain equipment in a dry

layup condition. Discuss how humidity was controlled and maintained below 60 percent,

whether the 60 percent is relative to the coldest portion of the system, the results of any

monitoring and trending of the air quality and humidity, and the corrective actions taken

(including any inspections) for any conditions where the humidity criterion was exceeded

(including corrective actions for the conditions identified in the above inspection report).

Also, Table 1 identifies that future one-time inspections are planned. Discuss how the

one-time inspections will differentiate between the rate of aging in the different

environments (operation vs. shutdown), and discuss whether the one-time inspections

will target locations that are susceptible to aging during normal operation or during

shutdown.

In its response, by letter dated October 8, 2004, the applicant stated that, for components within

the dry layup systems, a one-time inspection (restart, per letter dated November 16, 2005) will

be performed prior to Unit 1 restart to verify the material condition. The applicant further stated

that the One-Time Inspection Program does not differentiate between the rate of aging in

different environments (i.e., normal power operation versus cold shutdown).

Components in a Lubricating Oil Environment. - In RAI 3.0-4 LP, dated August 23, 2004, the

staff requested the following additional information for managing components exposed to a

lubricating oil environment.

For components in a lubricating oil environment, the LRA identified no AERMs. The applicant

was requested to discuss how the lubricating oil was maintained during the extended outage.

The applicant was also requested to discuss whether testing was performed to verify the oil

qualities, including moisture, that would affect aging. If the lubricating oil was drained, the

applicant was requested to discuss the resulting environment and any applicable aging

degradation. The applicant was further requested to discuss any planned inspections to verify

that there was no significant aging during the extended outage.

In its response to RAI 3.0-4 LP, dated October 8, 2004, the applicant stated that no

maintenance or testing was performed for the recirculation system lubricating oil environment

during plant layup. However, this lubricating oil environment is being deleted by design change

notice (DCN) 51219A, which replaces the recirculation pump MG sets with a variable frequency

drive. This modification has been installed on Units 2 and 3 and will be installed on Unit 1 prior

to restart.

The applicant further stated that no maintenance or testing was performed for the reactor core

isolation cooling system or the HPCI system lubricating oil environment during plant layup.
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However the applicant clarified that a sample of components with a lubrication oil environment

within these systems will be inspected for the following aging effects by the One-Time

Inspection Program.

 • carbon and low-alloy steel – loss of material due to general corrosion, crevice corrosion,

pitting corrosion, and galvanic corrosion

 • stainless steel - loss of material due to crevice corrosion and pitting corrosion

 • copper and copper alloys – loss of material due to crevice corrosion, pitting corrosion,

galvanic corrosion, and selective leaching

 • cast iron and cast iron alloys - loss of material due to general corrosion, crevice

corrosion, pitting corrosion, galvanic corrosion, and selective leaching

Systems Exposed to Air/Gas Environment - In RAI 3.0-5 LP, dated August 23, 2004, the staff

requested the additional information for systems exposed to an air/gas environment. Tables 2

and 3 show that some components are exposed to an air/gas internal environment during

normal operation, but state that this environment is not applicable during the extended outage.

These tables state that, due to drainage and system isolation, portions of several systems may

have been exposed to an internal environment of moist air. These tables also state that the

evaluation for treated water encompasses the aging effects for a moist air environment in these

systems. However, Tables 2 and 3 identify additional aging effects for moist air than they

identify for treated water (for example, cracking in low points where condensation and

chemicals can accumulate). Clarify the above discrepancy in Tables 2 and 3. Also, since the

rate of loss of material caused by a moist air environment during layup may be more severe

than a flowing treated water environment, explain why the evaluation of the aging effects for the

treated water environment would encompass that of the aging effects for a moist air

environment in these systems. Tables 2 and 3 state that one-time inspections are planned for

the components that are exposed to an air/gas internal environment. The applicant was

requested to discuss the plans for additional inspections before startup of Unit 1 to evaluate

aging during the extended outage, or inspections that were performed during the extended

outage. If no such inspections are planned or none have been performed, provide justification

that they are not needed and discuss how the one-time inspection will distinguish between the

rate of aging in the different environments.

In its response to RAI 3.0-5 LP, dated October 8, 2004, the applicant stated that Table 2

Systems [RVIs, Feedwater (03), Reactor Vessel Vents and Drains (10), Reactor Recirculation

(68), Reactor Water Cleanup (69) and Control Rod Drive (85)] and Table 3 Systems

[Condenser Circulating Water (27), Gland Seal Water (37), Containment (64), Reactor Core

Isolation Cooling (71), High Pressure Coolant Injection (73), and Core Spray (75)] address the

portions of these systems laid up in a wet environment. Due to closure sequence, closure

timing, and possible leakage past the double isolation valves or two drain valves for these

systems, it is assumed that an air/gas environment with an uncertain amount of moisture was

trapped between the double isolation valves. The trapped moisture between the double valves

was considered the same, (i.e., treated water or raw water) as water flowing through the valves

prior to closure. N/A (not applicable) denotes that this trapped air/gas environment will be

evaluated under the corresponding raw or treated water evaluations.
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The applicant further stated that during layup the temperature of the systems addressed in

Tables 2 and 3 were less than 140 °F. Therefore, crack initiation and growth due to SCC is not

a concern for stainless steels and nickel-based alloys in a wet layup environment. 

The applicant clarified that the evaluation of these moist air environments for the systems

addressed in Tables 2 and 3 identified no additional aging effects other than those identified for

the corresponding raw or treated-water environment. The LRA identified these trapped air

environments for restart inspection because the extent of corrosion could be quantified. It was

not the intent of this AMR to determine the rate of loss of material, but only to verify its material

condition. The applicant stated that the inspection will be performed prior to Unit 1 restart.

Systems Not Part of Wet Layup Program - In RAI 3.0-6 LP, dated August 23, 2004, the staff

requested the following additional information on systems that were not part of the wet layup

program and were exposed to stagnant treated (non-controlled) or raw water.

Table 3 of Evaluation of BFN Unit 1 Lay-up and Preservation Program (submittal dated

February 19, 2004) identifies several systems that were not incorporated into the Unit 1 wet

layup program. These systems were exposed to treated (non-controlled) or raw water during

the extended outage. Table 3 concluded that there is no additional aging management for these

systems. The staff required additional information on the following: (1) discussion of the results

of any water samples, including pH, oxygen levels, aggressive chemical species, biological

activity, and corrosion product levels, (2) discussion whether the systems were stagnant or

periodically flowed, (3) discussion whether the plans for prestartup inspections to determine the

loss of material due to general, pitting, and crevice corrosion, MIC, dealloying, and galvanic

corrosion, or provide justification that such inspections are not needed, and (4) also, discussion

of inspections for the degradation of other materials, such as elastomers and other non-metallic

materials.

In its response to RAI 3.0-6 LP, dated October 8, 2004, the applicant stated:

Condenser Circulating Water System (27) - System 27 was exposed to Tennessee

River water which is the same environment it is exposed to during normal operation.

Without the addition of foreign chemicals the aging effects during normal operation and

during layup are the same.

Gland Seal Water System (37) - The system was drained (ambient air present) with the

gland seal tank in component layup per MPI-1-000-TNK002. However, it was assumed

that the secondary containment loop seal as well as other low points in the system were

not completely drained. The applicant stated that therefore, stagnant treated water

supplied from the condensate system was evaluated for these areas.

Systems (Containment (64), Reactor Core Isolation Cooling (71), High Pressure Coolant

Injection (73), and Core Spray (75) - The torus and torus attached piping for System 64

(i.e., the torus itself) and for Systems 71, 73, and 75 (torus attached piping) saw torus

water maintained by Chemistry Program CI-13.1, Appendix A, Table 20) for extended

periods of time until the torus was drained in the summer of 2003. When filled, the torus

is approximately half full of water with the other half ambient air. The torus water was

not "flowing" in that the only significant water movement was relatively infrequent

transfers into and out of the Unit 1 torus. The torus on an operating unit cannot be
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considered "flowing" either. The operating unit's torus would also be nitrogen-inerted.

Torus coating touch-up/repair is part of the restart work to be completed while the torus

is drained. The torus impurity administrative goals for conductivity, chloride, and sulfate

given in CI-13.1 are 2.0. μS/cm, 75 ppb, and 75 ppb, respectively. The applicant stated

that a review of sampling data showed that the torus water was maintained within the

chemistry specifications and that sampling is performed quarterly. In respect to these

systems, the applicant will perform restart inspection prior to Unit 1 restart to verify the

material condition.

Inspections to be Performed Prior to Restart - In RAI 3.0-7 LP, dated August 23, 2004, the staff

requested the following additional information on Notes 1 and 2 of Tables 2 and 4 concerning

inspections to be performed prior to the Unit 1 restart.

Notes 1 and 2 of Tables 2 and 4 indicate that a restart inspection will be performed prior to

Unit 1 restart for certain components where additional aging effects were identified for the

extended shutdown. Examples include additional aging effects for copper alloy, cast iron, cast

iron alloy, and stainless steel components in system locations where condensation could build

up, and carbon and low-alloy steel in an internal environment. No descriptions of the

inspections were provided. The staff asked the applicant to discuss the proposed inspections,

including scope, method, procedure, parameters monitored and trended, detection of aging

effects, and acceptance criteria, in order to justify the adequacy of the inspections.

The applicant responded to RAI 3.0-7 LP by stating that Note 1 of Tables 2 and 4 identifies the

potential for external general corrosion on carbon and low-alloy steel components that are

normally operated at temperatures greater than 212 °F. This note is applicable to the reactor

vessel (RV), feedwater system (03), and the heater vents and drains system (06). External

surface monitoring is performed in accordance with the Systems Monitoring Program described

in the LRA Section B.2.1.39. The applicant stated that this is the same AMP proposed for

managing external loss of material during the period of extended operation.

The applicant also stated that Note 2 of Tables 2 and 4 identifies the potential for internal loss

of material and cracking (aluminum only) that are normally exposed to either dry air or nitrogen.

The applicant clarified that this note is applicable to the following systems and materials:

Feedwater (03) Copper Alloy

Main Steam (01) Aluminum Alloy

Containment Inerting (76) Carbon and Low-alloy steel

 Stainless Steel

 Nickel Alloy

Copper Alloy

Aluminum Alloy

Cast Iron
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Containment Atmosphere Carbon and Low-alloy steel

Dilution (84) Stainless Steel

Copper Alloy

Aluminum Alloy

Cast Iron

The applicant’s response to RAIs 3.0-2 LP, 3.0-3 LP, and 3.0-4 LP, by letter dated May 27,

2005, clarified that this is a restart inspection.

Management of Galvanic Corrosion - In RAI 3.0-8 LP, dated August 23, 2004, the staff

requested the following additional information on management of galvanic corrosion with the

water chemistry and one-time inspections.

The LRA and the supplement dated February 19, 2004, are not clear regarding the

management of galvanic corrosion. There is the potential for galvanic corrosion during the

extended outage for those systems that were maintained in wet layup, wet non-layup, or moist

air such that condensation and pooling could occur. The LRA and Reference 2 state that

galvanic corrosion is managed through use of the Chemistry Control Program and the

One-Time Inspection Program; however, there were differences in water chemistry during the

extended outage, and the One-Time Inspection Program does not cover galvanic corrosion.

The applicant was requested to describe how galvanic corrosion during the extended outage is

managed. The applicant was also requested to discuss any inspections that are planned to

determine the extent of galvanic corrosion during the extended outage. 

In its response to RAI 3.0-8 LP, dated October 8, 2004, the applicant stated that the Chemistry

Control Program implemented during the extended outage is the same program that BFN uses

on the two operating units during cold shutdown conditions for refueling and maintenance

outages. This extended outage program would consist of CI-13.1 chemistry program controls,

which would continue to be based on the EPRI BWR Water Chemistry Guidelines (TR-103515).

The applicant further stated that the One-Time Inspection Program utilized to verify the

effectiveness of the Chemistry Control Program for preventing loss of material will select the

susceptible locations (where materials with different electrochemical potentials are in contact in

the presence of contaminants). Finally the applicant stated that galvanic corrosion is included in

the One-Time Inspection Program.

In regard to SCC, the staff found the applicant's response to RAI 3.0-5 LP to be reasonable and

acceptable, because the applicant clarified that during layup the temperature of the systems

addressed in Tables 2 and 3 was less than 140 °F in a wet layup environment; therefore, crack

initiation and growth due to SCC is not a concern for stainless steels and nickel-based alloys. In

Tables 2 and 3, SCC is correctly identified as an aging effect for stainless steel during plant

operation at elevated temperatures and SCC is managed by various AMPs.

The staff reviewed the applicant's responses to the above RAIs and determined that additional

information was required concerning the application of the One-Time Inspection Program as a

verification program for layup and chemistry controls. By letter dated December 16, 2004, staff

submitted RAI 3.0-10 LP requesting the applicant to provide additional information on one-time

inspections. 
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The staff reviewed the applicant's responses to the above RAIs and determined that additional

information was required concerning the application of the One-Time Inspection Program as a

verification program for layup and chemistry controls. 

In RAI 3.0-10 LP, dated December 16, 2004, staff stated that industry guidance on recovering

plants placed in extended layups such as Browns Ferry specifically recommends that a

surveillance and assessment program is needed to monitor the effects of outage or storage

conditions on nuclear power plant components, otherwise, evidence of bad layup often will not

even manifest itself until after a plant has returned to power. In pursuing this line of reasoning,

the staff requested that the applicant clarify if one-time inspections may not be appropriate

where degradation is expected to occur or occur very slowly. Specifically, for systems not

associated with the BWRVIP program, the staff wanted the applicant to justify why a one-time

inspection is appropriate for aging management in lieu of periodic inspections. By letter dated

May 27, 2005, the applicant clarified the application of periodic inspections in lieu of one-time

inspections for areas subject to concentration of contaminants during layup. Targeted periodic

inspections are going to be used as compensatory actions to be performed after Unit 1 is

returned to operation to verify that no additional aging effects are occurring. By letter dated

November 16, 2005, the applicant also clarified that the compensatory actions included visual

and/or ultrasonic inspections to establish the physical condition of systems and components not

being replaced. The first periodic inspection will be performed prior to the end of the current

operating period, and the subsequent frequency will be determined based on the outcome of

the first periodic inspections performed. 

The restart inspections can be utilized as a baseline for comparison as identified in the Unit 1

Periodic Inspection Program (SER Section 3.0.3.3.5). Systems and portions of systems for

which periodic inspections will be performed included MS, FW, RHRSW, RCW, EECW, fire

protection, reactor building closed cooling water, RCIC, HPCI, RHR, and CRD. The staff

concurred that application of targeted periodic internal visual and ultrasonic inspections of a

sample of susceptible locations is appropriate to manage potential latent aging effects in Unit 1

systems and portions of systems in layup that were not in operation during the extended outage

and have not been replaced.

These staff dialogues and the ACRS interim report, dated October 19, 2005, led to the

development of a new plant-specific AMP B.2.1.42, “Unit 1 Periodic Inspection Program,” for

BFN Unit 1 components that will not be replaced before restart.

3.7.1.4 MIC

In RAI 3.0-3 LP, the staff requested the following additional information on MIC:

Industry documents such as EPRI NP-5106, indicate that all metals are susceptible to

MIC, especially in stagnant and low flow areas, and microbes in the system should be

monitored by an adequate program at least every week and more often in outages. NRC

Inspection Report 50-259/87-45 identified damage due to MIC had already occurred in

the fire protection system and water samples in the demineralized water system were

planned. Table 2 does not identify MIC as a corrosion mechanism (for example, in the

RWCU and CRD systems for systems intended for wet layup with demineralized water.

Table 3 does not identify MIC as a corrosion mechanism for systems that had no water
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chemistry control (wet, non-layup) during the extended outage. Similarly, Table 4 does

not identify MIC as a corrosion mechanism for components subject to a moist air

environment for extended periods of time. Provide technical justification that MIC is not

an aging mechanism applicable to the stagnant, low flow, and moist air portions of the

mechanical systems. Alternatively, describe how inspections would detect loss of

material caused by MIC at susceptible locations.

In its response to RAI 3.0-3 LP, by letter dated October 8, 2004, the applicant stated:

Table 2 contains Systems [Reactor Vessel and Internals (RVI), Feedwater (03), Reactor

Vessel Vents and Drains (10), Reactor Recirculation (68), Reactor Water Cleanup (69)

and Control Rod Drive (85)] laid up with demineralized water maintained by the

Chemistry Program CI-13.1 and moist air from possible pooling of Chemistry Program

CI-13.1 controlled treated water between drain valves and double isolation valves due to

closure sequence, closure timing, and possible leaking past the valves. Although

portions of these systems had stagnant, low flow, and moist air environments, the

Chemistry Program prevented the presence of microbes necessary to cause MIC

damage. A review of BFN PERs and Work Orders (WOs) (operating experience) did not

identify MIC as a concern in treated water.

Table 3 contains Systems [Condenser Circulating Water (27), Gland Seal Water (37),

Containment (64), Reactor Core Isolation Cooling (71), High Pressure Coolant Injection

(73), and Core Spray (75)].

 1. MIC is identified as a concern for raw water environments regardless of flow rate

in the Condenser Circulating Water System (27). 

 2. The laid up environment for the Gland Seal Water System (37) was treated

(condensate) water and moist air from possible pooling of treated water between

drain or isolation valves and in the loop seals. BFN operating experience did not

identify MIC as a concern in treated water environments. Although there were no

chemistry controls placed on system 37 during layup, raw water or other MIC

agents were not introduced into this system. Therefore, the microbes necessary

for the propagation of MIC were not present in this system during layup.

 3. Treated (torus) water was maintained by the Chemistry Program CI-13.1 during

wet layup. The portions of Systems [Containment (64), Reactor Core Isolation

Cooling (71), High Pressure Coolant Injection (73), and Core Spray (75)] within

the BFN LR scope (torus and torus attached piping) during Unit 1 layup had a

treated water environment and moist air from possible pooling of treated water

(torus water) between drain valves and double isolation valves due to closure

sequence and timing and possible leaking past the valves. Although portions of

these systems had stagnant, low flow, and moist air environments, the Chemistry

Program CI-13.1 prevented the presence of microbes necessary to cause MIC

damage. A review of BFN PERs and WOs (operating experience) did not identify

MIC as a concern in treated water.

Table 4 Systems [Main Steam (01), Condensate (02), Heater Drains and Vents (06),

Containment Inerting (76), and Containment Atmosphere Dilution (84)] contained

treated water or nitrogen prior to Unit 1 layup. These systems were drained during
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layup. These systems were isolated without the introduction of raw water or other MIC

agents. Therefore, the microbes necessary for the propagation of MIC were not present

in these systems during layup.

In a follow up to the general RAI 3.0-10 LP, dated December 16, 2004, the applicant was

requested to clarify why one-time inspections are appropriate for locations with stagnant, low

flow or intermittent flow where MIC is expected on the basis of industry operating experience

due to possibly ineffective chemistry control in these regions. The applicant was asked to

identify the results of any inspections performed in low flow or stagnant areas to demonstrate

that aging effects are not expected to occur or are expected to occur slowly. The applicant was

also requested to provide information on any corrosion monitoring programs for MIC, including

augmented inservice inspection of susceptible areas and corrosion coupons or spool pieces.

Otherwise, the applicant should consider the application of periodic inspections to evaluate

aging effects in these areas.

In the response provided by the applicant to RAI 3.0-10 LP, the staff's concerns relevant to MIC

were not addressed. The staff was concerned that various corrosion mechanisms that would

not be active during operation often appear during layup, as water chemistry controls may not

be as stringent, particularly in stagnant areas. Industry documents such as EPRI NP-5580,

“Sourcebook for Microbiologically Influenced Corrosion in Nuclear Power Plants,” indicate that

additions of corrosion inhibitors and biocides made after layup are unlikely to be effective, as

distribution throughout the system is limited. EPRI NP-5580 also indicates that proper attention

to layup is crucial to avoid MIC and during layup, microbial growth may proceed unimpeded as

fluid forces that remove attached organisms from pipe or vessel surfaces are absent. Staff is

also concerned that corrosion mechanisms that were not active during dry layup may become

active when the systems are wetted and returned to operation. To complete its review, the staff

again requested the additional information previously requested in RAI 3.0-10 LP, on

inspections performed or planned to determine that MIC is not a concern for systems subject to

conditions that promote MIC. The staff originally proposed this as URI 3.0-5 LP. The staff

discussed this issue with the applicant in follow-up teleconferences. The following is a

disposition of the resolution of the issues in the staff follow-ups and subsequent applicant

submittals. 

By letter dated May 27, 2005, the applicant referenced the response to RAI 3.0-10 LP included

in letter dated May 18, 2005, to address MIC. In the applicant's response by letter dated

May 18, 2005, the applicant clarified that the raw water piping is susceptible to MIC and the

primary method used for MIC control is routine injection of biocides. The applicant stated that

this treatment method has been effective in controlling MIC for in-service raw water piping. For

systems not in service during the extended outage the piping was inspected and evaluated. The

applicant stated that the majority of the raw water piping was in a dry layup condition and has

been inspected and found to have adequate wall thickness, with two exceptions. As identified

by the applicant, the portions of the RHRSW system in the reactor building that contained

moisture required replacement due to inadequate wall thickness. Similarly, approximately 3,000

feet of large bore and small bore RCW piping requires replacement due to inadequate wall

thickness.

The staff reviewed the applicant's response and found the response acceptable. The applicant

clarified that raw water piping susceptible to MIC during the extended outage has either been

replaced or inspected to verify that adequate wall thickness exists. In addition, there is
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reasonable assurance that the mitigative programs will be effective to preclude future MIC and

potential latent aging effects due to MIC in all systems subject to layup during the extended

outage, including systems containing raw water, will be detected and corrected by future

periodic inspections. All issues related to RAI 3.0-5 LP are resolved.

3.7.1.5 Transition from Layup Program to System Cleanliness Verification Program

The system cleanliness verification program is not addressed in the LRA nor in February 19,

2004, letter containing the attachment, "Evaluation of BFN Unit1 Layup and Preservation

Program.” NRC quarterly integrated inspection report 05000259/2004006 states that on

March 22, 2004, the applicant decided to remove all Unit 1 systems from layup. This decision

was based on the need to transition to a system Cleanliness Verification Program. According to

NRC quarterly integrated inspection report 05000259/2004007, this program is intended to

replace the previous equipment layup program that has been in place since the unit was

shutdown. This report also stated that, under the new program, the assigned system and

component engineers, along with chemistry personnel, would perform a series of inspections of

Unit 1 systems to identify any system degradation or special requirements to support Unit 1

recovery. It is the staff’s understanding that transition to the newer program was still in progress

at the time of the inspection period on July 10, 2004.

In RAI 3.0-11 LP, dated December 16, 2004, the applicant was requested to clarify if this series

of inspections is part of the One-Time Inspection Program that is going to be implemented prior

to Unit 1 restart. If the one-time inspections are different from or in addition to the cleanliness

verification program inspections, the applicant was requested to so clarify. Also, it is not clear to

the staff if this system cleanliness verification program includes inspections on components that

were replaced or repaired. The applicant was requested to provide additional information as to

what type of inspections have been or will be performed by the system Cleanliness Verification

Program (CVP).

In its response to RAI 3.0-11 LP, the applicant stated that inspections performed under the CVP

are not part of the one-time LRA inspections or credited as part of the license renewal

application. The applicant clarified that to facilitate Unit 1 restart activities, Unit 1 systems have

been removed from the layup program. It is not possible to maintain the layup program and

perform the required field work needed for restart of Unit 1. 

The applicant stated that the purpose of the CVP is to (1) verify, through cleanliness verification

of all internal and external surfaces of piping systems and metallic components, that the

requirements for fluid (gas or liquid) system internal and external cleanliness are in accordance

with TVA and industry standards; and (2) provide the detailed remedial cleaning instructions for

internal and external surfaces of piping systems and metallic components whose internal and

external surface cleanliness does not meet respective cleanliness criteria as a result of

extended layup, or work activity. 

The CVP activities are applicable to all Unit 1 steam, water, air, gas and oil piping systems and

components that receive a formal return to service in accordance with the Unit 1 Restart Test

Program System Preoperational Checklist. The applicant clarified that the only Unit 1 systems

excluded from this program are those that are currently in service or have been in service

supporting Units 2 and 3. 
3-382

The applicant also stated that CVP inspections are performed to ensure internal and external

system cleanliness and that foreign material control program requirements are met. Visual

inspections aided by boroscopes are performed to identify any needed remedial cleaning or

flushing activities. If inspection reveals evidence of piping degradation, a problem evaluation

report is initiated and entered into the Corrective Action Program. An engineering evaluation is

performed to ensure that the system is capable of operation through the extended period. The

applicant further stated that the inspections performed by the CVP are not a part of the 

one-time LRA inspections; nor are they a part of the license renewal process.

The staff reviewed the applicant's response to RAI 3.0-11 LP and found that the response is

reasonable and acceptable because the applicant provided sufficient information on system

cleanliness inspections and clarified that cleanliness inspections are different from the one-time

inspections credited for license renewal. The applicant credits visual inspections aided by

boroscopes to detect and correct degradation during the transition period between layup and

restart. Both external and internal inspections are performed to industry standards as part of the

system Cleanliness Verification Program. Internal inspections to recognized industry standards

should be adequate to detect degradation during the transition period between layup and

restart. 

3.7.2 Reactor Vessel internals and Reactor Coolant System

3.7.2.1 Reactor Recirculation System (068)

Summary of Technical Information in the Application. 

The applicant provided a summary of its evaluation of the Unit 1 layup and preservation

program in LRA Section 3.0.1. The applicant's specific AMRs for the reactor recirculation

system (068) of Unit 1 that are exposed to wet layup environment are given in Table 2 of the

applicant's letter, "Evaluation of the BFN Unit 1 Lay-up and Preservation Program," Revision 1,

dated February 19, 2004. The applicant identified several aging effects of the applicable

materials of the reactor recirculation system that are exposed to the wet layup environment.

These components extend from the reactor vessel outlet nozzle, through the valves and pumps,

to the reactor vessel inlet nozzle. Also included are components within the reactor recirculation

motor generator set oil system and instrument tubing and piping outside the drywell.

In Section 4.0 of chapter "Mechanical System/Program Evaluation Detail-Wet Layup Program

Unit 1" of the February 19, 2004, letter, the applicant identified the following aging effects

associated with stainless steel, carbon steel, and copper-alloy materials that are exposed to a

treated-water environment during the wet layup period of Unit 1. 

 • general corrosion

 • crevice corrosion

 • pitting corrosion 

 • galvanic corrosion

 • selective leaching

In Table 2, "Evaluation of BFN Unit 1 Layup and Preservation Program," Revision 1, the

applicant provided a summary of AMRs for the reactor recirculation systems of Unit 1 that are
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within the boundary of the wet layup program. These AMRs are not addressed in the GALL

Report. The staff also identified areas where additional information or clarification was needed.

The staff's evaluation of the applicant's responses to those RAIs is included below.

Crevice and Pitting Corrosion. The staff, after the review of the applicant's submittal,

determined that aging effects due to crevice and pitting corrosion of the reactor recirculation

system, are possible unless stringent control on the RCS water is implemented during the wet

layup period. The aging effects due to crevice and pitting corrosion on the reactor recirculation

system materials (i.e., carbon steel, stainless steel, and copper-alloy materials) can be more

pronounced when they are exposed to stagnant conditions during the wet layup rather than the

regular service condition. The applicant stated that the reactor recirculation system materials

will experience crevice and pitting corrosion when the dissolved oxygen content in the RCS

water exceeds 100 ppb, and the choride and sulphate contents exceed and 150 ppb with

stagnant or low flow conditions during the wet layup period. In Table 2 of the applicant's

submittal, "Evaluation of the BFN Unit 1 Lay-up and Preservation Program," Revision 1, the

applicant claims that it will manage this aging effect by CI-13.1 Chemistry Control Program. The

cold shutdown impurity limits for conductivity, chloride, and sulfate given in CI-13.1 (1.5. μS/cm,

15 ppb, 15 ppb) are more restrictive than those given in the EPRI BWR Water Chemistry

Guidelines (TR-103515-R2, page 4-6, Table 4-2) for "Reactor Water - Cold Shutdown." The

staff found that the implementation of the Chemistry Control Program would enable the

applicant to subsequently mitigate the crevice and pitting corrosion in the reactor recirculation

system components.

Selective Leaching. The staff, after the review of the applicant's submittal, determined that the

aging effect due to selective leaching of reactor recirculation system components fabricated

from copper-alloy material used in a treated-water environment require aging management for

selective leaching for the period of extended operation for the Unit 1 layup systems. The

applicant stated that copper-zinc alloys containing greater than 15 percent zinc in a

treated-water environment are susceptible to selective leaching, while copper alloys with a

copper content in excess of 85 percent resist dezincification. The applicant currently credits the

One-Time Inspection Program and the Selective Leaching of Materials Program; but, requires

no additional aging management of Unit 1 due to the wet layup condition as shown in Table 2 of

its February 19, 2004, letter. The staff found this acceptable because the One-Time Inspection

Program and Selective Leaching Program will be just as effective to detect and manage

selective leaching on the Unit 1 wet layup systems as it is on systems not in wet layup in BFN.

Loss of Material Due to General Corrosion. General corrosion of carbon and low-alloy steel in

treated water is an aging mechanism that must be managed for the period of extended

operation for the Unit 1 layup Systems. The applicant identified the Chemistry Control Program,

the One-Time Inspection Program and ASME Section XI Subsections IWB, IWC and IWD

Inspection Program. The Chemistry Control Program mitigates general corrosion by minimizing

dissolved oxygen, thus, reducing the effect of general corrosion as an internal aging effect. The

applicant’s one-time inspection will ensure that general corrosion has been controlled and the

ASME Section XI inspections will ensure that the affected components continue to perform their

required function during the period of extended operation.

Loss of Material Due to Galvanic Corrosion. Galvanic corrosion of carbon and low-alloy steel in

treated water is an aging mechanism that must be managed for the period of extended

operation for the Unit 1 layup systems. The applicant identified the Chemistry Control Program,
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the One-Time Inspection Program, and ASME Section XI Subsections IWB, IWC and IWD

Inspection Program. The Chemistry Control Program minimizes galvanic corrosion by

controlling dissolved oxygen, chlorides, conductivity, and PH. The applicant’s one-time

inspection will provide verification that galvanic corrosion has been managed during the Unit 1

wet layup period and the ASME Section XI inspections will ensure that the affected components

continue to perform their required function during the period of extended operation.

As a result of the Unit 1 restart efforts, the applicant is in the process of replacing several

components and is conducting numerous inspections. Below is a description of some of the

restart efforts that impact the recirculation system and provide additional confidence that Unit 1

will be adequately managed so that the intended functions of the reactor recirculation system

are maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3).

Recirculation System Piping. During the restart efforts on Unit 1, several components will be

replaced, obviating the need to be concerned about degradation of these components during

the wet-layup period. In RAI 3.1.2.4-6, dated December 1, 2004, the staff requested that the

applicant discuss whether the recirculation system piping had experienced any cracking in the

past. The applicant responded in part that no recirculation system piping welds less than NPS 4

were identified as having cracking or crack indications in the inservice records. The applicant

also stated that during the Unit 1 recovery efforts the recirculation system piping greater than

NPS 4 is being replaced with IGSCC-resistant piping (316NG or 316L). According to the

applicant, this includes all welds that it identified as having IGSCC indications. In order to clarify

the extent of piping replacement in the reactor recirculation system, the staff requested the

applicant to discuss replacement of piping less than NPS 4 in a follow up to RAI 3.1-1. The

applicant responded by letter dated January 20, 2005, and stated that all piping of the reactor

recirculation system (068) is being replaced with the exception of small sections of the 3/4-inch

and 1-inch piping on each side of the system 068 penetrations on LR drawing 1-47E817-1-LR.

Heat Exchangers. All heat exchangers that are not being replaced due to design changes are

being inspected. Inspection will include 100 percent eddy current testing of tubes. SR heat

exchangers will have their shell casing ultrasonically tested for thickness. The applicant also

stated that visual inspections of the heat exchangers for pitting or erosion are performed when

manway covers are removed or the connecting piping is replaced.

Valves. Valves within the piping systems were reviewed to determine whether the valves

needed to be replaced or refurbished. During the Unit 1 restart effort, approximately 3000

valves will be replaced. The applicant also estimated that approximately 1000 valves will be

tested and refurbished.

Conclusion. The staff, after reviewing the applicant's submittal, concluded that the

aforementioned aging effects do not cause any additional degradation of components in the

reactor recirculation system during the wet layup period at Unit 1. The staff believes that the

relevant critical variables that may cause any additional degradation due to these aging effects

are adequately managed during the wet layup period. If by chance some additional degradation

occurred in the reactor recirculation system, the applicant’s restart activities should be effective

in identifying and correcting issues prior to start up. 
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3.7.2.2 Reactor Vessel (RV), Reactor Vessel Internals (RVIs)

 Summary of Technical Information in the Application. 

The applicant's specific AMRs for the RV and RVIs at Unit 1 that are exposed to the wet layup

environment are given in Table 2 of the applicant's supplemental submittal, dated February 19,

2004, "Evaluation of the Unit 1 Layup and Preservation Program, Revision 1.” The applicant

identified several aging effects applicable to the materials in the RV and RVIs that are exposed

to the wet layup environment during the extended outage. 

The components in the RV and RVIs include RV attachment welds, reactor closure studs and

nuts, RV heads, flanges and shells, RV nozzles and safe ends, RV penetrations, RVIs core

shroud and core plate, RVIs core spray lines and spargers, RVIs dry tubes and guide tubes and

RVIs jet pump assemblies. 

In Section 4.0 of the supplemental submittal dated February 19, 2004, the applicant evaluated

the following aging effects that are associated with stainless steel materials when they are

exposed to RCS treated-water environment during the wet layup period at Unit 1. 

 • pitting corrosion 

 • crevice corrosion

 • MIC

 • SCC

 • thermal aging

 • neutron embrittlement

 • stress relaxation

 • particulate fouling

Technical Staff Evaluation of Aging Effects

In Table 2 of the supplemental submittal dated February 19, 2004, the applicant provided a

summary of AMRs for the RV and RVIs at Unit 1 that are within the boundary of the wet layup

program. These AMRs are not addressed in the GALL Report. The staff also identified several

areas where additional information or clarification was needed. The staff issued RAIs to the

applicant regarding the wet layup issues. The staff's evaluation of the applicant's submittal and

its responses to the RAIs are addressed below. 

Pitting and Crevice Corrosion. The staff, after the review of the applicant's submittal,

determined that the aging effects due to pitting and crevice corrosion of the RCS pressure and

non-pressure boundary components could have been significantly affected during the wet layup

period, unless stringent control on the RCS water was implemented during the wet layup period.

The RVs and RVIs could have been subjected to more frequent stagnant conditions during the

wet layup period than during regular service conditions. Therefore, aging effects due to pitting

and crevice corrosion on the RV and RVIs materials can be more pronounced when they are

exposed to stagnant conditions during the wet layup period. The applicant stated that the RV

materials may have experienced pitting when the RCS water dissolved oxygen concentration

exceeded 100 ppb and the chloride or sulfate concentrations exceeded 150 ppb during the wet

layup period. However, crevice corrosion could have occurred when the dissolved oxygen
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content in the RCS water exceeded 100 ppb. In Table 2 of the submittal, the applicant stated

that it managed these aging effects by CI-13.1 Chemistry Program. The cold shutdown impurity

limits for conductivity, chloride and sulfate given in CI-13.1 [1.5 μS/cm), 15 ppb, 15 ppb] are

more restrictive than those given in the EPRI BWR Water Chemistry Guidelines

(TR-103515-R2, page 4-6, Table 4-2). These guidelines are applicable for RCS water when the

plant is in cold shutdown condition. 

In RAI 3.0-1 LP(a), the staff requested that the applicant identify the differences between the

chemistry program(s) implemented in the RCS system during the wet layup period at Unit 1 and

the chemistry program to be implemented in the RCS system at Unit 1 during the period of

extended operation.

In its response to NRC RAI 3.0-1 LP(a), by letter dated October 8, 2004, the applicant stated

that the RCS water was monitored for conductivity, chloride and sulfate concentrations in

accordance with the requirements of CI-13.1. The chemistry control limits implemented during

the wet layup period at Unit 1 are the same as the chemistry control limits utilized by Units 2

and 3 during cold shutdown conditions for refueling and maintenance outages. The selected

BFN impurity limits are consistent with the limits for cold shutdown that are contained in

BWRVIP-79, "BWR Water Chemistry Guidelines," (EPRI Report TR-103515-R2,

February 2000), which is consistent with the GALL AMP XI.M2, "Water Chemistry," and the

Chemistry Control Program. The chemistry program implemented during the period of extended

operation for Unit 1 is the same program as that for Units 2 and 3 during power operation

conditions. 

The staff reviewed the response and found that implementation of a Chemistry Control Program

that is more restrictive than GALL AMP XI.M2, would enable the applicant to mitigate pitting

corrosion effectively in the RV and RVIs during the wet layup period at Unit 1. 

The staff contended that if the dissolved oxygen content exceeded 100 ppb during the wet

layup period, crevice corrosion of the RVIs could have occurred. In order to ensure that crevice

corrosion is not occurring in the RV and RVIs, the staff requests that the applicant confirm that

the dissolved oxygen content in the RCS water did not exceed 100 ppb during the wet layup

period. This staff issue was resolved by the applicant’s subsequent response and submittals

(see SER Section 3.7.2.2 below).

In RAI 3.0-1 LP(b), the staff requested that the applicant discuss the criteria (e.g., guidelines)

used to maintain the chemistry of the fluid in the wet layup systems, the chemistry parameters

monitored, and the frequency of the monitoring/trending. 

In its response to RAI 3.0-1 LP(b), by letter dated October 8, 2004, the applicant stated that

during the wet layup period reactor water was monitored in accordance with the requirements

specified in Table 5 of the CI-13.1. The impurity limits for conductivity, chloride, and sulfate

given in CI-13.1 were 1.5. μS/cm, 15 ppb and 15 ppb, respectively. The applicant also stated

that sampling was performed once every two weeks, and the monitoring and trending results

demonstrated that the RCS water was maintained within its impurity limits during the wet layup

period. 

Since the verification frequency of the RCS water chemistry is once every two weeks during the

wet layup period, the staff determined that pitting and crevice corrosion in the RV and RVIs can
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occur if they are exposed to higher concentrations of chlorides and sulfates due to a leak in the

primary systems. The staff issued follow-up RAI 3.0-1 LP (b), requesting that the applicant

provide information regarding its past experience related to any sudden increase in

concentration of chlorides and sulfates in the RCS water during the wet layup period, and the

corrective actions taken to prevent impurities migrating into crevices in the RV and RVIs. The

staff further requested that the applicant identify the crevice locations in the RV and RVIs that

will not be replaced and where accumulation of aggressive ions such as chlorides and sulfates

inside the crevice could have enhanced the likelihood of pitting and crevice corrosion during the

wet layup period at Unit 1. The staff also requested that the applicant provide information

regarding the type of inspection it intends to use in identifying the aging effects due to pitting

and crevice corrosion in the RV and RVIs prior to Unit 1 restart and during the extended period

of operation.

In its response to follow-up RAI 3.0-1 LP(b), by letter dated January 31, 2005, the applicant

stated that during the wet layup period at Unit 1, the RCS water was operated as a closed-loop

system using the RWCU system. Impurities (i.e., chlorides and sulfates) in the make-up water

system at Unit 1 can potentially contaminate the RCS water. Condensate water was used for

make-up water. If any impurities were detected, a new ion exchange resin would be applied to

the RWCU system demineralizer. Since the RCS water would be processed approximately 1.5

times a day through the RWCU system, the applicant claimed that verification of RCS water

chemistry every two weeks would be adequate in detecting the impurities. The applicant found

no occurrences of sudden increase in concentration of impurities (i.e., chlorides and sulfates) in

the RCS water during the wet layup period at Unit 1. The applicant stated that the impurities

were maintained at acceptable levels (< 15 ppb) during the wet layup period. Based on

stringent chemistry control, the applicant claimed that the RV and RVIs were less susceptible to

pitting corrosion during the wet layup period. The applicant also proposed to perform

inspections (discussed below) on the RV and RVIs prior to Unit 1 restart. 

The staff reviewed the response and found it acceptable because the applicant implemented a

Chemistry Control Program that is more restrictive than GALL AMP XI.M2. Since the impurities

(i.e., chlorides and sulfates) in the RCS water were kept below the acceptable levels of 15 ppb,

the RV and RVIs were less susceptible to pitting during the wet layup period. 

In RAI 3.1-3 LP, the staff requested that the applicant provide details on any inspection plans

for the RV and RVIs prior to Unit 1 restart. 

In its response to RAI 3.1-3 LP, by letter dated August 23, 2004, the applicant stated that the

RV and its components will be inspected in accordance with the requirements of the ASME

Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program. The RVIs will be

inspected in accordance with the requirements of relevant BWRVIP guidelines. The following

list includes the RVIs and the applicable BWRVIP reports approved by the staff (with the

exception of BWRVIP-76).

• BWRVIP-18-----Core Spray 

• BWRVIP-25-----Core Plate

• BWRVIP-26-----Top Guide

• BWRVIP-27-A--Standby Liquid Control

• BWRVIP-38-----Shroud Support

• BWRVIP-41-----Jet Pump
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• BWRVIP-47-----Lower Plenum (CRD, Incore)

• BWRVIP-48---- Vessel Attachment Welds

• BWRVIP-49-----Instrumentation Penetrations

• BWRVIP-76-----Core Shroud (under staff's review)

The applicant stated that the core shroud access hole covers will be examined in accordance

with GE SIL 462, Revision 1. The applicant stated that the access hole covers for Unit 1 are

cracked essentially 360 degrees around and will be replaced prior to Unit 1 restart.

The staff reviewed the response and found it acceptable because of the implementation of the

ISI program, which is an established AMP that is based on compliance with the staff's ISI

requirements in 10 CFR 50.55a. This program has appropriate requirements for inspecting the

RV components prior to Unit 1 restart. The RVIs will be inspected in accordance with the

requirements of applicable BWRVIP guidelines, thus enabling the applicant to identify pitting

corrosion in the RVIs in a timely manner so that proper corrective actions could be taken to

ensure their structural integrity prior to Unit 1 restart. 

The staff’s position is that if the dissolved oxygen content exceeds 100 ppb during the wet layup

period, crevice corrosion of the RVIs could occur. In order to ensure that crevice corrosion is

not occurring in the RV and RVIs, the staff requests that the applicant confirm that the

dissolved oxygen content in the RCS water did not exceed 100 ppb during the wet layup period

(Unresolved Item 3.7.2.2-1 in the applicant’s response dated May 27, 2005). The staff followed

this issue with the applicant in follow-up teleconferences. The following is a disposition of the

resolution of the issues in the staff follow-ups and subsequent applicant submittals.

To confirm that the crevice locations in RVIs are not susceptible to corrosion, the staff requests

that the applicant identify these locations and provide information as to how it uses the

applicable BWRVIP inspection guidelines to detect any crevice corrosion of the RVIs prior to

Unit 1 restart. (Unresolved Item 3.7.2.2-2 in the applicant’s response dated October 13, 2005).

In its response, by letter dated May 27, 2005, the applicant indicated that during the wet layup

period the RCS water was open to the atmosphere; therefore, the dissolved oxygen content in

RCS water was expected to increase to 8 ppm. The staff requested that the applicant provide

information regarding the implementation of the BWRVIP inspection guidelines to detect crevice

corrosion of the RVIs prior to Unit 1 restart. In its response, the applicant also listed the

following systems that have crevice type configurations, and proposed to implement appropriate

BWRVIP inspection guidelines to monitor the aging effect due to crevice corrosion in these

systems. The systems with crevice configuration include: (1) core spray; (2) jet pump assembly;

(3) top guide; (4) control rod guide, and (5) core plate. The staff found the applicant's response

acceptable because the inspection frequency and the inspection techniques specified in the

respective BWRVIP guidelines, and the augmented inspection for the top guide (see TLAA

SER Section 4.2.8.2) will adequately identify the crevice corrosion in the RVIs components so

that corrective actions can be taken prior to Unit 1 restart, and after inservice inspection in

accordance with BWRVIP guidelines. The staff considers these issues resolved.

Conclusion. The staff, after reviewing the applicant's submittal, and its responses to RAIs,

concluded that the aging effect due to pitting corrosion had not caused any degradation of the

RV and RVIs during the wet layup period at Unit 1. If any additional degradation occurred due

to pitting corrosion in the RV and RVIs, the applicant's restart activities should be effective in
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identifying and correcting issues prior to Unit 1 restart. The staff concluded that the aging effect

due to crevice corrosion in the RVs and RVIs during the wet layup can be ascertained.

The applicant stated that the following aging effects are less likely to occur in the RV and RVIs

and, as such, they do not require an AMP. This assessment was based on the fact that the

conditions (stated below for each aging effect) in the RV and RVIs are less conducive for these

aging effects to cause any degradation during the wet layup period. 

 • MIC

 • SCC

 • thermal aging

 • neutron embrittlement

 • stress relaxation

MIC. In Table 2 of the submittal, the applicant stated that MIC is unlikely to occur in treated

water systems where sulfates are less than 150 ppb, and at temperatures greater than 210 °F

or pH greater than 10. The applicant claimed that Unit 1 layup systems contain treated water

with little or no contamination. A review of BFN's work orders identified no instances where MIC

was a failure mechanism for any components in the scope of license renewal for the RV and

RVIs. The applicant stated that the RV and RVIs will not be affected by the aging effect due to

MIC during the wet layup period. Based on the review of the submitted information, and in the

absence of any evidence that indicates contamination in Unit 1 systems during the wet layup

period, the staff believes that the RV and RVIs have not degraded due to MIC during the wet

layup period at Unit 1.

Stress Corrosion Cracking. In Table 2 of the applicant's submittal, the applicant stated that for

treated-water environments, stainless steel and nickel alloys are susceptible to SCC in the

presence of chlorides or sulfate concentrations greater than 150 ppb and when the dissolved

oxygen exceeds 100 ppb at temperatures greater than 140 °F. The applicant claimed that

limiting the chloride and sulfate concentrations to less than 150 ppb, and the dissolved oxygen

to less than 100 ppb eliminates the potential for SCC of the stainless and nickel alloys’ internal

surfaces. The normal temperature of the RV systems is less than 140 °F during the wet layup

period. The applicant concluded that the RV and RVIs have not degraded due to SCC during

the wet layup period.

In NRC RAI 3.0-1 LP b(4), the staff requested that the applicant provide information related to

any addition of hydrogen inside the vessel and RCS systems to reduce the oxidizing nature of

RCS water, which in turn reduces the occurrence of SCC of the RV and RVIs. In its response to

RAI 3.0-1 LP b(4), by letter dated January 31, 2005, the applicant stated that no hydrogen was

added to any of the RCS systems during the wet layup period. However, hydrogen will be

added to the RCS systems during normal power operation at Unit 1. The staff found that the

applicant's response is acceptable because during the wet layup period, the temperature of the

RV and RVIs was less than 140 °F; therefore, the RVI and RVIs were less likely to experience

SCC. 

In RAI 3.0-1 LP b(5), the staff requested that the applicant provide information related to the

measurement of ECP of the reactor coolant, which will provide information on the oxidizing

nature of the RCS water. In its response to RAI 3.0-1 LP b(5), by letter dated January 31, 2005,

the applicant stated that no ECP measurements were made during the wet layup period. Since
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the RCS temperature is kept below 140 °F during the wet layup period, aging effects of the RV

and RVIs due to SCC is less likely. The staff found that the applicant's response of not

measuring ECP values of the RCS water during the wet layup period is acceptable because

SCC is less likely to occur when the RCS temperature was kept below 140 °F during the wet

layup period at Unit 1.

Thermal Aging. The applicant stated that wrought austenitic stainless steel is not susceptible to

thermal embrittlement when exposed to normal nuclear plant operating environments. However,

CASS materials are susceptible to thermal embrittlement depending upon material composition

and time at high temperatures. CASS materials subjected to temperatures greater than 482 °F

are susceptible to thermal aging. The normal temperature of the RCS system during the wet

layup period at Unit 1 is less than 482 °F; therefore, the applicant claimed that CASS materials

did not experience degradation due to thermal aging during the wet layup period. The staff,

after the review of the submittal, concluded that the CASS materials did not degrade due to

thermal aging during the wet layup period.

Neutron Embrittlement. The applicant stated that the carbon and low-alloy steel RV beltline

region of the Unit 1 was not subjected to neutron fluence during the wet layup period; therefore,

the degradation due to neutron embrittlement is not considered a potential aging effect. The

staff agrees with this disposition, and concluded that the RV beltline region did not degrade due

to neutron embrittlement during the wet layup period.

Stress Relaxation. The applicant stated that stress relaxation is a potential aging mechanism for

bolting/fasteners with the RV and RVIs. The applicant claimed that the bolting/fasteners did not

degrade due to stress relaxation during the wet layup period. The staff believes that during the

wet layup period at Unit 1 the bolting/fasteners were not subject to any service-related loading

conditions; consequently, they did not experience degradation due to stress relaxation. 

Conclusion. The staff, after reviewing the applicant's submittal and its responses to RAIs,

concluded that the aging effect due to pitting corrosion did not cause any degradation of the RV

and RVIs during the wet layup period at Unit 1. If any additional degradation occurred due to

pitting corrosion in the RV and RVIs, the applicant's restart activities should be effective in

identifying and correcting issues prior to Unit 1 restart. The staff concluded that the aging effect

due to crevice corrosion in the RVs and RVIs during the wet layup can be ascertained. 

The staff, after reviewing the applicant's submittal, concluded that other aging effects did not

cause any degradation in the RV and RVIs during the wet layup period at Unit 1. The staff

believes that the relevant critical variables that cause any degradation due to these aging

effects were adequately controlled during the wet layup period. These critical variables include

reactor water temperature, RCS water chemistry, neutron fluence and any service-induced

loading conditions. Based on the information provided by the applicant thus far, the staff

concluded that these critical variables stayed dormant and did not cause any degradation of the

RV and RVIs during the wet layup period. If any additional degradation occurred in the RV and

RVIs, the applicant's restart activities should be effective in identifying and correcting issues

prior to Unit 1 restart.
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3.7.3 Engineered Safety Features

3.7.3.1 Engineered Safety Features Systems in Dry Layup

3.7.3.1.1 High Pressure Coolant Injection System

Technical Staff Evaluation. The technical staff reviewed the AMR of the HPCI system to

determine whether the proposed aging management was adequate to address any potential

aging during the extended shutdown of Unit 1. The HPCI system is described in LRA

Section 2.3.2.3. LRA Table 3.2.2.3 contains the AMR for the system for normal operation. LRA

Section 3.0.1 states that the Unit 1 HPCI system was maintained in dry layup during the

extended shutdown. The applicant's February 19, 2004, submittal described the applicant's

process for evaluating the effects of aging during the extended shutdown. The staff verified that

the applicant had identified all applicable AERMs during the extended shutdown and credited

appropriate AMPs for managing the AERMs. The staff also reviewed the applicable UFSAR

supplements for the AMPs to ensure that the program descriptions adequately describe the

AMPs.

Aging Effects. Table 1 of the applicant's February 19, 2004, supplement on wet layup provides

the AMR of the HPCI system components within the scope of license renewal and was

maintained in dry layup conditions. The component types include bolting, condenser, expansion

joint, fittings, flexible connectors, gland seal blower, heat exchangers, piping, pumps, restricting

orifices, strainers, tanks, traps, tubing, turbines, and valves. 

The February 19, 2004, submittal describes the internal environment of the system as being

maintained at less than 60 percent RH de-humidified air. The external environment was inside

air. 

For the Unit 1 HPCI system components, the applicant identified the following materials,

environments, and AERMs: carbon and low-alloy steel components in air/gas (internal) or inside

air (external) environments are subject to a loss of material due to general corrosion. Cast iron

and cast iron alloy components in air/gas (internal) or inside air (external) environments are

subject to a loss of material due to general corrosion. Elastomer components in inside air

(external) environments are subject to hardening and loss of strength due to elastomer

degradation. No aging effects are identified for stainless steel, nickel-alloy, and copper-alloy

components in air/gas (internal) or inside air (external) environments. No aging effects are

identified for glass components in inside air (external) environments. No aging effects are

identified for elastomers in air/gas (internal) environments.

During its review, the staff determined that additional information was needed to complete its

review.

In Table 1 of the February 19, 2004, submittal, for the HPCI system (73) and core spray system

(75), the Unit 1 layup components made of carbon and low-alloy steel as well as cast iron and

cast iron alloy in air/gas (internal) or inside air (external) environments are subject to general

corrosion during the period of extended outage. In the LRA AMR, the same aging effect is also

identified for the same components in air/gas (internal) and inside air (external) environments.

Because of the uncertainty of the dryness of air environments, the staff requested, in RAI 3.2-1
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LP, the applicant to assure that the above layup air environments for these components are not

any more aggressive than their counterparts in the plant operating environments, and that no

additional aging effects would need to be considered. By letter dated October 8, 2004, the

applicant stated that the HPCI system (73) was drained and laid up dry per 1-GOI-100-13.A and

0-TI-373. The core spray system (75) was drained and laid up dry per 1-GOI-100-13.17 and

0-TI-373. The air/gas environments for these systems were maintained to less than 60 percent

humidity with dehumidifiers. The applicant stated that both the normal and layup environments

were relatively dry (no pooling) air/gas environments. In addition, the heating and ventilation in

the reactor building was maintained during layup; therefore, the inside air environment for

systems 73 and 75 did not significantly change systems 73 and 75. Based on the above, the

staff concluded that the layup air environments for the above components are not any more

aggressive than their counterparts in the plant operating environments, and the aging effects

for these components in the normal operating and layup environments are the same. RAI 3.2-1

LP is, therefore, resolved.

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004; and January 31, and May 18 and 27, 2005; the staff

concurred with the applicant's evaluation of the aging effects of the materials and environments

associated with the HPCI system during the extended shutdown. The staff did not identify any

omitted aging effects. Therefore, the staff found that the applicant had identified the appropriate

aging effects for the Unit 1 HPCI system during the extended shutdown.

Aging Management Programs. After evaluating the applicant's identification of aging effects, the

staff evaluated the AMPs to determine if they are appropriate for managing the identified aging

effects from the extended shutdown. The staff also verified that the UFSAR supplement

contains an adequate description of the program. 

Table 1 of the applicant's February 19, 2004, submittal identifies the following AMPs for

managing the aging effects described above for the HPCI system. 

 • One-Time Inspection Program (B.2.1.29)

 • Systems Monitoring Program (B.2.1.39)

SER Sections 3.0.3.1.7 and 3.0.3.3.1, respectively, present the staff's detailed review of these

AMPs.

During its review, the staff determined that additional information was needed to complete its

review. 

As stated in Table 1 of the February 19, 2004, submittal, for the HPCI system (73) and core

spray system (75), the Unit 1 layup components made of carbon and low-alloy steel as well as

cast iron and cast iron alloy in air/gas (internal) environments are subject to general corrosion

during the period of extended outage. For the LRA AMR, the same aging effect is identified for

the same components in an air/gas (internal) environment, with the One-Time Inspection

Program credited as the only AMP for managing the identified aging effects. No additional

AMPs were proposed for the layup program.

In RAI 3.2-2 LP, the staff requested the applicant to provide justification that additional

inspection programs were not required for possible unintended moisture conditions
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accumulated in the above components of both the HPCI system (73) and the core spray system

(75), during the period of extended outage. By letter dated October 8, 2004, the applicant

stated that pooled water is not anticipated for the portions of Systems 73 and 75 addressed in

Table 1 per the layup program 0-TI-373. To ensure detection of possible material degradation,

the applicant stated that the restart inspection will be performed prior to the Unit 1 restart

instead of at the end of the current licensing period to verify that the layup program has been

adequate in protecting the material from significant degradation. Based on the lack of

aggressive environments associated with the components in Systems 73 and 75, the staff

found that the applicant's initiative in performing restart inspections for possible material

degradation prior to Unit 1 restart is acceptable. RAI 3.2-2 LP is, therefore, resolved. 

To ensure the general acceptability of the One-Time Inspection Program in managing loss of

material due to general corrosion, the staff requested in RAI 3.0-2 LP that the applicant provide

detailed information of the One-Time Inspection Program, and provide justification that it is

adequate for managing the aging effects for the components within the dry layup systems. The

staff's discussion of this RAI and its resolution by the applicant are provided in SER

Section 3.0.3.3.5.

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004; and January 31, and May 18 and 27, 2005; the staff

found that the applicant had identified appropriate AMPs for managing the aging effects of the

Unit 1 HPCI system components during the extended shutdown. In addition, the staff found the

program descriptions in the UFSAR supplement acceptable.

Conclusion. On the basis of its review, the staff concluded that the applicant had adequately

identified the aging effects, and the AMPs credited for managing the aging effects, for the 

Unit 1 HPCI system components during the extended shutdown, so 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 54.29(a). 

The staff also reviewed the applicable UFSAR supplement program descriptions and concluded

that the UFSAR supplement provides an adequate description of the AMPs credited for

managing aging in these components, as required by 10 CFR 54.21(d).

3.7.3.1.2 Core Spray System

Technical Staff Evaluation. The technical staff reviewed the AMR of the core spray system (75)

to determine whether the proposed aging management was adequate to address any potential

aging during the extended shutdown of Unit 1. The core spray system is described in LRA

Section 2.3.2.5. LRA Table 3.2.2.5 contains the AMR for the system for normal operation. LRA

Section 3.0.1 states that Unit 1 core spray system was maintained in dry layup during the

extended shutdown. The applicant's February 19, 2004, submittal describes the applicant's

process for evaluating the effects of aging during the extended shutdown. The staff verified that

the applicant identified all applicable AERMs during the extended shutdown and credited

appropriate AMPs for managing the AERMs. The staff also reviewed the applicable UFSAR

supplements for the AMPs to ensure that the program descriptions adequately describe the

AMPs.
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Aging Effects. Table 1 of the applicant's February 19, 2004, submittal provides the AMR of the

core spray system components within the scope of license renewal and maintained in dry layup

conditions. The component types include bolting, fittings, piping, pumps, restricting orifices,

strainers, tanks, tubing, and valves. 

The February 19, 2004, submittal describes the internal environment of the system as being

maintained at less than 60 percent RH de-humidified air. The external environment was inside

air. 

For the Unit 1 core spray system components, the applicant identified the following materials,

environments, and AERMs: carbon and low-alloy steel, and cast iron and cast iron alloy.

Components in air/gas (internal) or inside air (external) environments are subject to a loss of

material due to general corrosion. No aging effects are identified for stainless steel, aluminum

alloy, and polymer components in air/gas (internal) or inside air (external) environments.

During its review, the staff determined that additional information was needed to complete its

review.

In Table 1 of the February 19, 2004, submittal for the core spray system (75), the Unit 1 layup

components made of carbon and low-alloy steel, as well as cast iron and cast iron alloy,

components in air/gas (internal) or inside air (external) environments are subject to general

corrosion during the period of extended outage. In the LRA AMR, the same aging effect is also

identified for the same components in air/gas (internal) and inside air (external) environments.

Because of the uncertainty of the dryness of air environments, the staff requested, in RAI 3.2-1

LP, that the applicant assure that the layup air environments for these components are not any

more aggressive than their counterparts in the plant operating environments, and that no

additional aging effects would need to be considered. The staff's discussion of this RAI and its

resolution by the applicant are provided in SER Section 3.7.3.1.1.

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004, the staff concurred with the applicant's evaluation of

the aging effects of the materials and environments associated with the core spray system

during the extended shutdown. The staff did not identify any omitted aging effects. Therefore,

the staff found that the applicant had identified the appropriate aging effects for the Unit 1 core

spray system during the extended shutdown.

Aging Management Programs. After evaluating the applicant's identification of aging effects, the

staff evaluated the AMPs to determine if they are appropriate for managing the identified aging

effects from the extended shutdown. The staff also verified that the UFSAR supplement

contains an adequate description of the program. 

Table 1 of the applicant's February 19, 2004, submittal identifies the following AMPs for

managing the aging effects described above for the core spray system.

 • One-Time Inspection Program (B.2.1.29). 

 • Systems Monitoring Program (B.2.1.39)

SER Sections 3.0.3.1.7 and 3.0.3.3.1, respectively, present the staff's detailed review of these

AMPs.
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During its review, the staff determined that additional information was needed to complete its

review. 

As stated in Table 1 of the February 19, 2004, submittal, for the core spray system (75), the

Unit 1 layup components made of carbon and low-alloy steel as well as cast iron and cast iron

alloy in air/gas (internal) environments are subject to general corrosion during the period of

extended outage. For the LRA AMR, the same aging effect is identified for the same

components in an air/gas (internal) environment, with the One-Time Inspection Program

credited as the only AMP for the material/environment combination. No additional AMPs were

proposed for the counterpart components included in the layup program. In RAI 3.2-2 LP, the

staff requested the applicant to provide justification that additional inspection programs were

not required, for possible unintended moisture conditions accumulated in the system

components during the period of extended outage. The staff's discussion of this RAI and its

resolution by the applicant are provided in SER Section 3.7.3.1.1. 

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004, the staff found the applicant had identified appropriate

AMPs for managing the aging effects of the Unit 1 core spray system components during the

extended shutdown. In addition, the staff found the program descriptions in the UFSAR

supplement acceptable.

Conclusion. On the basis of its review, the staff concluded that the applicant had adequately

identified the aging effects, and the AMPs credited for managing the aging effects, for the 

Unit 1 core spray system components during the extended shutdown, so 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 54.29(a). 

The staff also reviewed the applicable UFSAR supplement program descriptions and concluded

that the UFSAR supplement provides an adequate description of the AMPs credited for

managing aging in these components, as required by 10 CFR 54.21(d).

3.7.3.2 Engineered Safety Features Systems in Various Wet Environments

3.7.3.2.1 Containment System

Technical Staff Evaluation. The technical staff reviewed the AMR of the containment system

(64) to determine whether the proposed aging management was adequate to address any

potential aging during the extended shutdown of Unit 1. The containment system is described in

LRA Section 2.3.2.1. LRA Table 3.2.2.1 contains the AMR for the system for normal operation.

LRA Section 3.0.1 and the applicant's February 19, 2004, submittal state that the portions of

Unit 1 containment system within the scope of BFN license renewal were not incorporated into

the BFN layup program, but were included in the evaluation. The components within the scope

of BFN license renewal for the containment system (64) saw treated (torus) water based on the

locations or leakage of valves were maintained by the Chemistry Program (CI-13.1) for

extended periods of time. The applicant's February 19, 2004, submittal describes the

applicant's process for evaluating the effects of aging during the extended shutdown. The staff

verified that the applicant had identified all applicable AERMs during the extended shutdown

and credited appropriate AMPs for managing the AERMs. The staff also reviewed the
3-396

applicable UFSAR supplements for the AMPs to ensure that the program descriptions

adequately describe the AMPs.

Aging Effects. Table 3 of the applicant's February 19, 2004, submittal provides the AMR of the

containment system components within the scope of license renewal that were not incorporated

into the BFN wet layup program. The component types include bolting, duckwork, heat

exchangers, fire dampers, flexible connectors, fittings, piping, strainers, traps, tubing, and

valves.

The February 19, 2004, submittal identified treated water as the internal environment of the

system, and the external environment was inside air, outside air, buried, and treated water. 

For the Unit 1 containment system components, the applicant identified the following materials,

environments, and AERMs: carbon and low-alloy steel components in treated water (internal

and external) environments are subject to loss of material due to general, crevice, pitting, and

galvanic corrosion. Carbon low-alloy steel components in inside air (external) and outside air

(external) environments are subject to loss of material due to general corrosion. Carbon and

low-alloy steel components in buried (external) environments are subject to loss of material due

to general, crevice, and pitting corrosion, and MIC. Stainless steel components in treated water

(internal) environments are subject to loss of material due to crevice and pitting corrosion.

Nickel-alloy components in treated water (internal) environments are subject to loss of material

due to crevice and pitting corrosion. Elastomer components in inside air (external) and outside

air (external) environments are subject to hardening and loss of strength due to elastomer

degradation (ultraviolet radiation).

During its review, the staff determined that additional information was needed to complete its

review. 

Table 3 of the applicant's February 19, 2004, submittal indicates components in the

containment system (64), HPCI system (73), and core spray system (75) that are exposed to an

air/gas (internal) environment during normal operation, whereas their counterpart environment

during the extended outage is noted as "N/A." This table states that, due to drainage and

system isolation, portions of these systems may have been exposed to an internal environment

of moist air. The table also states that the evaluation for treated water encompasses the aging

effects for a moist air environment in these systems. In RAI 3.0-5 LP, the staff requested the

applicant to explain why the evaluation of the aging effects for the treated-water environment

would encompass that of the aging effects for a moist air environment in these systems, since

the rate of loss of material caused by a moist air environment during layup may be more severe

than a flowing treated-water environment during normal operation. By letter dated October 8,

2004, the applicant stated that Table 3 addresses the aging management for portions of several

systems (including containment, HPCI, and core spray systems) laid up in a wet environment.

Due to closure sequence, closure timing, and possible leakage past the double isolation valves

or two drain valves for these systems, it is assumed that an air/gas environment with an

uncertain amount of moisture was trapped between the double isolation valves. The trapped

moisture between the double isolation valves was considered the same (i.e., raw or treated

water) as was water flowing through the valves prior to closure. The applicant stated that the

N/A denotes that this trapped air/gas environment will be evaluated under the corresponding

raw or treated water evaluations.
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The applicant stated that the evaluation of these moist air environments for the systems

addressed in Table 3 identified no additional aging effects other than those identified for the

corresponding raw or treated-water environment. The applicant stated that the LRA identified

these trapped air environments for one-time (restart) inspections because the extent of

corrosion could be quantified. It was not the intent of this AMR to determine the rate of loss of

material. The applicant further stated that the restart inspection will be performed prior to Unit 1

restart to verify the material condition. 

The staff determined that the applicant had adequately explained the nature of the trapped

air/gas environments, and why the evaluation of the aging effects for the treated-water

environment in the above three ESF systems would encompass that of the aging effects for a

moist air environment in these systems. The applicant also committed to perform a restart

inspection prior to Unit 1 restart to verify the material condition of the system components. This

is acceptable to the staff; therefore, RAI 3.0-5 LP is closed for Systems 64, 73, and 75. 

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004, the staff concurred with the applicant's evaluation of

the aging effects of the materials and environments associated with the containment system

during the extended shutdown. The staff did not identify any omitted aging effects. Therefore,

the staff found that the applicant had identified the appropriate aging effects for the Unit 1

containment system during the extended shutdown.

Aging Management Programs. After evaluating the applicant's identification of aging effects, the

staff evaluated the AMPs to determine if they are appropriate for managing the identified aging

effects from the extended shutdown. The staff also verified that the UFSAR supplement

contains an adequate description of the program. 

Table 3 of the applicant's February 19, 2004, submittal identifies the following AMPs for

managing the aging effects described above for the containment system.

 • Chemistry Control Program (B.2.1.5)

 • One-Time Inspection Program (B.2.1.29). 

 • Buried Piping and Tanks Inspection Program (B.2.1.31)

 • Systems Monitoring Program (B.2.1.39)

SER Sections 3.0.3.2.2, 3.0.3.1.7, 3.0.3.1.9, and 3.0.3.3.1, respectively, present the staff's

detailed review of these AMPs.

During its review, the staff determined that additional information was needed to complete its

review. 

Table 3 of the applicant's February 19, 2004, submittal indicates that components in the

containment (64), HPCI (73), and core spray (75) systems were exposed to treated

(non-controlled) water environments during the extended outage. Table 3 identified no

additional AMPs for these layup systems, other than those AMPs specified in LRA for the

period of extended operation. In RAI 3.0-6 LP, the staff requested the applicant to justify the

determination by providing the results of any water sampling performed, and discuss whether

the systems were stagnant or periodically flowed during the period of extended outage. The

staff also requested the applicant to discuss the plans for pre-startup inspections or provide
3-398

justification that such inspections are not needed. By letter dated October 8, 2004, the applicant

stated that the torus and torus attached piping for the containment system (i.e., the torus itself)

and HPCI and core spray systems (torus attached piping) saw torus water maintained by

CI-13.1 chemistry program, Appendix A, Table 20, for extended periods of time until the torus

was drained in the summer of 2003. When filled, the torus is approximately half full of water

with the other half ambient air. The torus water was not flowing in that the only significant water

movement was relatively infrequent transfers into and out of the Unit 1 torus. The torus on an

operating unit cannot be considered "flowing" either. The operating unit's torus would also be

nitrogen-inerted. The applicant stated that torus coating touch-up/repair is part of the restart

work to be completed while the torus is drained. 

The applicant stated that the torus impurity administrative goals for conductivity, chloride, and

sulfate given in CI-13.1 are 2.0. μS/cm, 75 ppb, and 75 ppb, respectively, which are within the

chemistry specifications. Sampling is performed quarterly. The applicant also stated that the

restart inspection will be performed prior to Unit 1 restart to verify the material condition. 

Based on the above information, pending the staff's acceptance of the applicant's wet layup

program chemistry controls provided in SER Section 3.7.1.1, the staff determined that the

applicant had adequately addressed the staff's concerns related to water chemistry existing

during layup and pre-startup inspections, for the containment, HPCI, and core spray systems.

RAI 3.0-6 LP is, therefore, closed for these three systems. 

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004, the staff found the applicant had identified appropriate

AMPs for managing the aging effects of the Unit 1 containment system components not

incorporated in the wet layup program during the extended shutdown. In addition, the staff

found the program descriptions in the UFSAR supplement acceptable.

Conclusion. On the basis of its review, the staff concluded that the applicant had adequately

identified the aging effects, and the AMPs credited for managing the aging effects, for the 

Unit 1 containment system components during the extended shutdown, so 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 54.29(a). 

The staff also reviewed the applicable UFSAR supplement program descriptions and concluded

that the UFSAR supplement provides an adequate description of the AMPs credited for

managing aging in these components, as required by 10 CFR 54.21(d). 

3.7.3.2.2 High Pressure Coolant Injection System 

Technical Staff Evaluation. The technical staff reviewed the AMR of the HPCI system (73) to

determine whether the proposed aging management was adequate to address any potential

aging during the extended shutdown of Unit 1. The HPCI system is described in LRA

Section 2.3.2.3. LRA Table 3.2.2.3 contains the AMR for the system for normal operation. LRA

Section 3.0.1 and the applicant's February 19, 2004, submittal state that the Unit 1 HPCI

system within the scope of license renewal was not incorporated into the layup program but was

included in the evaluation. Based on location, valve leakage, etc., the components within the

scope of license renewal for the HPCI system (73) saw treated (torus) water maintained by

CI-13.1 chemistry program for extended periods of time. The applicant's February 19, 2004,
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submittal describes the applicant's process for evaluating the effects of aging during the

extended shutdown. The staff verified that the applicant identified all applicable AERMs during

the extended shutdown and credited appropriate AMPs for managing the AERMs. The staff

also reviewed the applicable UFSAR supplements for the AMPs to ensure that the program

descriptions adequately describe the AMPs.

Aging Effects. Table 3 of the applicant's February 19, 2004, submittal provides the AMR of the

HPCI system components within the scope of license renewal that were not incorporated into

the wet layup program. The component types include bolting, condenser, expansion joint,

fittings, flexible connectors, gland seal blower, heat exchangers, piping, pumps, restricting

orifices, strainers, tanks, traps, tubing, turbines, and valves.

The LRA and the February 19, 2004, submittal identified treated water as the internal

environment of the system, and the external environment was inside air and treated water. 

For the Unit 1 HPCI system components, the applicant identified the following materials,

environments, and AERMs: carbon and low-alloy steel components in treated water (internal

and external) environments are subject to loss of material due to general, crevice, pitting, and

galvanic corrosion. Carbon low-alloy steel components in inside air (external) environments are

subject to loss of material due to general corrosion. Stainless steel components in treated water

(internal) are subject to loss of material due to crevice and pitting corrosion. Nickel-alloy

components in treated water (internal) environments are subject to loss of material due to

crevice and pitting corrosion. Copper-alloy components in treated water (internal) are subject to

loss of material due to selective leaching, crevice and pitting corrosion, as well as galvanic

corrosion. Cast iron and cast iron alloy components in treated water (internal) environments are

subject to a loss of material due to general, crevice, pitting, and selective leaching corrosion.

Cast iron and cast iron alloy components in inside air (external) environments are subject to

loss of material due to general corrosion. Elastomer components in inside air (external)

environments are subject to elastomer degradation due to ultraviolet radiation.

During its review, the staff determined that additional information was needed to complete its

review. 

In Table 3 of the applicant's February 19, 2004, submittal, components in the HPCI system (73)

are shown to be exposed to an air/gas internal environment during normal operation, whereas

the environment during the extended outage is noted as "N/A.” This table states that, due to

drainage and system isolation, portions of this system may have been exposed to an internal

environment of moist air. The table also states that the evaluation for treated water

encompasses the aging effects for a moist air environment in this system. In RAI 3.0-5 LP, the

staff requested the applicant to explain why the evaluation of the aging effects for the 

treated-water environment would encompass that of the aging effects for a moist air

environment in this system, since the rate of loss of material caused by a moist air environment

during layup may be more severe than a flowing treated-water environment during normal

operation. The staff's discussion of this RAI and its resolution by the applicant are provided in

SER Sections 3.7.3.2.1.

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004, the staff concurred with the applicant's evaluation of

the aging effects of the materials and environments associated with the HPCI system during the
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extended shutdown. The staff did not identify any omitted aging effects. Therefore, the staff

found that the applicant had identified the appropriate aging effects for the Unit 1 HPCI system

during the extended shutdown.

Aging Management Programs. After evaluating the applicant's identification of aging effects, the

staff evaluated the AMPs to determine if they are appropriate for managing the identified aging

effects from the extended shutdown. The staff also verified that the UFSAR supplement

contains an adequate description of the program.

. 

Table 3 of the applicant's February 19, 2004, submittal identifies the following AMPs for

managing the aging effects described above for the HPCI system.

 • ASME Section XI Subsections IWB, IWC, & IWD Inservice Inspection Program (B.2.1.4)

 • Chemistry Control Program (B.2.1.5)

 • BWR Stress Corrosion Cracking Program (B.2.1.10)

 • Flow-Accelerated Corrosion Program (B.2.1.15)

 • One-Time Inspection Program (B.2.1.29). 

 • Selective Leaching of Materials Program (B.2.1.30)

 • Systems Monitoring Program (B.2.1.39)

SER Sections 3.0.3.1.3, 3.0.3.2.2, 3.0.3.2.5, 3.0.3.2.9, 3.0.3.1.7, 3.0.3.1.8, and 3.0.3.3.1,

respectively, present the staff's detailed review of these AMPs.

During its review, the staff determined that additional information was needed to complete its

review. 

Table 3 of the applicant's February 19, 2004, submittal indicates that the HPCI system was not

formally incorporated into the Unit 1 wet layup program. This system was exposed to treated

(non-controlled) water during the extended outage. Table 3 identified no additional AMPs for

this layup system, other than those AMPs specified in the LRA for the period of extended

operation. In RAI 3.0-6 LP, the staff requested the applicant to justify the determination by

providing results of any water sampling performed and to discuss whether the system was

stagnant or periodically flowed during the period of extended outage. The staff also requested

the applicant to discuss the plans for pre-startup inspections or provide justification that such

inspections are not needed. The staff's discussion of this RAI and its resolution by the applicant

are provided in SER Sections 3.7.3.2.1. 

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004, the staff found the applicant had identified appropriate

AMPs for managing the aging effects of the Unit 1 HPCI system components not incorporated

in the wet layup program during the extended shutdown. In addition, the staff found the

program descriptions in the UFSAR supplement acceptable.

Conclusion. On the basis of its review, the staff concluded that the applicant had adequately

identified the aging effects and the AMPs credited for managing the aging effects for the Unit 1

HPCI system components during the extended shutdown, so 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 54.29(a). 
3-401

The staff also reviewed the applicable UFSAR supplement program descriptions and concluded

that the UFSAR supplement provides an adequate description of the AMPs credited for

managing aging in these components, as required by 10 CFR 54.21(d).

3.7.3.2.3 Core Spray System 

Technical Staff Evaluation. The technical staff reviewed the AMR of the core spray system (75)

to determine whether the proposed aging management was adequate to address any potential

aging during the extended shutdown of Unit 1. The core spray system is described in LRA

Section 2.3.2.5. LRA Table 3.2.2.5 contains the AMR for the system for normal operation. LRA

Section 3.0.1 and the applicant's February 19, 2004, submittal states that, Unit 1 core spray

system within the scope of license renewal was not incorporated into the layup program, but

was included in the evaluation. Based on location, valve leakage, etc., the components within

the scope of license renewal for the core spray system (75) saw treated (torus) water for

extended periods of time. The applicant's February 19, 2004, submittal describes the

applicant's process for evaluating the effects of aging during the extended shutdown. The staff

verified that the applicant had identified all applicable AERMs during the extended shutdown

and credited appropriate AMPs for managing the AERMs. The staff also reviewed the

applicable UFSAR supplements for the AMPs to ensure that the program descriptions

adequately describe the AMPs.

Aging Effects. Table 3 of the February 19, 2004, submittal provides the AMR of the core spray

system components within the scope of license renewal that were not incorporated into the BFN

wet layup program. The component types include bolting, condenser, expansion joint, fittings,

flexible connectors, gland seal blower, heat exchangers, piping, pumps, restricting orifice,

strainers, tanks, traps, tubing, turbines, and valves. 

The LRA and the February 19, 2004, submittal identified treated water as the internal

environment of the system, and the external environment was inside air and treated water. 

For the Unit 1 core spray system components, the applicant identified the following materials,

environments, and AERMs: carbon and low-alloy steel components in treated water (internal

and external) environments are subject to loss of material due to general, crevice, pitting, and

galvanic corrosion. Carbon low-alloy steel components in inside air (external) environments are

subject to loss of material due to general corrosion. Stainless steel components in treated water

(internal and external) are subject to loss of material due to crevice and pitting corrosion.

Aluminum alloy components in treated water (internal) are subject to loss of material due to

crevice and pitting corrosion, as well as crack initiation/growth due to stress corrosion cracking.

Cast iron and cast iron alloy components in treated water (internal) environments are subject to

a loss of material due to general, crevice, pitting, and selective leaching corrosion. Cast iron

and cast iron alloy components in inside air (external) environments are subject to loss of

material due to general corrosion.

During its review, the staff determined that additional information was needed to complete its

review. 

In Table 3 of the applicant's February 19, 2004, submittal, components in the core spray system

(75) are shown to be exposed to an air/gas internal environment during normal operation,

whereas the environment during the extended outage is noted as "N/A.” This table states that,
3-402

due to drainage and system isolation, portions of this system may have been exposed to an

internal environment of moist air. The table also states that the evaluation of treated water

encompasses the aging effects for a moist air environment in this system. In RAI 3.0-5 LP, the

staff requested the applicant to explain why the evaluation of the aging effects for the

treated-water environment would encompass that of the aging effects for a moist air

environment in this system, since the rate of loss of material caused by a moist air environment

during layup may be more severe than a flowing treated-water environment. The staff's

discussion of this RAI and its resolution by the applicant are provided in SER

Sections 3.7.3.2.1. 

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004, the staff concurred with the applicant's evaluation of

the aging effects of the materials and environments associated with the core spray system

during the extended shutdown. The staff did not identify any omitted aging effects. Therefore,

the staff found that the applicant had identified the appropriate aging effects for the Unit 1 core

spray system during the extended shutdown.

Aging Management Programs. After evaluating the applicant's identification of aging effects, the

staff evaluated the AMPs to determine if they are appropriate for managing the identified aging

effects from the extended shutdown. The staff also verified that the UFSAR supplement

contains an adequate description of the program. 

Table 3 of the applicant's February 19, 2004, submittal identifies the following AMPs for

managing the aging effects described above for the core spray system.

 • ASME Section XI Subsections IWB, IWC, & IWD Inservice Inspection Program (B.2.1.4)

 • Chemistry Control Program (B.2.1.5)

 • One-Time Inspection Program (B.2.1.29). 

 • Selective Leaching of Materials Program (B.2.1.30)

 • Systems Monitoring Program (B.2.1.39)

SER Sections 3.0.3.1.3, 3.0.3.2.2, 3.0.3.1.7, 3.0.3.1.8, and 3.0.3.3.1, respectively, present the

staff's detailed review of these AMPs.

During its review, the staff determined that additional information was needed to complete its

review.

Table 3 of the applicant's February 19, 2004, submittal indicates that the core spray system

was not formally incorporated into the Unit 1 wet layup program. This system was exposed to

treated (non-controlled) water during the extended outage. Table 3 identified no additional

AMPs for this layup system, other than those AMPs specified in LRA for the period of extended

operation. In RAI 3.0-6 LP, the staff requested the applicant to justify the determination by

providing results of any water sampling performed, and discuss whether the system was

stagnant or periodically flowed during the period of extended outage. The staff also requested

the applicant to discuss the plans for pre-startup inspections or provide justification that such

inspections are not needed. The staff's discussion of this RAI and its resolution by the applicant

are provided in SER Sections 3.7.3.2.1. 
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On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004, the staff found the applicant identified appropriate

AMPs for managing the aging effects of the Unit 1 core spray system components not

incorporated in the wet layup program during the extended shutdown. In addition, the staff

found the program descriptions in the UFSAR supplement acceptable.

Conclusion. On the basis of its review, the staff concluded that the applicant had adequately

identified the aging effects and the AMPs credited for managing the aging effects for the Unit 1

core spray system components during the extended shutdown, so 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 54.29(a). 

The staff also reviewed the applicable UFSAR supplement program descriptions and concluded

that the UFSAR supplement provides an adequate description of the AMPs credited for

managing aging in these components, as required by 10 CFR 54.21(d).

3.7.3.3 Engineered Safety Features Systems in Various Dry Environments

3.7.3.3.1 Containment Inerting System

Technical Staff Evaluation. The technical staff reviewed the AMR of the containment inerting

system (76) to determine whether the proposed aging management was adequate to address

any potential aging during the extended shutdown of Unit 1. The containment inerting system is

described in LRA Section 2.3.2.6. LRA Table 3.2.2.6 contains the AMR for the system for

normal operation. LRA Section 3.0.1 and the applicant's February 19, 2004, submittal states

that the Unit 1 containment inerting system was not formally incorporated into the BFN layup

program, but was included in the evaluation. The applicant stated that there were no moisture

controls for the portions of the Unit 1 containment inerting system within the scope of BFN

license renewal. The applicant's February 19, 2004, submittal describes the applicant's process

for evaluating the effects of aging during the extended shutdown. The staff verified that the

applicant had identified all applicable AERMs during the extended shutdown and credited

appropriate AMPs for managing the AERMs. The staff also reviewed the applicable UFSAR

supplements for the AMPs to ensure that the program descriptions adequately describe the

AMPs.

Aging Effects. Table 4 of the February 19, 2004, submittal provides the AMR of the containment

inerting system components within the scope of license renewal which were not incorporated

into the BFN layup program. The component types include bolting, flexible connectors, heat

exchangers, fittings, piping, pumps, strainers, traps, tubing, and valves.

The applicant's February 19, 2004, submittal identified air/gas as the internal environment of

the system, whereas the external environment was inside air, outside air, buried, and

embedded/encased. 

For the Unit 1 containment inerting system components, the applicant identified the following

materials, environments, and AERMs, where, because of the uncontrolled moist air, aging

effects in addition to those requiring management during the period of extended operation were

identified: carbon and low-alloy steel components in air/gas (internal) environments are subject
3-404

to loss of material due to general, crevice, pitting, and galvanic corrosion. Carbon low-alloy

steel components in inside air (external) environments are subject to loss of material due to

general corrosion. Stainless steel components in air/gas (internal) environments are subject to

loss of material due to crevice and pitting corrosion. Nickel-alloy components in air/gas

(internal) environments are subject to loss of material due to crevice and pitting corrosion.

Copper-alloy components in air/gas (internal) environments are subject to loss of material due

to selective leaching, crevice corrosion, pitting corrosion, and galvanic corrosion. Aluminum

alloy components in air/gas environments are subject to loss of material due to crevice, pitting,

and galvanic corrosion, and crack initiation/growth due to SCC. Cast iron and cast iron alloy

components in air/gas (internal) environments are subject to loss of material due to general,

crevice, pitting, and galvanic corrosion, as well as selective leaching. Cast iron and cast iron

alloy components in inside air (external) environments are subject to loss of material due to

general corrosion. 

On the basis of its review of the information provided in the LRA, as supplemented by letter

dated February 19, 2004, the staff concurred with the applicant's evaluation of the aging effects

of the materials and environments associated with the containment inerting system during the

extended shutdown. The staff did not identify any omitted aging effects. Therefore, the staff

found that the applicant had identified the appropriate aging effects for the Unit 1 containment

inerting system during the extended shutdown.

Aging Management Programs. After evaluating the applicant's identification of aging effects, the

staff evaluated the AMPs to determine if they are appropriate for managing the identified aging

effects from the extended shutdown. The staff also verified that the UFSAR supplement

contains an adequate description of the program. 

Table 4 of the applicant's February 19, 2004, submittal identifies the following AMPs for

managing the aging effects described above for the containment inerting system.

 • One-Time Inspection Program (B.2.1.29). 

 • Systems Monitoring Program (B.2.1.39)

SER Sections 3.0.3.1.7 and 3.0.3.3.1, respectively, present the staff's detailed review of these

AMPs.

During its review, the staff determined that additional information was needed to complete its

review. 

In Table 4 of the February 19, 2004, submittal, for the containment inerting system (76), the

applicant stated that inspections will be performed prior to Unit 1 restart for certain components

where additional aging effects were identified for the extended outage. These additional aging

effects include those identified for carbon and low-alloy steel, stainless steel, nickel alloy,

copper alloy, aluminum alloy, and cast iron and cast iron alloy components in system locations

where condensation could build up. No descriptions of the inspections were provided. In 

RAI 3.0-7 LP, the staff requested the applicant to discuss the proposed inspections, including

scope, method, procedure, parameters monitored and trended, detection of aging effects, and

acceptance criteria, in order to justify the adequacy of the inspections. By letter dated 

October 8, 2004, the applicant stated that internal surface monitoring is performed in

accordance with the One-Time Inspection Program described in the LRA, Appendix B,
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Section B.2.1.29. This is the same AMP proposed for managing internal aging effects of

components exposed to moist air during the period of extended operation. The staff found the

applicant's commitment of performing one-time inspections to be acceptable, and RAI 3.0-7 LP

is closed for the containment inerting system. The staff's discussion of the adequacy of the

One-Time Inspection Program in managing the identified aging effects for the system

components, versus periodic inspections, is provided in SER Section 3.7.1. 

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004, January 31, 2005, May 18 and 27, 2005, the staff

found the applicant had identified appropriate AMPs for managing the aging effects of the

Unit 1 containment inerting system components not incorporated in the dry layup program

during the extended shutdown. In addition, the staff found the program descriptions in the

UFSAR supplement acceptable.

Conclusion. On the basis of its review, the staff concluded that the applicant had adequately

identified the aging effects, and the AMPs credited for managing the aging effects, for the

Unit 1 containment inerting system components during the extended shutdown, so 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 54.29(a). 

The staff also reviewed the applicable UFSAR supplement program descriptions and concluded

that the UFSAR supplement provides an adequate description of the AMPs credited for

managing aging in these components, as required by 10 CFR 54.21(d). 

3.7.3.3.2 Containment Atmosphere Dilution System.

Technical Staff Evaluation. The technical staff reviewed the AMR of the containment

atmosphere dilution system (ADS) (84) to determine whether the proposed aging management

was adequate to address any potential aging during the extended shutdown of Unit 1. The

containment ADS is described in LRA Section 2.3.2.7. LRA Table 3.2.2.7 contains the AMR for

the system for normal operation. LRA Section 3.0.1 and the applicant's February 19, 2004,

submittal states that the Unit 1 containment ADS was not formally incorporated into the dry

layup program, but was included in the evaluation. The applicant stated that there were no

moisture controls for the portions of the Unit 1 containment ADS within the scope of license

renewal. 

The applicant's February 19, 2004, submittal describes the applicant's process for evaluating

the effects of aging during the extended shutdown. The staff verified that the applicant had

identified all applicable AERMs during the extended shutdown and credited appropriate AMPs

for managing the AERMs. The staff also reviewed the applicable UFSAR supplements for the

AMPs to ensure that the program descriptions adequately describe the AMPs.

Aging Effects. Table 4 of the February 19, 2004, submittal provides the AMR of the containment

ADS components within the scope of license renewal which were not incorporated into the BFN

dry layup program. The component types include bolting, fittings, flex hose, heat exchangers,

piping, tanks, tubing, and valves.
3-406

The LRA and the February 19, 2004, submittal identified air/gas as the internal environment of

the system, whereas the external environment was inside air, outside air, buried, and

embedded/encased. 

For the Unit 1 containment ADS components, the applicant identified the following materials,

environments, and AERMs, where, because of the uncontrolled moist air, aging effects in

addition to those requiring management during the period of extended operation were

identified: carbon and low-alloy steel components in air/gas (internal) environments are subject

to loss of material due to general, crevice, pitting, and galvanic corrosion. Carbon low-alloy

steel components in inside air (external) and outside air (external) environments are subject to

loss of material due to general corrosion. Stainless steel components in air/gas (internal)

environments are subject to loss of material due to crevice and pitting corrosion. Stainless steel

components in buried (external) environments are subject to loss of material due to crevice and

pitting corrosion, and MIC. Copper alloy components in air/gas (internal) environments are

subject to loss of material due to selective leaching, crevice corrosion, pitting corrosion, and

galvanic corrosion. Aluminum alloy components in air/gas environments are subject to loss of

material due to crevice, pitting, and galvanic corrosion, and crack initiation/growth due to SCC.

Cast iron and cast iron alloy components in air/gas (internal) environments are subject to loss of

material due to general, crevice, pitting, and galvanic corrosion, as well as selective leaching.

Cast iron and cast iron alloy components in inside air (external) environments are subject to

loss of material due to general corrosion. 

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19, 2004, the staff concurred with the applicant's evaluation of the aging effects

of the materials and environments associated with the containment ADS during the extended

shutdown. The staff did not identify any omitted aging effects. Therefore, the staff found that

the applicant had identified the appropriate aging effects for the Unit 1 containment ADS during

the extended shutdown.

Aging Management Programs. After evaluating the applicant's identification of aging effects, the

staff evaluated the AMPs to determine if they are appropriate for managing the identified aging

effects from the extended shutdown. The staff also verified that the UFSAR supplement

contains an adequate description of the program. 

Table 4 of the applicant's February 19, 2004, submittal identifies the following AMPs for

managing the aging effects described above for the containment atmosphere dilution system.

 • One-Time Inspection Program (B.2.1.29). 

 • Buried Piping and Tanks Inspection Program (B.2.1.31)

 • Systems Monitoring Program (B.2.1.39)

SER Sections 3.0.3.1.7, 3.0.3.1.9, and 3.0.3.3.1, respectively, present the staff's detailed

review of these AMPs.

During its review, the staff determined that additional information was needed to complete its

review. 

In Table 4 of the February 19, 2004, submittal, for the containment ADS (84), the applicant

stated that inspections will be performed prior to Unit 1 restart for certain components where
3-407

additional aging effects were identified for the extended outage. These additional aging effects

include those identified for carbon and low-alloy steel, stainless steel, copper alloy, aluminum

alloy, and cast iron and cast iron alloy components in system locations where condensation

could build up. No descriptions of the inspections were provided. In 

RAI 3.0-7 LP, the staff requested the applicant to discuss the proposed inspections, including

scope, method, procedure, parameters monitored and trended, detection of aging effects, and

acceptance criteria, in order to justify the adequacy of the inspections. The staff's discussion of

this RAI and its resolution by the applicant are provided in SER Section 3.7.3.3.1. 

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004, the staff found the applicant had identified appropriate

AMPs for managing the aging effects of the Unit 1 containment ADS components not

incorporated in the dry layup program during the extended shutdown. In addition, the staff

found the program descriptions in the UFSAR supplement acceptable.

Conclusion. On the basis of its review, the staff concluded that the applicant had adequately

identified the aging effects, and the AMPs credited for managing the aging effects, for the

Unit 1 containment ADS components during the extended shutdown, so 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 54.29(a). 

The staff also reviewed the applicable UFSAR supplement program descriptions and concluded

that the UFSAR supplement provides an adequate description of the AMPs credited for

managing aging in these components, as required by 10 CFR 54.21(d). 

3.7.4 Auxiliary Systems

3.7.4.1 Auxiliary Systems in Dry Layup

3.7.4.1.1 Standby Liquid Control System

Technical Staff Evaluation. The technical staff reviewed the AMR of the standby liquid control

system to determine whether the proposed aging management was adequate to address any

potential aging during the extended shutdown of Unit 1. The standby liquid control system is

described in LRA Section 2.3.3.18. LRA Table 3.3.2.18 contains the AMR for the system for

normal operation. LRA Section 3.0.1 states that the Unit 1 standby liquid control system was

maintained in dry layup during the extended shutdown. The applicant's February 19, 2004,

submittal of additional information describes the applicant's process for evaluating the effects of

aging during the extended shutdown. The staff verified that the applicant identified all applicable

AERMs during the extended shutdown and credited appropriate AMPs for managing the

AERMs. The staff also reviewed the applicable UFSAR supplements for the AMPs to ensure

that the program descriptions adequately describe the AMPs. 

During its review, the staff determined that additional information was needed to complete its

review. General RAIs 3.0-2 LP, 3.0-8 LP, and 3.0-10 LP are related to the standby liquid control

system. These RAIs, the applicant's responses, and the staff's review of the applicant's

responses are discussed in SER Section 3.7.1.3. There are no system-specific RAIs on the

standby liquid control system. 
3-408

Aging Effects. LRA Table 3.3.2.18 provides the AMR of the standby liquid control system

components within the scope of license renewal and subject to AMR. The component types

include piping, fittings, bolting, pumps, tanks, and valves.

The LRA and the February 19, 2004, submittal of additional information describe the

environment during the Unit 1 shutdown as follows: the internal environment was maintained at

less of 60 percent relative humidity (de-humidified air) and the external environment was inside

air.

For the Unit 1 system components, the applicant identified on Evaluation of the Unit 1 Layup

and Preservation Program Table 1, the following materials, environments, and AERMs: carbon

and low-alloy steel components exposed to air/gas and inside air are subject to a loss of

material due to general corrosion. Stainless steel, aluminum alloy and polymer-delrin exposed

to air/gas and inside air experience no aging effects. 

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004; and January 31, and May 18 and 27, 2005; the staff

concurred with the applicant's evaluation of the aging effects of the materials and environments

associated with the standby liquid control system during the extended shutdown. The staff did

not identify any omitted aging effects. Therefore, the staff found that the applicant had identified

the appropriate aging effects for the Unit 1 standby liquid control system during the extended

shutdown.

Aging Management Programs. After evaluating the applicant's identification of aging effects, the

staff evaluated the AMPs to determine if they are appropriate for managing the identified aging

effects from the extended shutdown. The staff also verified that the UFSAR supplement

contains an adequate description of the program. 

Evaluation of the Unit Layup and Preservation Program Table 1 identifies the following AMPs

for managing the aging effects described above for the standby liquid control system in dry

layup. 

 • One-Time Inspection Program (B.2.1.29)

 • Systems Monitoring Program (B.2.1.39)

The staff's detailed review of these AMPs is found in SER Section 3.0.3.1.7 and 3.0.3.3.1,

respectively. 

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004, January 31, 2005, May 18 and 27, 2005, the staff

found the applicant had identified appropriate AMPs for managing the aging effects of the

Unit 1 standby liquid control system components during the extended shutdown. In addition, the

staff found the program descriptions in the UFSAR supplement acceptable.

Conclusion. On the basis of its review, the staff concluded that the applicant had adequately

identified the aging effects and the AMPs credited for managing the aging effects for the Unit 1

standby liquid control system components during the extended shutdown, so 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 54.29(a). 
3-409

The staff also reviewed the applicable UFSAR supplement program descriptions and concluded

that the UFSAR supplement provides an adequate description of the AMPs credited for

managing aging in these components, as required by 10 CFR 54.21(d).

3.7.4.1.2 Off-Gas System

Technical Staff Evaluation. The technical staff reviewed the AMR of the off-gas system to

determine whether the proposed aging management was adequate to address any potential

aging during the extended shutdown of Unit 1. The off-gas system is described in LRA

Section 2.3.3.19. LRA Table 3.3.2.19 contains the AMR for the system for normal operation.

LRA Section 3.0.1 states that the Unit 1 off-gas system was maintained in dry layup during the

extended shutdown. The applicant's February 19, 2004, submittal of additional information

describes the applicant's process for evaluating the effects of aging during the extended

shutdown. The staff verified that the applicant had identified all applicable AERMs during the

extended shutdown and credited appropriate AMPs for managing the AERMs. The staff also

reviewed the applicable UFSAR supplements for the AMPs to ensure that the program

descriptions adequately describe the AMPs. 

During its review, the staff determined that additional information was needed to complete its

review. General RAIs 3.0-2 LP, 3.0-8 LP, and 3.0-10 LP are related to the off-gas system.

These RAIs, the applicant's response and the staff's review of the applicant's response are

discussed in SER Section. There are no system-specific RAIs on the off-gas system. 

Aging Effects. LRA Table 3.3.2.19 provides the AMR of the off-gas system components within

the scope of license renewal and subject to AMR. The component types include bolting,

ductwork, piping and fittings.

The LRA and the February 19, 2004, submittal of additional information describe the

environment during the Unit 1 shutdown as follows: the internal environment was maintained at

less than 60 percent relative humidity (de-humidified air), and the outside environment was

inside air.

For the Unit 1 system components, the applicant identified on Evaluation of the Unit 1 Layup

and Preservation Program Table 1, the following materials, environments, and AERMs: carbon

and low-alloy steel components exposed to air/gas and inside air are subject to a loss of

material due to general corrosion. Stainless steel and copper alloy exposed to air/gas and

inside air experience no aging effects. 

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004; and January 31, and May 18 and 27, 2005; the staff

concurred with the applicant's evaluation of the aging effects of the materials and environments

associated with the off-gas system during the extended shutdown. The staff did not identify any

omitted aging effects. Therefore, the staff found that the applicant had identified the appropriate

aging effects for the Unit 1 off-gas system during the extended shutdown.

Aging Management Programs. After evaluating the applicant's identification of aging effects, the

staff evaluated the AMPs to determine if they are appropriate for managing the identified aging

effects from the extended shutdown. The staff also verified that the UFSAR supplement

contains an adequate description of the program. 
3-410

Evaluation of the BFN Unit Layup and Preservation Program Table 1 identifies the following

AMPs for managing the aging effects described above for the off-gas system in dry layup. 

 • One-Time Inspection Program (B.2.1.29)

 • Systems Monitoring Program (B.2.1.39)

The staff's detailed review of these AMPs is found in SER Section 3.0.3.1.7 and 3.0.3.3.1,

respectively. 

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004, January 31, 2005, May 18 and 27, 2005, the staff

found the applicant had identified appropriate AMPs for managing the aging effects of the

Unit 1 off-gas system. components during the extended shutdown. In addition, the staff found

the program descriptions in the UFSAR supplement acceptable.

Conclusion. On the basis of its review, the staff concluded that the applicant had adequately

identified the aging effects, and the AMPs credited for managing the aging effects, for the

Unit 1 off-gas system. components during the extended shutdown, so 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 54.29(a). 

The staff also reviewed the applicable UFSAR supplement program descriptions and concluded

that the UFSAR supplement provides an adequate description of the AMPs credited for

managing aging in these components, as required by 10 CFR 54.21(d).

3.7.4.1.3 Reactor Core Isolation Cooling System

Technical Staff Evaluation. The technical staff reviewed the AMR of the RCIC system to

determine whether the proposed aging management was adequate to address any potential

aging during the extended shutdown of Unit 1. The reactor core isolation cooling system is

described in LRA Section 2.3.3.23. LRA Table 3.3.2.23 contains the AMR for the system for

normal operation. LRA Section 3.0.1 states that Unit 1 reactor core isolation cooling system for

wet layup was not formally incorporated into the wet layup program, but was evaluated. The

applicant's February 19, 2004, submittal of additional information (including Table 1 and 3).

shows that the RCIC system was subject to both a dry layup condition and a wetted condition.

The applicant's response to RAI 3.0-6 LP shows that the RCIC torus attached piping saw torus

water maintained by Chemistry Program CI-13.1 for extended periods of time. The BFN layup

program for dry layup maintained the internal environment of Unit 1 reactor core isolation

cooling system at less than 60 percent RH de-humidified air. The applicant's February 19,

2004, submittal of additional information (including Table 1 and 3), describes the applicant's

process for evaluating the effects of aging during the extended shutdown. The staff verified that

the applicant had identified all applicable AERMs during the extended shutdown and credited

appropriate AMPs for managing the AERMs. The staff also reviewed the applicable UFSAR

supplements for the AMPs to ensure that the program descriptions adequately describe the

AMPs. 

During its review, the staff determined that additional information was needed to complete its

review. General RAIs 3.0-2 LP, 3.0-3 LP, 3.0-4 LP, 3.0-5 LP, 3.0-6 LP, 3.0-8 LP, 3.0-9 LP and

3.0-10 LP are related to the reactor core isolation cooling system. RAIs 3.0-2 LP to RAI 3.0-8
3-411

LP are discussed in SER Section 3.7.1.3, RAI 3.0-9 LP is discussed in SER Section 3.7.1.2 and

RAI 3.0-10 LP is discussed in SER Section 3.7.1.3. There are no system-specific RAIs on the

reactor core isolation cooling system.

Aging Effects. LRA Table 3.3.2.23 provides the AMR of the reactor core isolation cooling

system components within the scope of license renewal and subject to AMR. The component

types include bolting, condenser, expansion joint, fittings, fittings - RCPB, flexible connector,

heat exchangers, piping, piping - RCPB, pumps, restricting orifice, restricting orifice - RCPB,

strainers, tanks, traps, tubing, turbines, valves, and valves - RCPB.

Table 1 of the February 19, 2004, submittal of additional information describes the dry layup

environment during the Unit 1 shutdown as follows: the internal environment was air/gas (less

than 60 percent RH) and the external environment was inside air. Table 3 of the February 19,

2004, submittal identifies the internal environment as treated water and the external

environment as inside air or treated water.

For the Unit 1 system components, the applicant identified on Evaluation of the BFN Unit 1

Layup and Preservation Program Tables 1 and 3, the following materials, environments, and

AERMs: carbon and low-alloy steel components as well as cast iron and cast iron alloy

components. exposed to air/gas (internal) or inside air (external) environments are subject to a

loss of material due to general corrosion; carbon and low-alloy steel components as well as

cast iron and cast iron alloy components exposed to treated water are subject to general

corrosion, crevice corrosion, galvanic corrosion, and pitting corrosion; stainless steel

components in treated water are subject to crevice corrosion, and pitting corrosion; copper-alloy

components in treated water are subject to a loss of material due to selective leaching, crevice

corrosion, galvanic corrosion, and pitting corrosion; aluminum alloy components. in treated

water are subject to a loss of material due to crack initiation and growth due to SCC, crevice

corrosion, galvanic corrosion, and pitting corrosion; stainless steel, copper alloy, aluminum

alloy, and glass components exposed to air/gas (internal) or inside air (external) environments

experience no aging effects. Glass components in treated-water environment also experience

no aging effects.

In response to general RAI 3.0-9 LP, the applicant identified that the RCIC steam trap drain

was replaced with 2-1⁄4 percent chromium materials to prevent FAC.

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004; and January 31, and May 18, and 27, 2005; the staff

concurred with the applicant's evaluation of the aging effects of the materials and environments

associated with the reactor core isolation cooling system during the extended shutdown. The

staff did not identify any omitted aging effects. Therefore, the staff found that the applicant had

identified the appropriate aging effects for the Unit 1 reactor core isolation cooling system

during the extended shutdown.

Aging Management Programs. After evaluating the applicant's identification of aging effects, the

staff evaluated the AMPs to determine if they are appropriate for managing the identified aging

effects from the extended shutdown. The staff also verified that the UFSAR supplement

contains an adequate description of the program. 
3-412

Evaluation of the BFN Unit Layup and Preservation Program Tables 1 and 3 identify the

following AMPs for managing the aging effects described above for the reactor core isolation

cooling system in a dry layup or a treated-water environment.

 • ASME Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program

(B.2.1.4)

 • BWR Stress Corrosion Cracking Program (B.2.1.10)

 • Chemistry Control Program (B.2.1.5)

 • Flow-Accelerated Corrosion Program (B.2.1.15)

 • One-Time Inspection Program (B.2.1.29)

 • Selective Leaching of Materials Program (B.2.1.30)

 • Systems Monitoring Program (B.2.1.39)

The staff's detailed review of these AMPs is found in SER Section 3.0.3.1.3, 3.0.3.2.5,

3.0.3.2.2, 3.0.3.2.9, 3.0.3.1.7, 3.0.3.1.8, and 3.0.3.3.1, respectively.

In follow-up RAI 3.3-2, the staff questioned if one-time inspections are appropriate where there

may be insufficient operating experience. By letter dated May 27, 2005, the applicant clarified

the application of periodic inspections in lieu of one-time inspections for areas subject to

concentration of contaminants during layup. Targeted periodic inspections are going to be used

as compensatory actions to be performed after Unit 1 is returned to operation to verify no

additional aging effects are occurring. By letter dated November 16, 2005, the applicant also

clarified that the compensatory actions included visual and/or ultrasonic inspections to establish

the physical condition of systems and components not being replaced. The first periodic

inspection will be performed prior to the end of the current operating period and the subsequent

frequency will be determined based on the outcome of the first periodic inspections performed. 

The restart inspections can be utilized as a baseline for comparison as identified in the Unit 1

Periodic Inspection Program (SER Section 3.0.3.3.5). Systems and portions of systems for

which periodic inspections will be performed included MS, FW, RHRSW, RCW, EECW, fire

protection, reactor building closed cooling water, RCIC, HPCI, RHR, and CRD. The staff

concurred that application of targeted periodic internal visual and ultrasonic inspections of a

sample of susceptible locations is appropriate to manage potential latent aging effects in Unit 1

systems and portions of systems in layup that were not in operation during the extended outage

and have not been replaced.

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19, 2004, October 8, 2004, and January 31, 2005, the staff found that the

applicant had identified appropriate AMPs for managing the aging effects of the Unit 1 RCIC

system components during the extended shutdown. In addition, the staff found the program

descriptions in the UFSAR supplement acceptable.

Conclusion. On the basis of its review, the staff concluded that the applicant had adequately

identified the aging effects and the AMPs credited for managing the aging effects for the Unit 1

reactor core isolation cooling system components during the extended shutdown, so that there
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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 54.29(a). 

The staff also reviewed the applicable UFSAR supplement program descriptions and concluded

that the UFSAR supplement provides an adequate description of the AMPs credited for

managing aging in these components, as required by 10 CFR 54.21(d).

3.7.4.2 Auxiliary Systems in Wet Lay up

3.7.4.2.1 Reactor Water Cleanup System

Technical Staff Evaluation. The technical staff reviewed the AMR of the reactor water cleanup

system to determine whether the proposed aging management was adequate to address any

potential aging during the extended shutdown of Unit 1. The reactor water cleanup system is

described in LRA Section 2.3.3.21. LRA Table 3.3.2.21 contains the AMR for the system for

normal operation. LRA Section 3.0.1 states that Unit 1 reactor water cleanup system was

maintained in wet lay up during the extended shutdown. The applicant's February 19, 2004,

submittal of additional information, describes the applicant's process for evaluating the effects

of aging during the extended shutdown. The staff verified that the applicant had identified all

applicable AERMs during the extended shutdown and credited appropriate AMPs for managing

the AERMs. The staff also reviewed the applicable UFSAR supplements for the AMPs to

ensure that the program descriptions adequately describe the AMPs.

During its review, the staff determined that additional information was needed to complete its

review. General RAIs applicable to the RWCU system include RAI 3.0-1 LP, 3,0-3 LP, 3.0-5 LP,

3.0-7 LP, 3.0-8 LP, 3.0-9 LP, 3.0-10 LP, 3.0-11 LP. The description of these general RAIs, the

applicant's response to these RAIs and the staff's review of the applicant's responses are

included in SER Sections 3.7.1.1, 3.7.1.4, 3.7.1.3, 3.7.1.2, and 3.7.1.5. There are no

system-specific RAIs for the reactor water cleanup system.

Aging Effects. LRA Table 3.3.2.21 provides the AMR of the reactor water cleanup system

components within the scope of license renewal and subject to AMR. The component types

include piping and fittings, heat exchangers, pumps, restricting orifices, strainers, tanks, tubing,

and valves.

The LRA and the February 19, 2004, submittal of additional information, describe the

environment during the Unit 1 shutdown as follows: the internal environment was flowing,

air-saturated, demineralized water (treated water) and the outside environment was inside air.

For the Unit 1 system components, the applicant identified on Evaluation of the BFN Unit 1

Layup and Preservation Program Table 2, the following materials, environments, and AERMs:

carbon and low-alloy steel components exposed to treated water are subject to a loss of

material due to general corrosion, crevice corrosion, galvanic corrosion, and pitting corrosion;

stainless steel components in treated water are subject to a loss of material due to crevice and

pitting corrosion; cast iron and cast iron alloy components in treated water are subject to a loss

of material due to general corrosion, crevice corrosion, galvanic corrosion, and pitting corrosion

as well as selective leaching; copper and copper-alloy components in a treated-water

environment are subject to a loss of material due to crevice corrosion, pitting corrosion and
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selective leaching. Glass components in a treated-water environment experience no aging

effects; carbon and low-alloy steel components as well as cast iron and cast iron alloy

components in inside air are subject to a loss of material due to general corrosion; stainless

steel, copper alloy, and glass exposed to inside air experience no aging effects. 

Table 2 does not identify IGSCC for the stainless steel RWCU system components during layup

and LRA Section F.13 indicates that RWCU piping outside the primary containment isolation

valves will be replaced with IGSCC-resistant material. In response to general RAI 3.0-9 LP the

applicant submitted system-specific information in regard to specific components that will be

replaced prior to startup. By letter dated January 31,2005, the applicant clarified the scope and

basis for the following RWCU specific components being replaced with IGSCC-resistant

material prior to Unit 1 restart:

 • RWCU hot piping both inside and outside the drywell is being replaced with 316NG

 • RWCU valves replaced with 316L 

 • RWCU pumps (IGSCC related)

 • RWCU regenerative heat exchangers with 316L

Therefore, based on the commitment that stainless steel piping will be replaced with IGSCCresistant material prior to Unit 1 restart, the staff concluded that IGSCC is not a technical

concern for the RWCU system as a result of layup conditions during the extended shutdown.

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004; and January 31, and May 18 and 27, 2005; the staff

concurred with the applicant's evaluation of the aging effects of the materials and environments

associated with the reactor water cleanup system during the extended shutdown. The staff did

not identify any omitted aging effects. Therefore, the staff found that the applicant had identified

the appropriate aging effects for the Unit 1 reactor water cleanup system during the extended

shutdown.

Aging Management Programs. After evaluating the applicant's identification of aging effects, the

staff evaluated the AMPs to determine if they are appropriate for managing the identified aging

effects from the extended shutdown. The staff also verified that the UFSAR supplement

contains an adequate description of the program. 

Evaluation of the BFN Unit Layup and Preservation Program Table 2 identified the following

AMPs for managing the aging effects described above for the reactor water cleanup system in

wet layup. 

 • ASME Section XI Subsections IWB, IWC and IWD Inspection Program (B.2.1.4)

 • Bolting Integrity Program (B.2.1.16)

 • BWR Reactor Water Cleanup System Program (B.2.1.22)

 • Chemistry Control Program (B.2.1.5)

 • Closed-Cycle Cooling Water System Program (B.2.1.18)

 • One-Time Inspection Program (B.2.1.29)

 • Selective Leaching of Materials Program (B.2.1.30)

 • Systems Monitoring Program (B.2.1.39)
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The staff's detailed review of these AMPs is found in SER Sections 3.0.3.1.3, 3.0.3.2.10,

3.0.3.2.15, 3.0.3.2.2 3.0.3.2.12, 3.0.3.1.7, 3.0.3.1.8X, and 3.0.3.3.1, respectively.

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19, 2004, October 8, 2004, and January 31, 2005, the staff found the applicant

had identified appropriate AMPs for managing the aging effects of the Unit 1 reactor water

cleanup system components during the extended shutdown. In addition, the staff found the

program descriptions in the UFSAR supplement acceptable.

Conclusion. On the basis of its review, the staff concluded that the applicant had adequately

identified the aging effects, and the AMPs credited for managing the aging effects, for the

Unit 1 reactor water cleanup system components during the extended shutdown, so 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 54.29(a). 

The staff also reviewed the applicable UFSAR supplement program descriptions and concluded

that the UFSAR supplement provides an adequate description of the AMPs credited for

managing aging in these components, as required by 10 CFR 54.21(d).

3.7.4.2.2 Control Rod Drive System

Technical Staff Evaluation. The technical staff reviewed the AMR of the CRD system to

determine whether the proposed aging management was adequate to address any potential

aging during the extended shutdown of Unit 1. The CRD system is described in LRA

Section 2.3.3.29. LRA Table 3.3.2.29 contains the AMR for the system for normal operation.

LRA Section 3.0.1 states that the Unit 1 CRD system was maintained in wet layup during the

extended shutdown. The applicant's February 19, 2004, submittal (including Table 2) describes

the applicant's process for evaluating the effects of aging during the extended shutdown. The

staff verified that the applicant had identified all applicable AERMs during the extended

shutdown and credited appropriate AMPs for managing the AERMs. The staff also reviewed the

applicable UFSAR supplements for the AMPs to ensure that the program descriptions

adequately describe the AMPs.

During its review, the staff determined that additional information was needed to complete its

review. General RAIs 3.0-1 LP, 3.0-3 LP, 3.0-5 LP, 3.0-6 LP, 3.0-9 LP, and 3.0-10 LP are

related to the CRD system. The description of the general RAIs that relates to both the SSCs in

the auxiliary system and other mechanical system groups, the applicant's response to these

RAIs and the staff's review of the applicant's responses are in SER Sections 3.7.1.1, 3.7.1.4,

3.7.1.3, and 3.7.1.2. System-specific RAI 3.3-2 LP on the CRD system, the applicant's

responses and the staff's review of the applicant's responses are described below.

Aging Effects. LRA Table 3.3.2.29 provides the AMR of the CRD system components within the

scope of license renewal and subject to AMR. The component types include bolting, fittings,

fittings - RCPB, heat exchangers, piping, piping - RCPB, pumps, restricting orifice, rupture disk,

strainers, strainers - RCPB, tanks, tubing, valves, and valves - RCPB.

Table 2 of the February 19, 2004, submittal describes the environment during the Unit 1

shutdown as follows: the internal environment was flowing, air-saturated, demineralized water

(treated water) and the outside environment was inside air.
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For the Unit 1 system components, the applicant identified the following materials,

environments, and AERMs: carbon and low-alloy steel components exposed to air-saturated

demineralized water are subject to a loss of material due to general corrosion, crevice

corrosion, galvanic corrosion, and pitting corrosion; stainless steel and aluminum alloy

components in treated water are subject to a loss of material due to crevice and pitting

corrosion; carbon and low-alloy steel components as well as cast iron and cast iron alloy

components in inside air are subject to a loss of material due to general corrosion; stainless

steel, copper alloy, and aluminum alloy components exposed to inside air experience no aging

effects. 

In RAI 3.3-2 LP the staff requested the following additional information on Table 2 concerning

the internal environment and inspections for the CRD system.

LRA Table 3.3.2.29 and Table 2 of the supplement state that many carbon and low-alloy steel

components in the CRD system have an internal environment of raw water during normal

operation. However, Table 2 states that this environment is not applicable during the extended

outage. The applicant was requested to clarify the environment during the extended outage,

and discuss the implications of the environment on the aging of these components. The

applicant was requested to specify any applicable aging effects with the corresponding AMPs

and also discuss whether any inspections are planned to determine the extent of aging during

the extended outage.

The applicant responded to RAI 3.3-2 LP (b)1 by stating that the raw cooling water system

provides cooling water to the CRD pump oil cooler and thrust bearing. The applicant further

clarified that the following materials see the raw water environment during layup: carbon steel

piping and fittings, copper valves, copper heat exchanger (cooler) tubing, cast iron heat

exchanger (cooler) head.

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004; and January 31, and May 18, and 27, 2005; the staff

concurred with the applicant's evaluation of the aging effects of the materials and environments

associated with the CRD system during the extended shutdown. The staff did not identify any

omitted aging effects. Therefore, the staff found that the applicant had identified the appropriate

aging effects for the unit CRD system during the extended shutdown.

Aging Management Programs. After evaluating the applicant's identification of aging effects, the

staff evaluated the AMPs to determine if they are appropriate for managing the identified aging

effects from the extended shutdown. The staff also verified that the UFSAR supplement

contains an adequate description of the program. 

Evaluation of the BFN Unit Layup and Preservation Program Table 3 identifies the following

AMPs for managing the aging effects described above for the CRD system in wet layup:

 • BWR Stress Corrosion Cracking Program (B.2.1.10)

 • Chemistry Control Program (B.2.1.5)

 • One-Time Inspection Program (B.2.1.29)

 • Open-Cycle Cooling Water System Program (B.2.1.17)

 • Selective Leaching of Materials Program (B.2.1.30)

 • Systems Monitoring Program (B.2.1.39)
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The staff's detailed review of these AMPs is found in SER Section 3.0.3.2.5, 3.0.3.2.2,

3.0.3.1.7, 3.0.3.2.11, 3.0.3.1.8, and 3.0.3.3.1, respectively.

In response to RAI 3.3-2 LP, the applicant stated that a sample of components with a raw water

environment within the CRD system (85) will be inspected for the following aging effects by the

One-Time Inspection Program.

 • Carbon and low-alloy steel – Loss of material due to general corrosion, crevice

corrosion, pitting corrosion, galvanic corrosion, microbiologically influenced corrosion,

and biofouling 

 • Copper and copper alloys – Loss of material due to crevice corrosion, pitting corrosion,

microbiologically influenced corrosion, biofouling, and selective leaching

 • Cast iron and cast iron alloys - Loss of material due to general corrosion, crevice

corrosion, pitting corrosion, galvanic corrosion, microbiologically influenced corrosion,

biofouling, and selective leaching

The staff reviewed the applicant's above response to the RAI and determined that additional

information was required. In follow-up RAI 3.3-2 LP the applicant was requested to clarify

whether one-time inspection is appropriate to manage aging of carbon steel, cast iron and

copper-based components in a raw water environment during layup. 

The applicant's response to follow-up RAI 3.3-2 LP stated that there is no need to perform a

one-time inspection on the components that were subjected to a raw water environment during

layup. The applicant indicated that the inspections would have been better characterized as

"restart inspection" instead of "One-Time Inspection.” The applicant further stated that once the

CRD system is returned to service the components will have the same AMPs applied to them

as their current Unit 2 and 3 counterpart components.

Staff reviewed the applicant’s response and concurred that, in general, restart inspections are

appropriate to detect and correct degradation experienced during layup. However, staff is

concerned that one-time inspections performed during the extended outage may not be

appropriate to detect latent aging effects in the CRD system resulting from layup during the

extended operating period. Latent aging effects are anticipated in crevices and in stagnant

areas where contaminants are concentrated. For areas subject to concentration of

contaminants during layup, the applicant should justify the application of one-time inspections in

lieu of periodic inspections. By letter dated May 27, 2005, the applicant clarified the application

of periodic inspections in lieu of one-time inspections for areas subject to concentration of

contaminants during layup. Targeted periodic inspections are going to be used as

compensatory actions to be performed after Unit 1 is returned to operation to verify no

additional aging effects are occurring. By letter dated November 16, 2005, the applicant also

clarified that the compensatory actions included visual and/or ultrasonic inspections to establish

the physical condition of systems and components not being replaced. The first periodic

inspection will be performed prior to the end of the current operating period and the subsequent

frequency will be determined based on the outcome of the first periodic inspections performed. 
3-418

The restart inspections can be utilized as a baseline for comparison as identified in the Unit 1

Periodic Inspection Program (SER Section 3.0.3.3.5). Systems and portions of systems for

which periodic inspections will be performed included MS, FW, RHRSW, RCW, EECW, fire

protection, reactor building closed cooling water, RCIC, HPCI, RHR, and CRD. The staff

concurred that application of targeted periodic internal visual and ultrasonic inspections of a

sample of susceptible locations is appropriate to manage potential latent aging effects in Unit 1

systems and portions of systems in layup that were not in operation during the extended outage

and have not been replaced.

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004; and January 31, and May 18 and 27, 2005; the staff

found the applicant had identified appropriate AMPs for managing the aging effects of the

Unit 1 CRD system components during the extended shutdown. In addition, the staff found the

program descriptions in the UFSAR supplement acceptable.

Conclusion. On the basis of its review, the staff concluded that the applicant had adequately

identified the aging effects and the AMPs credited for managing the aging effects [pending

resolution of the general RAIs] for the Unit 1 CRD system components during the extended

shutdown, so 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 54.29(a). 

The staff also reviewed the applicable UFSAR supplement program descriptions and concluded

that the UFSAR supplement provides an adequate description of the AMPs credited for

managing aging in these components, as required by 10 CFR 54.21(d).

3.7.4.3 Auxiliary Systems Not in Layup Program

During its review of auxiliary systems, the staff determined that additional information was

needed to complete its review. By letter dated August 23, 2004, the staff issued general

RAI 3.3-1 LP requesting the following additional information on systems and portions of

systems that were not included in the layup program.

LRA Section 3.0.1 describes the criteria for evaluating systems for aging during the

extended outage. Systems that remain in operation for Unit 1 or in support of operation

for Units 2 and 3 are not evaluated. However, based on the system descriptions, it

appears that at least a portion of the following systems should have been evaluated

(i.e., it appears that the system was idle or that only the main headers were needed to

support operation of Units 2 and 3). Discuss the operation of the following systems

during the extended shutdown, and explain why these systems were not evaluated for

aging during the extended shutdown.

 • Residual Heat Removal Service Water System (023)

 • Control Air System (032)

 • Sampling and Water Quality System (043)

 • Emergency Equipment Cooling Water System (067)

 • Reactor Water Cleanup System (069)

 • Reactor Building Closed Cooling Water System (070)
3-419

 • Radioactive Waste Treatment System (077)

 • Neutron Monitoring System (092)

If it is determined that these systems, or portions thereof, met the criteria for evaluation,

provide an evaluation of aging during the extended outage. Include a description of the

environment, identification of AERMs, and proposed aging management. Also, discuss

any inspections that are planned to determine the extent of aging during the extended

outage.

By letter dated October 8, 2004, the applicant responded to RAI 3.3-1 LP by providing the

following additional information.

With regard to residual heat removal service water system (23) and emergency equipment

cooling water system (67), the applicant stated that the Unit 1 portions of piping and

components for these systems not required for Unit 2 and 3 operation are not in the layup

program. The piping and components in these systems are in shared systems and contained

either raw water or moist air during the extended outage period. The applicant stated that these

systems have been evaluated for a raw water and/or moist air environment for the in-service

portions of these systems. The aging effects identified for the operating conditions encompass

the aging effects for the layup conditions. The restart inspection will be performed prior to Unit 1

restart to verify the material condition.

The applicant also stated that for control air system (32) the Unit 1 piping components of this

system not required for Unit 2 and 3 operation but in scope for license renewal is not in the

layup program. For this system, any additional aging effects would be due to moisture collecting

in the system components. For the operating condition the internal environment is air/gas

without a significant amount of moisture present. During layup there were no moisture controls

on the non-operating Unit 1 portions of this system. Without moisture controls the possibility of

moisture collecting at system low points exists. The aging effects associated with moist air are

contained in the detailed layup evaluation of the containment inerting system (76) and the

containment atmosphere dilution system (84). The potential aging effects for the control air will

be similar to those identified for the containment inerting and containment atmosphere dilution

systems. The restart inspection will be performed prior to Unit 1 restart to verify the material

condition.

For the sampling and water quality system (43), the applicant stated that the Unit 1 piping and

components of this system not required for Unit 2 and 3 operation are not in the lay-up

program. The piping and components in this system contained treated water, raw water,

and/or moist air during the extended outage period. This system has been evaluated for these

environments for the operating condition. The aging effects identified for the operating

conditions encompass the aging effects for the layup conditions. The restart inspection will be

performed prior to Unit 1 restart to verify the material condition. Related to the reactor water

cleanup system (69), the applicant stated that the system was evaluated per BFN Unit 1, Layup

and Preservation Program, Table 2.

For the reactor building closed cooling water system (70) the applicant stated that portions of

the Unit 1 piping and components of this system not required for Unit 2 and 3 operation are not

in the layup program. The piping and components in this system contained treated water

maintained to CI-13.1 and/or moist air during the extended outage period. The aging effects
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associated with treated water maintained to CI-13.1 are contained in the detailed layup

evaluation of the reactor core isolation cooling system (71), the HPCI system (73), and the core

spray system (75). The potential aging effects for the closed cooling water system (70) will be

similar to those identified for the reactor core isolation cooling system (71), the HPCI system

(73), and the core spray system (75). The restart inspection will be performed prior to Unit 1

restart to verify the material condition.

For the radioactive waste treatment system (77), the applicant stated that the Unit 1 piping and

components for this system are not in the layup program. The piping and components in this

system within the LRA scope remained in-service. An aging effects evaluation was performed

for this system and documented in LRA Table 3.3.2.25. 

Finally, related to the neutron monitoring system (92), the applicant stated that the Unit 1

portions of piping and components for this system are not in the layup program. The portion of

this system that is within the scope of license renewal is part of the reactor vessel pressure

boundary. An aging effects evaluation was performed for the Unit 1 layup portions of the RVI

system. The aging effects evaluation for the RV and RVI encompasses the neutron monitoring

system (92). The restart inspection will be performed prior to Unit 1 restart to verify the material

condition.

With the staff issue raised in RAI 3.0-3 LP concerning MIC in stagnant areas, the staff reviewed

the applicant's response to RAI 3.0-3 and, in general, found it to be reasonable and acceptable

because it clarified that the subject systems were either in-service or were not part of the layup

program. Systems that were in service during the extended outage are reviewed as part of the

AMR. For systems that were not part of the layup program, the applicant includes an evaluation

of aging effects and credits restart inspections to verify the material condition. In these systems,

the applicant's evaluation of aging effects determined that aging effects identified for the

operating conditions encompass the aging effects for the layup conditions. The staff's

evaluation of restart inspections to manage aging effects including MIC for stagnant systems

not in-service can be found in SER Sections 3.0.3.3.5, 3.7.1.3, and 3.7.1.4.

3.7.5 Steam and Power Conversion Systems

3.7.5.1 Steam and Power Conversion Systems in Wet Layup

3.7.5.1.1 Feedwater System

Technical Staff Evaluation. The technical staff reviewed the AMR of the feedwater system (03)

to determine whether the proposed aging management was adequate to address any potential

aging during the extended shutdown of Unit 1. The feedwater system is described in LRA

Section 2.3.4.3. LRA Table 3.4.2.3 contains the AMR for the system for normal operation. LRA

Section 3.0.1 states that Unit 1 feedwater system was maintained in wet layup during the

extended shutdown. The applicant's February 19, 2004, submittal describes the applicant's

process for evaluating the effects of aging during the extended shutdown. The staff verified that

the applicant identified all applicable AERMs during the extended shutdown and credited

appropriate AMPs for managing the AERMs. The staff also reviewed the applicable UFSAR

supplements for the AMPs to ensure that the program descriptions adequately describe the

AMPs.
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Aging Effects. Table 2 of the applicant's February 19, 2004, submittal provides the AMR of the

feedwater system components within the scope of license renewal that were maintained in wet

layup conditions. The component types include bolting, fittings, piping, restricting orifices,

tubing, and valves. 

The February 19, 2004, submittal states that portions of the Unit 1 feedwater system are within

the boundary of the layup program. However, the portions of the Unit 1 feedwater system within

the scope of license renewal sees the same water as the portions of Unit 1 reactor vessel and

internals system, boiler drains and vents system, recirculation system, reactor water cleanup

system, and CRD system. The applicant stated that BFN maintains the internal environment of

these systems with flowing, air-saturated, demineralized water per the CI-13.1 chemistry

program. Due to drainage and system isolation, portions of these systems did not see the same

environment as that seen by the portions of the Unit 1 feedwater system within the scope of

license renewal, for an extended period of time. The applicant stated, however, that the

evaluation for treated water encompasses the aging effects for a moist air environment in these

systems. 

For the Unit 1 feedwater system components, the applicant identified the following materials,

environments, and AERMs: carbon and low-alloy steel components in treated water (internal)

environments are subject to loss of material due to general, crevice, pitting, and galvanic

corrosion; carbon and low-alloy steel components in inside air (external) environments are

subject to loss of material due to general corrosion; stainless steel components in treated water

(internal) environments are subject to loss of material due to crevice and pitting corrosion;

copper-alloy components in air/gas (internal) moist environments are subject to loss of material

due to crevice, galvanic, and pitting corrosion, as well as selective leaching; no AERMS were

identified for stainless steel and copper-alloy components in inside air (external) environments.

On the basis of its review of the information provided in the LRA, as supplemented by letter

dated February 19, 2004, the staff concurred with the applicant's evaluation of the aging effects

of the materials and environments associated with the feedwater system during the extended

shutdown. The staff did not identify any omitted aging effects. Therefore, the staff found that

the applicant had identified the appropriate aging effects for the Unit 1 feedwater system during

the extended shutdown.

Aging Management Programs. After evaluating the applicant's identification of aging effects, the

staff evaluated the AMPs to determine if they are appropriate for managing the identified aging

effects from the extended shutdown. The staff also verified that the UFSAR supplement

contains an adequate description of the program. 

Table 2 of the applicant's February 19, 2004, submittal identifies the following AMPs for

managing the aging effects described above for the feedwater system.

 • ASME Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program

(B.2.1.4)

 • Chemistry Control Program (B.2.1.5)

 • Flow-Accelerated Corrosion Program (B.2.1.15)

 • One-Time Inspection Program (B.2.1.29)
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SER Sections 3.0.3.1.3, 3.0.3.2.2, 3.0.3.2.9, and 3.0.3.1.7, respectively, present the staff's

detailed review of these AMPs.

During its review, the staff determined that additional information was needed to complete its

review. 

In Table 2 of the February 19, 2004, submittal, for the feedwater system (03), the applicant

indicated that carbon and low-alloy steel components in inside air (external) environments are

subject to loss of material due to general corrosion, because the components' surface

temperature is less than 212 °F during the period of extended outage. The applicant indicated

that the components will be inspected for external corrosion prior to Unit 1 restart, without

providing details for the inspection provided. The applicant also indicated that inspections will

be performed prior to Unit 1 restart for the copper-alloy components for which additional aging

effects (i.e., loss of material due to crevice, galvanic, and pitting corrosion, and selective

leaching) were identified for the extended outage. These additional aging effects are the results

of the presence of moist air in system locations where condensation could build up. The

applicant indicated that inspections will be performed for the components prior to Unit 1 restart,

but again, provided no descriptions of the inspections. 

In RAI 3.0-7 LP, the staff requested the applicant to discuss the proposed inspections, including

scope, method, procedure, parameters monitored and trended, detection of aging effects, and

acceptance criteria, in order to justify the adequacy of the inspections. By letter dated

October 8, 2004, the applicant stated that external surface monitoring will be performed for the

affected carbon and low-alloy steel components in accordance with the Systems Monitoring

Program described in LRA, Appendix B, LRA Section B.2.1.39. The applicant noted that this is

the same AMP proposed for managing external loss of material during the period of extended

operation. By letters dated January 31 and May 18, 2005, and January 31, 2006, the applicant

stated that restart inspections of the internal surface will be performed prior to Unit 1 restart to

verify the material condition for the affected copper-alloy components. The applicant also

committed to perform the Unit 1 Periodic Inspection Program for specific locations of piping and

fitting components before and during the period of extended operation. The staff determined

the Systems Monitoring Program to be adequate in managing the external aging effects. The

staff also determined that the applicant's commitment of performing restart inspections,

followed by periodic inspections, for the internal aging effects is acceptable. RAI 3.0-7 LP is,

therefore, closed for the feedwater system. The staff's discussion of the general adequacy of

restart inspections managing the aging effects versus periodic inspections during the period of

extended outage is provided in SER Section 3.7.1.

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004; and January 31, and May 18 and 27, 2005, the staff

found the applicant had identified appropriate AMPs for managing the aging effects of the

Unit 1 feedwater system components during the extended shutdown. In addition, the staff found

the program descriptions in the UFSAR supplement acceptable.

Conclusion. On the basis of its review, the staff concluded that the applicant had adequately

identified the aging effects and the AMPs credited for managing the aging effects for the Unit 1

feedwater system components during the extended shutdown, so 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 54.29(a). 
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The staff also reviewed the applicable UFSAR supplement program descriptions and concluded

that the UFSAR supplement provides an adequate description of the AMPs credited for

managing aging in these components, as required by 10 CFR 54.21(d).

3.7.5.2 Steam and Power Conversion Systems in Various Wet Environments

3.7.5.2.1 Condenser Circulation Water System

Technical Staff Evaluation. The technical staff reviewed the AMR of the condenser circulation

water system (27) to determine whether the proposed aging management was adequate to

address any potential aging during the extended shutdown of Unit 1. The condenser circulation

water system is described in LRA Section 2.3.4.6. LRA Table 3.4.2.6 provides the AMR for the

system for normal operation. LRA Section 3.0.1 and the applicant's February 19, 2004,

submittal states that the portion of Unit 1 condenser circulation water system within the scope of

license renewal was not incorporated into the wet layup program, but was included in the

evaluation. Based, in part, on location and valve leakage, the components within the scope of

license renewal for the condenser circulation water system (27) experienced raw stagnant water

for extended periods of time. The applicant's February 19, 2004, submittal describes the

applicant's process for evaluating the effects of aging during the extended shutdown. The staff

verified that the applicant identified all applicable AERMs during the extended shutdown and

credited appropriate AMPs for managing the AERMs. The staff also reviewed the applicable

UFSAR supplements for the AMPs to ensure that the program descriptions adequately describe

the AMPs.

Aging Effects. Table 3 of the February 19, 2004, submittal provides the AMR of the condenser

circulation water system components within the scope of license renewal thath were not

incorporated into the wet layup program. The component types include bolting, fittings, piping,

strainers, tubing, and valves.

The February 19, 2004, submittal identified raw water as the internal environment of the

system, and the external environment was inside air, outside air, buried, and

embedded/encased.

For the Unit 1 condenser circulation water system components, the applicant identified the

following materials, environments, and AERMs: carbon and low-alloy steel components in raw

water (internal) environments are subject to loss of material due to general, crevice, and pitting

corrosion, as well as loss of material due to biofouling and MIC; carbon and low-alloy steel

components in inside air (external) and outside air (external) environments are subject to loss of

material due to general corrosion; carbon and low-alloy steel components in buried (external)

environments are subject to loss of material due to general, crevice, and pitting corrosion, as

well as MIC; cast iron and cast iron alloy components in raw water (internal) environments are

subject to loss of material due to general, crevice, and pitting corrosion, as well as loss of

material due to biofouling and MIC; cast iron and cast iron alloy components in inside air

(external) environments are subject to loss of material due to general corrosion; no aging

effects are identified for carbon and low-alloy steel components in embedded/encased

(external) environments, and stainless steel and copper-alloy components in inside air

(external) environments. 
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During its review, the staff determined that additional information was needed to complete its

review. 

In Table 3 of its February 19, 2004, submittal, the applicant stated that, for the condenser

circulation water system (27), carbon and low-alloy steel components and cast iron and cast

iron alloy components in raw water (internal) environments were susceptible to loss of material. 

due to general, crevice, and pitting corrosion, as well as loss of material due to biofouling and

MIC. Since the components were exposed to raw stagnant water for an extended period of

time, portions of the components, especially those at low points, may have already been

subject to aging degradation far more severe than their Units 2 and 3 counterparts in normal

plant operation. In RAI 3.4-2 LP, the staff requested the applicant to justify the basis for not

performing inspections for the aging effects prior to Unit 1 restart. By letter dated October 8,

2004, the applicant stated that during normal operation and layup, condenser circulation water

system components saw raw stagnant water. Restart inspections will be performed prior to

Unit 1 restart to verify the material condition. The staff determined that the applicant's

commitment of performing restart inspections prior to Unit 1 restart is acceptable, and RAI 3.4-2

LP is closed. The staff's discussion of the general adequacy of the applicant's restart

inspections for systems containing raw water during layup is provided in SER Section 3.7.1. 

In Table 3 of its February 19, 2004, submittal, the applicant stated that, for condenser

circulation water system (27), cast iron and cast iron alloy components (valves, fittings, etc.)

were exposed to raw water (internal) environments, and identified no aging effects due to

selective leaching. The staff noted that in raw water environments, leaching in the form of

graphitic corrosion could occur with loss of iron matrix from gray cast iron. In addition, gray cast

iron can also display the effects of selective leaching in relatively mild environments. In

RAI 3.4-3 LP, the staff requested the applicant to discuss why selective leaching is not

identified as a potential aging mechanism requiring management for the components. By letter

dated October 8, 2004, the applicant stated that the aging effects write-up in its February 19,

2004, submittal did identify selective leaching as an aging mechanism for gray cast iron for the

condenser circulation water system, and the line item in Table 3 should have included selective

leaching for gray cast iron in the system. This response is acceptable to the staff, and RAI 3.4-3

LP is closed.

In Table 3 of the applicant's February 19, 2004, submittal, the applicant indicates that

components in the condenser circulation water system (27) and gland seal water system (37)

are exposed to an air/gas internal environment during normal operation, whereas the

environment during the extended outage is noted as "N/A.” This table states that, due to

drainage and system isolation, portions of these systems saw a moist air environment for

extended periods of time. The table states, however, that the evaluation for raw and treated

water encompasses the aging effects for a moist air environment in these systems. In RAI 3.0-5

LP, the staff requested the applicant to explain why the evaluation of the aging effects for the

raw and treated-water environment would encompass that of the aging effects for a moist air

environment in these systems, since the rate of loss of material caused by a moist air

environment during layup may be more severe than a flowing raw or treated-water environment

during normal operation. By letter dated October 8, 2004, the applicant stated that Table 3

addresses the aging management for portions of several systems (including condenser

circulation water and gland seal water systems) laid up in a wet environment. Due to closure

sequence, closure timing, and possible leakage past the double isolation valves or two drain

valves for these systems, it is assumed that an air/gas environment with an uncertain amount of
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moisture was trapped between the double isolation valves. The trapped moisture between the

double isolation valves was considered the same (i.e., raw or treated water) as was flowing

through the valves prior to closure. The applicant stated that the N/A (not applicable) denotes

that this trapped air/gas environment will be evaluated under the corresponding raw or treated

water evaluations. 

The applicant stated that the evaluation of these moist air environments for the systems

addressed in Table 3 identified no additional aging effects other than those identified for the

corresponding raw or treated-water environment. The applicant stated that the LRA identified

these trapped air environments for one-time inspections because the extent of corrosion could

be quantified. It was not the intent of this AMR to determine the rate of loss of material. The

applicant further stated that the restart inspection will be performed prior to Unit 1 restart to

verify the material condition. 

The staff determined that the applicant had adequately explained the nature of the trapped

air/gas environments, and why the evaluation of the aging effects for the raw and treated-water

environments, in the above two systems, would encompass that of the aging effects for a moist

air environment in these systems. The applicant also committed to perform restart inspections

prior to Unit 1 restart, to verify the material condition of the system components. This is

acceptable to the staff, and RAI 3.0-5 LP is closed for the condenser circulation water system

(27) and gland seal water system (37) systems. The staff's discussion of the general adequacy

of the restart inspections for systems containing treated water and raw water during layup is

provided in SER Section 3.7.1. 

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004; and January 31, and May 18 and 27, 2005; the staff

concurred with the applicant's evaluation of the aging effects of the materials and environments

associated with the condenser circulation water system during the extended shutdown. The

staff did not identify any omitted aging effects. Therefore, the staff found that the applicant had

identified the appropriate aging effects for the Unit 1 condenser circulation water system during

the extended shutdown.

Aging Management Programs. After evaluating the applicant's identification of aging effects, the

staff evaluated the AMPs to determine if they are appropriate for managing the identified aging

effects from the extended shutdown. The staff also verified that the UFSAR supplement

contains an adequate description of the program. 

Table 3 identifies the following AMPs for managing the aging effects described above for the

condenser circulating water system.

 • One-Time Inspection Program (B.2.1.29)

 • Buried Piping and Tanks Inspection Program (B.2.1.31)

 • Systems Monitoring Program (B.2.1.39)

SER Sections 3.0.3.1.7, 3.0.3.1.9, and 3.0.3.3.1, respectively, present the staff's detailed

review of these AMPs.

During its review, the staff determined that additional information was needed to complete its

review. 
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In Table 3 of its February 19, 2004, submittal, the applicant identified no additional AMPs for the

components in this layup system, other than the above AMPs specified in the LRA for the

period of extended operation. In RAI 3.0-6 LP, the staff requested the applicant to justify the

conclusion by discussing the water samples performed for the normal operation and the period

of extended outage. By letter dated October 8, 2004, the applicant stated that the condenser

circulation water system was exposed to Tennessee River water, which is the same

environment it is exposed to during normal operation. Without the addition of foreign chemicals,

the aging effects during normal operation and during layup are the same. However, the

applicant stated that the restart inspection will be performed prior to Unit 1 restart to verify the

material condition. This commitment is acceptable to the staff, and RAI 3.0-6 LP is closed for

the condenser circulation water system. The staff's discussion of the general adequacy of the

restart inspections as it relates to the systems containing raw water during layup is provided in

SER Section 3.7.1.

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004; January 31, and May 18 and 27, 2005; the staff found

the applicant had identified appropriate AMPs for managing the aging effects of the Unit 1

condenser circulation water system components not incorporated in the wet layup program

during the extended shutdown. In addition, the staff found the program descriptions in the

UFSAR supplement acceptable.

Conclusion. On the basis of its review, the staff concluded that the applicant had adequately

identified the aging effects, and the AMPs credited for managing the aging effects, for the

Unit 1 condenser circulation water system components during the extended shutdown, so 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 54.29(a). 

The staff also reviewed the applicable UFSAR supplement program descriptions and concluded

that the UFSAR supplement provides an adequate description of the AMPs credited for

managing aging in these components, as required by 10 CFR 54.21(d). 

3.7.5.2.2. Gland Seal Water System

Technical Staff Evaluation. The technical staff reviewed the AMR of the gland seal water

system (37) to determine whether the proposed aging management was adequate to address

any potential aging during the extended shutdown of Unit 1. The gland seal water system is

described in LRA Section 2.3.4.7. LRA Table 3.4.2.7 contains the AMR for the system for

normal operation. LRA Section 3.0.1 and the applicant's February 19, 2004, submittal states

that the portion of the Unit 1 gland seal water system within the scope of BFN license renewal

was not incorporated into the BFN wet layup program, but was included in the evaluation.

Based on location, valve leakage, etc., the components within the scope of license renewal for

the gland seal water system (37) saw treated water for extended periods of time. The

applicant's February 19, 2004, submittal describes the applicant's process for evaluating the

effects of aging during the extended shutdown. The staff verified that the applicant had

identified all applicable AERMs during the extended shutdown and credited appropriate AMPs

for managing the AERMs. The staff also reviewed the applicable UFSAR supplements for the

AMPs to ensure that the program descriptions adequately describe the AMPs.
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Aging Effects. Table 3 of the February 19, 2004, submittal provides the AMR of the gland seal

water system components within the scope of license renewal that were not incorporated into

the BFN wet layup program. The component types include bolting, fittings, piping, tanks, tubing,

and valves.

The February 19, 2004, submittal identified treated water as the internal environment of the

system, and the external environment was inside air. 

For the Unit 1 gland seal water system components, the applicant identified the following

materials, environments, and AERMs: carbon and low-alloy steel components in treated water

(internal) environments are subject to loss of material due to general, crevice, pitting, and

galvanic corrosion; carbon and low-alloy steel components in inside air (external) environments

are subject to loss of material due to general corrosion; copper-alloy components in treated

water (internal) environments are subject to loss of material due to selective leaching, crevice

and pitting corrosion; cast iron and cast iron alloy components in treated water (internal)

environments are subject to loss of material due to general, crevice, and pitting corrosion, as

well as selective leaching; cast iron and cast iron alloy components in inside air (external)

environments are subject to loss of material due to general corrosion; no AERMS are identified

for carbon and low-alloy steel in air/gas (internal) environments, copper alloy components in

air/gas (internal) environment, and cast iron and cast iron alloy in air/gas (internal)

environments no aging effects are identified for glass components in treated water (internal),

air/gas (internal), and inside air (external) environments.

During its review, the staff determined that additional information was needed to complete its

review. 

In Table 3 of its February 19, 2004, submittal, the applicant stated that the portion of the gland

seal water system (37) within the scope of license renewal was not incorporated into the Unit 1

wet layup program. The applicant identified various aging effects for carbon and low-alloy steel,

copper alloy, and cast iron and cast iron alloy components in treated water (internal)

environments. To ensure that these components have not been subjected to aging degradation

more severe than their Units 2 and 3 counterparts during plant operation, in RAI 3.4-1 LP, the

staff requested that the applicant (1) describe the general environments associated with the

above system components; (2) provide a detailed description of the water chemistry of the

treated water and discuss its differences from the water chemistry existing in the plant

operation; (3) discuss any water chemistry monitoring that had been performed for the treated

water during the layup period; (4) discuss the possibility of incurring more severe aging

degradations to these layup components than could have occurred during plant operation,

considering the potential effects of different water temperature and stagnant flow condition; (5)

discuss how the latent effect of the potentially more severe aging degradation occurring in the

Unit 1 layup can be accounted for in the license AMR; and (6) justify the basis for not
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performing inspections for potential aging effects for these components prior to Unit 1 restart.

By letter dated October 8, 2004, the applicant provided the following information:

 1. Gland seal water system was drained (ambient air present) with the gland seal tank in

component layup per MPI-1-000-TNK002. However, it was assumed that the secondary

containment loop seal as well as other low points in the system were not completely

drained (the layup environment for the system is treated (condensate) water and moist

air from possible pooling of treated water between drain or isolation valves and in the

loop seals). Therefore, stagnant treated water supplied from the condensate system

(02) was evaluated for these areas. 

 2. The impurity administrative goals for conductivity, chloride, and sulfate given in CI-13.1

are 2.0. μS/cm, 75 ppb, and 75 ppb, respectively. Sampling is performed weekly. The

chemistry program implemented during the wet layup period is essentially the same

program that BFN uses on the two operating units during cold shutdown conditions for

refueling and maintenance outage. This extended operation program would consist of

CI-13.1 "Chemistry Program" controls which would continue to be based on the EPRI

BWR Water Chemistry Guidelines (TR-103515).

 3. As discussed in Item (1), the treated water is sampled and monitored per the Chemistry

Control Program CI-13.1. The aging effects/aging mechanisms for the components

within the systems in layup are similar to those determined for the operational units.

 4. As discussed in Item (1), the possibility of low flow or stagnant conditions exists in this

system. Due to low flow conditions in the system, the restart inspection will be

performed prior to Unit 1 restart to verify the material condition.

 5. There have been no latent effects identified for the chemistry program implemented

during the Unit 1 wet layup period. This program is essentially the same program that

BFN uses for operating units during cold shutdown conditions for refueling and

maintenance outages (EPRI BWR Water Chemistry Guidelines TR-103515-R2).

 6. The restart inspection will be implemented prior to Unit 1restart.

Based on the above responses to the RAI, the staff considered that the applicant had

adequately addressed its concerns, and ensured that the wet layup components in the system

had not been subjected to aging degradation more severe than their Units 2 and 3 counterparts

during plant operation. RAI 3.4-1 LP is, therefore, closed for the gland seal water system. The

staff's discussion for the general adequacy of the One-Time Inspection Program as a

verification program for layup and chemistry control is provided in SER Section 3.7.1.3. 

Table 3 of the applicant's February 19, 2004, submittal indicates that components in the gland

seal water system (37) are exposed to an air/gas internal environment during normal operation,

whereas the environment during the extended outage is noted as "N/A.” This table states that,

due to drainage and system isolation, portions of this system may have been exposed to an

internal environment of moist air. The table also states that the evaluation for treated water

encompasses the aging effects for a moist air environment in this system. In RAI 3.0-5 LP, the

staff requested the applicant to explain why the evaluation of the aging effects for the

treated-water environment would encompass that of the aging effects for a moist air

environment in this system, since the rate of loss of material caused by a moist air environment

during layup may be more severe than a flowing treated-water environment during normal
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operation. The staff's discussion of this RAI and its resolution by the applicant are provided in

SER Section 3.7.5.2.1. 

Table 3 of the applicant's February 19, 2004, submittal indicates that, for gland seal water

system (37), copper-alloy components and cast iron and cast iron alloy components saw

treated (condensate) water for an extended period of time. The applicant identified loss of

material due to general corrosion, selective leaching, crevice corrosion, and pitting corrosion as

the AERMs. In RAI 3.4-4 LP, the staff requested the applicant to explain why galvanic corrosion

is not identified as a potential aging mechanism for the components. By letter dated October 8,

2004, the applicant stated that the cast iron components within the gland seal water system

(37) are in contact with carbon steel piping. Cast iron and carbon steel are grouped together in

the galvanic series as similar metals. Since cast iron components within the system are not in

contact with more cathodic materials, galvanic corrosion is not a concern. Similarly,

copper-alloy components are not in contact with a more cathodic material such as stainless

steel within the gland seal water system. Therefore, galvanic corrosion is not a concern. The

staff found the applicant's explanation to be acceptable, and RAI 3.4-4 LP is closed. 

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004; and January 31, and May 18 and 27, 2005; the staff

concurred with the applicant's evaluation of the aging effects of the materials and environments

associated with the gland seal water system during the extended shutdown. The staff did not

identify any omitted aging effects. Therefore, the staff found that the applicant had identified the

appropriate aging effects for the Unit 1 gland seal water system during the extended shutdown.

Aging Management Programs. After evaluating the applicant's identification of aging effects, the

staff evaluated the AMPs to determine if they are appropriate for managing the identified aging

effects from the extended shutdown. The staff also verified that the UFSAR supplement

contains an adequate description of the program. 

Table 3 of the applicant's February 19, 2004, submittal identifies the following AMPs for

managing the aging effects described above for the gland seal water system.

 • Chemistry Control Program (B.2.1.5)

 • One-Time Inspection Program (B.2.1.29)

 • Selective Leaching of Materials Program (B.2.1.30)

 • Systems Monitoring Program (B.2.1.39)

SER Sections 3.0.3.2.2, 3.0.3.1.7, 3.0.3.1.8, and 3.0.3.3.1, respectively, present the staff's

detailed review of these AMPs.

During its review, the staff determined that additional information was needed to complete its

review. 

Table 3 of the applicant's February 19, 2004, submittal indicates that components in the gland

seal water system (37) were exposed to treated (non-controlled) water environments during the

extended outage. Table 3 identified no additional AMPs for this layup system, other than those

AMPs specified in the LRA for the period of extended operation. In RAI 3.0-6 LP, the staff

requested the applicant to justify the determination by discussing the water sampling performed

for the normal operation and the period of extended outage. By letter dated October 8, 2004,
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the applicant stated that the system had been drained (ambient air present) with gland seal tank

in component layup per MPI-1-000-TNK002. However, it was assumed that the secondary

containment loop seal as well as other low points in the system had not been completely

drained. Therefore, stagnant treated water supplied from the condensate system (02) was

evaluated for these areas. The applicant stated that a restart inspection will be performed prior

to Unit 1 restart to verify the material condition. The staff found the applicant's commitment to

perform a restart inspection for the potential low points in the system to be acceptable, and

RAI 3.0-6 LP is closed for the gland seal water system. The staff's discussion of the general

adequacy of the restart inspections in managing the identified aging effects for the system

components, as opposed to periodic inspections, is provided in SER Section 3.7.1.

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004, January 31, 2005, May 18 and 27, 2005, the staff

found the applicant had identified appropriate AMPs for managing the aging effects of the

Unit 1 gland seal water system components not incorporated in the wet layup program during

the extended shutdown. In addition, the staff found the program descriptions in the UFSAR

supplement acceptable.

Conclusion. On the basis of its review, the staff concluded that the applicant had adequately

identified the aging effects and the AMPs credited for managing the aging effects for the Unit 1

gland seal water system components during the extended shutdown, so 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 54.29(a). 

The staff also reviewed the applicable UFSAR supplement program descriptions and concluded

that the UFSAR supplement provides an adequate description of the AMPs credited for

managing aging in these components, as required by 10 CFR 54.21(d). 

3.7.5.3 Steam and Power Conversion Systems in Various Dry Environments

3.7.5.3.1 Main Steam System

Technical Staff Evaluation. The technical staff reviewed the AMR of the main steam system

(01) to determine whether the proposed aging management was adequate to address any

potential aging during the extended shutdown of Unit 1. The main steam system is described in

LRA Section 2.3.4.1. LRA Table 3.4.2.1 contains the AMR for the system for normal operation.

LRA Section 3.0.1 and the applicant's February 19, 2004, submittal states that portions of

Unit 1 main steam system are within the boundary of the BFN layup program. However, the

portions of this system within the scope of license renewal are those that lack moisture controls

and are considered moist air control components. The applicant's February 19, 2004, submittal

describes the applicant's process for evaluating the effects of aging during the extended

shutdown. The staff verified that the applicant identified all applicable AERMs during the

extended shutdown and credited appropriate AMPs for managing the AERMs. The staff also

reviewed the applicable UFSAR supplements for the AMPs to ensure that the program

descriptions adequately describe the AMPs.
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Aging Effects. Table 4 of the February 19, 2004, submittal provides the AMR of the main steam

system components within the scope of license renewal that were exposed to an air

environment that lacked moisture controls. The component types include bolting, fittings, piping,

restricting orifices, strainers, tubing, and valves.

The applicant's February 19, 2004, submittal identified air/gas (moist air) as the internal

environment of the system, whereas the external environment was inside air. 

For the Unit 1 main steam system components, the applicant identified the following materials,

environments, and AERMs, where, because of the uncontrolled moist air, aging effects different

from those requiring management during the period of extended operation were identified:

aluminum alloy components in air/gas (internal) moist air environments are subject to loss of

material due to crevice, galvanic, and pitting corrosion, as well as crack initiation/growth due to

SCC, carbon and low-alloy steel components in air/gas (internal) moist air environments are

subject to loss of material due to general, crevice, pitting, and galvanic corrosion; carbon

low-alloy steel components in inside air (external) environments are subject to loss of material

due to general corrosion; stainless steel components in air/gas (internal) moist air environments

are subject to loss of material due to crevice corrosion and pitting corrosion; no aging effects

are identified for aluminum alloy and stainless steel components in inside air (external)

environments. 

On the basis of its review of the information provided in the LRA, as supplemented by letter

dated February 19, 2004, the staff concurred with the applicant's evaluation of the aging effects

of the materials and environments associated with the main steam system during the extended

shutdown. The staff did not identify any omitted aging effects. Therefore, the staff found that

the applicant had identified the appropriate aging effects for the Unit 1 main steam system

during the extended shutdown.

Aging Management Programs. After evaluating the applicant's identification of aging effects, the

staff evaluated the AMPs to determine if they are appropriate for managing the identified aging

effects from the extended shutdown. The staff also verified that the UFSAR supplement

contains an adequate description of the program. 

Table 4 of the applicant's February 19, 2004, submittal identifies the following AMPs for

managing the aging effects described above for the main steam system.

 • ASME Section XI Subsections IWB, IWC, and IWD Inservice Inspection Program

(B.2.1.4)

 • Chemistry Control Program (B.2.1.5)

 • BWR Stress Corrosion Cracking Program (B.2.1.10)

 • Flow-Accelerated Corrosion Program (B.2.1.15)

 • One-Time Inspection Program (B.2.1.29)

 • Systems Monitoring Program (B.2.1.39)

SER Sections 3.0.3.1.3, 3.0.3.2.2, 3.0.3.2.5, 3.0.3.2.9, 3.0.3.1.7, and 3.0.3.3.1, respectively,

present the staff's detailed review of these AMPs.
3-432

During its review, the staff determined that additional information was needed to complete its

review. 

In Table 4 of the February 19, 2004, submittal, for the main steam system (01), the applicant

indicated that inspections will be performed prior to Unit 1 restart for the aluminum alloy

components for which additional aging effects (i.e., loss of material due to crevice, galvanic,

and pitting corrosion, and crack initiation/growth due to SCC) had been identified for the

extended outage. These additional aging effects are the results of the presence of moist air in

system locations where condensation could build up. The applicant indicated that inspections

will be performed for the components prior to Unit 1 restart. However, no descriptions of the

inspections were provided. In RAI 3.0-7 LP, the staff requested the applicant to discuss the

proposed inspections, including scope, method, procedure, parameters monitored and trended,

detection of aging effects, and acceptance criteria, in order to justify the adequacy of the

inspections. By letter dated October 8, 2004, the applicant stated that internal surface

monitoring is performed in accordance with the One-Time Inspection Program described in the

LRA Section B.2.1.29. The applicant noted that this is the same AMP proposed for managing

internal aging effects of components exposed to moist air during the period of extended

operation. By letter dated January 31, 2005, in response to RAI 3.0-10 LP, the applicant stated

that the inspections described in the October 8, 2004, letter would have been better

characterized as restart inspections instead of one-time inspections. Thus, the reference to the

One-Time Inspection Program performed prior to restart in the October 8, 2004, letter is

considered to be a restart inspection. The staff found the applicant's commitment to perform

restart inspections prior to Unit 1 restart to be acceptable, and RAI 3.0-7 LP is closed for the

main steam system. The staff's discussion of the general adequacy of restart inspections

managing the identified aging effects versus periodic inspections during the period of extended

outage is provided in SER Section 3.7.1.

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004, January 31, May 18 and 27, 2005, the staff found the

applicant identified appropriate AMPs for managing the aging effects of the Unit 1 main steam

system components exposed to an environment that lacked moisture controls. In addition, the

staff found the program descriptions in the UFSAR supplement acceptable.

Conclusion. On the basis of its review, the staff concluded that the applicant had adequately

identified the aging effects, and the AMPs credited for managing the aging effects, for the

Unit 1 main steam system components during the extended shutdown, so 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 54.29(a). 

The staff also reviewed the applicable UFSAR supplement program descriptions and concluded

that the UFSAR supplement provides an adequate description of the AMPs credited for

managing aging in these components, as required by 10 CFR 54.21(d). 

3.7.5.3.2 Condensate and Demineralized Water System

Technical Staff Evaluation. The technical staff reviewed the AMR of the condensate and

demineralized water system (02) to determine whether the proposed aging management was

adequate to address any potential aging during the extended shutdown of Unit 1. The

condensate and demineralized water system is described in LRA Section 2.3.4.2. LRA
3-433

Table 3.4.2.2 contains the AMR for the system for normal operation. LRA Section 3.0.1 and the

applicant's February 19, 2004, submittal states that portions of Unit 1 condensate and

demineralized water system are within the boundary of the BFN layup program. However, the

portions of this system within the scope of license renewal lacked moisture controls and is,

therefore, considered moist air. The applicant's February 19, 2004, submittal describes the

applicant's process for evaluating the effects of aging during the extended shutdown. The staff

verified that the applicant identified all applicable AERMs during the extended shutdown and

credited appropriate AMPs for managing the AERMs. The staff also reviewed the applicable

UFSAR supplements for the AMPs to ensure that the program descriptions adequately describe

the AMPs.

Aging Effects. Table 4 of the February 19, 2004 submittal; provides the AMR of the condensate

and demineralized water system components within the scope of license renewal that were

exposed to an air environment that lacked moisture controls. The component types include

bolting, condenser, expansion joint, fittings, piping, pumps, restricting orifices, tanks, tubing,

and valves. In its submittal, the applicant. identified air/gas (moist air) as the internal

environment of the system, whereas the external environment was inside air and outside air.

For the Unit 1 condensate and demineralized water system components, the applicant identified

the following materials, environments, and AERMs: copper-alloy components in air/gas

(internal) moist air environments are subject to loss of material due to selective leaching,

crevice corrosion, and pitting corrosion; aluminum alloy components in air/gas (internal) moist

air environments are subject to loss of material due to crevice, galvanic, and pitting corrosion,

as well as crack initiation/growth due to SCC; carbon and low-alloy steel components in air/gas

(internal) moist air environments are subject to loss of material due to general, crevice, and

pitting corrosion; carbon low-alloy steel; and cast iron and cast iron alloy components in inside

air (external) or outside air (external) environments are subject to loss of material due to

general corrosion; stainless steel components in air/gas (internal) moist air environments are

subject to loss of material due to crevice corrosion and pitting corrosion; cast iron and cast iron

alloys in air/gas (internal) moist air environments are subject to loss of material due to galvanic,

general, crevice, and pitting corrosion, as well as selective leaching; no aging effects are

identified for Copper-alloy components in inside air (external) environments; no aging effects

are identified for aluminum alloy, and stainless steel components in an inside air. (external) or

outside air (external) environment; no aging effects are identified for polymer materials in an

air/gas (internal) moist air or inside air (external) environment. 

During its review, the staff determined that additional information was needed to complete its

review. 

In Table 4 of its February 19, 2004, submittal, the applicant identified galvanic corrosion for the

cast iron and cast iron alloys in air/gas (internal) environments during the Unit 1 layup period,

but not for the plant operating condition. In RAI 3.4-5 LP, the staff requested the applicant to

explain the discrepancy. By letter dated October 8, 2004, the applicant stated that the cast iron

valves and fittings within the scope of license renewal for both normal operation and Unit 1

layup are coupled with either carbon steel or aluminum. Due to cast iron being either equal to or

greater than carbon steel or aluminum in galvanic series, galvanic corrosion is not a concern for

the cast iron components within the scope of license renewal for the condensate and

demineralized water system. The staff found the applicant's explanation to be acceptable, and

RAI 3.4-5 LP is closed. 
3-434

In RAI 3.4-6 LP, the staff requested the applicant to explain why galvanic corrosion was not

identified as a potential aging mechanism for the copper-alloy components in the condensate

and demineralized water system that are exposed to air/gas (internal) moist air environments.

By letter dated October 8, 2004, the applicant stated that the copper-alloy fittings and valves

within the scope of license renewal for the condensate and demineralized water system are not

in contact with a more cathodic material such as stainless steel or nickel-based alloys.

Therefore, galvanic corrosion is not a concern for the components of the condensate and

demineralized water system during the period of extended operation. The staff found the

applicant's explanation to be acceptable, and RAI 3.4-6 LP is closed.

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004, the staff concurred with the applicant's evaluation of

the aging effects of the materials and environments associated with the condensate and

demineralized water system during the extended shutdown. The staff did not identify any

omitted aging effects. Therefore, the staff found that the applicant had identified the appropriate

aging effects for the Unit 1 condensate and demineralized water system during the extended

shutdown.

Aging Management Programs. After evaluating the applicant's identification of aging effects, the

staff evaluated the AMPs to determine if they are appropriate for managing the identified aging

effects from the extended shutdown. The staff also verified that the UFSAR supplement

contains an adequate description of the program. 

Table 4 of the applicant's February 19, 2004, submittal identifies the following AMPs for

managing the aging effects described above for the condensate system and demineralized

water system.

 • Chemistry Control Program (B.2.1.5)

 • Aboveground Carbon Steel Tanks Program (B.2.1.26)

 • One-Time Inspection Program (B.2.1.29)

 • Selective Leaching of Materials Program (B.2.1.30)

 • Systems Monitoring Program (B.2.1.39)

SER Sections 3.0.3.2.2, 3.0.3.1.6, 3.0.3.1.7, 3.0.3.1.8, and 3.0.3.3.1, respectively, present the

staff's detailed review of these AMPs.

During its review, the staff determined that additional information was needed to complete its

review. 

In Table 4 of the February 19, 2004, submittal, for the condensate and demineralized water

system (02), no AMPs other than those identified above for the period of extended operation

are noted for the extended outage. In RAI 3.4-5 LP, the staff requested the applicant to justify

the basis for not performing inspections of the affected system components prior to Unit 1

restart. By letter dated October 8, 2004, the applicant stated that the one-time (restart)

inspections described in the LRA will be performed prior to Unit 1 restart to verify the material

condition. The staff found the applicant's commitment of performing these inspections prior to

Unit 1 restart to be acceptable, and considers RAI 3.4-5 LP closed for this system. The staff's

discussion of the general adequacy of the restart inspections managing the aging effects

versus periodic inspections for the system components is provided in SER Section 3.7.1.
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On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004, and January 31, May 18, and 27, 2005, the staff found

the applicant identified appropriate AMPs for managing the aging effects of the Unit 1

condensate and demineralized water system components exposed to an environment that

lacked moisture controls. In addition, the staff found the program descriptions in the UFSAR

supplement acceptable.

Conclusion. On the basis of its review, the staff concluded that the applicant had adequately

identified the aging effects, and the AMPs credited for managing the aging effects, for the

Unit 1 condensate and demineralized water system components during the extended shutdown,

so 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 54.29(a). 

The staff also reviewed the applicable UFSAR supplement program descriptions and concluded

that the UFSAR supplement provides an adequate description of the AMPs credited for

managing aging in these components, as required by 10 CFR 54.21(d). 

3.7.5.3.3 Heater Drains and Vents System

Technical Staff Evaluation. The technical staff reviewed the AMR of the heater drains and vents

system (06) to determine whether the proposed aging management was adequate to address

any potential aging during the extended shutdown of Unit 1. The heater drains and vents

system is described in LRA Section 2.3.4.4. LRA Table 3.4.2.4 contains the AMR for the system

for normal operation. LRA Section 3.0.1 and the applicant's February 19, 2004, submittal state

that portions of Unit 1 heater drains and vents system are within the boundary of the BFN layup

program. However, the portions of this system within the scope of license renewal lack moisture

controls and are considered moist air control components. The applicant's February 19, 2004,

submittal describes the applicant's process for evaluating the effects of aging during the

extended shutdown. The staff verified that the applicant had identified all applicable AERMs

during the extended shutdown and credited appropriate AMPs for managing the AERMs. The

staff also reviewed the applicable UFSAR supplements for the AMPs to ensure that the

program descriptions adequately describe the AMPs.

Aging Effects. Table 4 of the February 19, 2004, submittal provides the AMR of the heater

drains and vents system components within the scope of license renewal that were exposed to

an air environment that lacked moisture controls. The component types include bolting, fittings,

piping, traps, and valves.

The applicant's February 19, 2004, submittal identified air/gas (moist air) as the internal

environment of the system, whereas the external environment was inside air. 

For the Unit 1 heater drains and vents system components, the applicant identified the following

materials, environments, and AERMs: carbon and low-alloy steel components in air/gas

(internal) moist air environments are subject to loss of material due to general, crevice, pitting,

and galvanic corrosion; carbon low-alloy steel components in inside air (external) environments

are subject to loss of material due to general corrosion.

On the basis of its review of the information provided in the LRA, as supplemented by letter

dated February 19, 2004, the staff concurred with the applicant's evaluation of the aging effects
3-436

of the materials and environments associated with the heater drains and vents system during

the extended shutdown. The staff did not identify any omitted aging effects. Therefore, the staff

found that the applicant had identified the appropriate aging effects for the Unit 1 heater drains

and vents system during the extended shutdown.

Aging Management Programs. After evaluating the applicant's identification of aging effects, the

staff evaluated the AMPs to determine if they are appropriate for managing the identified aging

effects from the extended shutdown. The staff also verified that the UFSAR supplement

contains an adequate description of the program. 

Table 4 of the applicant's February 19, 2004, submittal identifies the following AMPs for

managing the aging effects described above for the heater drains and vents system.

 • Chemistry Control Program (B.2.1.5)

 • Flow-Accelerated Corrosion Program (B.2.1.15)

 • One-Time Inspection Program (B.2.1.29)

SER Sections 3.0.3.2.2, 3.0.3.2.9, and 3.0.3.1.7, respectively, present the staff's detailed

review of these AMPs. During its review, the staff determined that additional information was

needed to complete its review. 

In Table 4 of the February 19, 2004, submittal, for the heater drains and vents system (06), the

applicant indicated that carbon and low-alloy steel components in inside air (external)

environments are subject to loss of material due to general corrosion, because the components'

surface temperature is less than 212 °F during the period of extended outage. The applicant

indicated that the components will be inspected for external corrosion prior to Unit 1 restart, but

provided no details for the inspection. In RAI 3.0-7 LP, the staff requested the applicant to

discuss the proposed inspections, including scope, method, procedure, parameters monitored

and trended, detection of aging effects, and acceptance criteria, in order to justify the adequacy

of the inspections. By letter dated October 8, 2004, the applicant stated that external surface

monitoring the affected carbon and low-alloy steel components in accordance with the Systems

Monitoring Program described in the LRA, Appendix B, Section B.2.1.39 is performed. The

applicant noted that this is the same AMP proposed for managing external loss of material is

performed during the period of extended operation. The staff determined the Systems

Monitoring Program to be adequate in managing the external aging effects. RAI 3.0-7 LP is,

therefore, closed for the heater drains and vents system (06). 

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19 and October 8, 2004, the staff found the applicant had identified appropriate

AMPs for managing the aging effects of the Unit 1 heater drains and vents system components

exposed to an environment that lacked moisture controls. In addition, the staff found the

program descriptions in the UFSAR supplement acceptable.

Conclusion. On the basis of its review, the staff concluded that the applicant had adequately

identified the aging effects and the AMPs credited for managing the aging effects for the Unit 1

heater drains and vents system components during the extended shutdown, so 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 54.29(a). 
3-437

The staff also reviewed the applicable UFSAR supplement program descriptions and concluded

that the UFSAR supplement provides an adequate description of the AMPs credited for

managing aging in these components, as required by 10 CFR 54.21(d). 

3.7.6 Containments, Structures, and Component Supports

3.7.6.1 Summary of Technical Information in the Application

In LRA Section 3.5, the applicant addressed the aging management of containments, structures

and component supports. LRA Section 3.0.1 contains a summary of the Evaluation of the Unit 1

Layup and Preservation Program. By letter dated February 19, 2004, the applicant submitted

additional information, entitled, Submittal of Evaluation of the BFN Unit Layup and Preservation

Program, was reviewed by the staff. The staff determined that it needed additional information

to complete its review. 

3.7.6.2 Technical Staff Evaluation

The technical staff reviewed the applicant's AMR results for BFN containments, structures and

component supports and reported its evaluation findings in SER Section 3.5. The staff also

reviewed the containment and structural aspects of the applicant's evaluation of the BFN Unit 1

Layup and Preservation Program, and determined that additional information was needed to

complete its review.

The staff determined that the BFN document titled, "Evaluation of the BFN Unit 1 LayUp and

Preservation Program," including Tables 1 through 4, did not provide information related to

BFN's evaluation of the Unit 1 spent fuel storage system layup effects. RAI 3.5-1 (related to

Unit 1 layup issue) requested, by letter dated June 23, 2004, that the applicant describe the

method adopted in assessing the Unit 1 spent fuel storage system related layup effects. The

applicant was also asked to provide a discussion of the applicable spent fuel pool environments

(any delta change in pool water chemistry, ambient humidity, and temperature, etc.), results of

past periodic inspections of the spent fuel pool structural components and pool liners, any

observed pool leakages or degraded conditions, and corrective actions taken to support BFN's

conclusion that no layup effect is applicable to the Unit 1 spent fuel storage system.

By letter dated July 19, 2004, the applicant responded that: 

The Unit 1 spent fuel storage system was never placed in layup. The Unit 1 spent fuel

storage system contains spent fuel and remained in service since Unit 1 was shut down

and defueled in 1985. The Unit 1 spent fuel storage pool is located on elevation 664.0'

of the Unit 1 reactor building. This area where the spent fuel pools are located is

referred to as the refuel floor and is common for all three units (i.e., there are no

physical barriers separating the spent fuel pools from the other units). Therefore the

spent fuel pools are exposed to the same operating environments. The spent fuel

storage pool chemistry is maintained in accordance with Technical Requirement Manual

section TR 3.9.3 Spent Fuel Pool Water Chemistry. 

The spent fuel pool storage system is in service and complies with all applicable license

and regulatory requirements. The structural components of the Unit 1 spent fuel storage
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system are being monitored under the Maintenance Rule (Structures Monitoring

Program) requirements, which are the same requirements as those for inspection of the

Unit 2 and 3 spent fuel storage system. Plant procedure 0-TI-346 implements the

requirements of the Maintenance Rule and contains the same performance criteria for

all 3 units. The Maintenance Rule inspection results for Unit 1 spent fuel storage pool

are consistent with the Maintenance Rule inspection results for Unit 2 and 3 spent fuel

storage pools. The structural components of the Unit 1 spent fuel pool and the

supporting equipment of the spent fuel pool storage system are all exposed to an

environment that is consistent with the operating environments of the Units 2 and 3

spent fuel storage system. Any degraded condition discovered during system operation

or as part of the Maintenance Rule inspection of the Unit 1 spent fuel storage system is

handled the same as for the Units 2 and 3 spent fuel storage systems. The BFN

Corrective Action Program to address degraded conditions is SPP-3.1. The structural

components of BFN spent fuel storage system are addressed in LRA Section 2.4.2.1. 

The operating environment for the Unit 1 spent fuel storage system is consistent with

the operating environments of the Units 2 and 3 spent fuel storage systems and the

system has been maintained consistent with license and regulatory requirements and

the plant corrective program. Therefore, there is no difference between the Unit 1 spent

fuel storage system and those of Units 2 and 3. Since the system was not in layup, as

described above, no layup effects are applicable to the Unit 1 system. This is the basis

for not including the spent fuel storage system to the BFN document "Evaluation of the

BFN Unit 1 Layup and Preservation Program.”

The staff found the applicant’s response, which is based on plant-specific structural

configuration and operational experience, adequate and reasonable to support its assertion that

no layup effects are applicable to the Unit 1 spent fuel storage system. Therefore, the RAI is

considered closed.

In RAI 3.5-2 the staff requested the applicant to describe the approach used in evaluating the

Unit 1 structures and component supports related layup effects. The staff also requested the

applicant to provide a discussion of the environments applicable to Unit 1 structures and

component supports (e.g., any exposure to aggressive chemicals or ponding of water,

significant change in ambient humidity and temperature, etc.), results of past periodic

inspections of the structures and component supports, any observed degraded conditions, and

corrective actions taken to support BFN's conclusion that no layup effect is applicable to Unit 1

structures and component supports that require an AMR.

In its letter dated July 19, 2004, the applicant responded that:

For Unit 1 structures and component supports, the external service environments

defined in Table 3.0.2 of the LRA were used in the aging management review. An

example of an environment is the "Inside Air" environment that is defined in Table 3.0.2

as "Atmospheric air, maximum average temperature 150 °F, humidity up to 100 percent,

potentially exposed to ionizing radiation, not exposed to weather." The range of interior

temperatures, pressures, relative humidity, and radiation dose for the reactor building

and primary containment are defined in calculations ND-Q1999-900031 (RIMS W78

030430 005), "Summary of Operational Environmental Conditions for Browns Ferry

Nuclear Plant," ND-Q2999-880143 (RIMS R14 020723 105), "Summary of Harsh
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Environmental Conditions for Browns Ferry Unit 2" and NDQ3999- 910035 (RIMS R14

020723 104), "Summary of Harsh Environmental Conditions for Browns Ferry Unit 3."

The interior temperatures, pressures, relative humidity, and radiation dose are shown on

the Harsh Environmental Data Drawings 47E225 series for each unit. The environmental

conditions defined in the referenced calculations are enveloped by the definition for

"Inside Air" contained in Table 3.0.2, except for the area of the main steam tunnel

located on elevation 565.0' of the Units 2 and 3 reactor buildings. The main steam

tunnels during plant operation have an average area temperature of 160°F. This

temperature occurs as a result of plant operation and has not been seen in the same

area of the Unit 1 reactor building during plant lay-up. The Unit 1 lay-up environment is

the same or bounded by the evaluated operating environments.

The Unit 1 reactor building structure is subject to the Maintenance Rule SMP

requirements. A baseline inspection for the BFN SMP was performed in 1997. All the

same attribute inspections that were performed for Units 2 and 3 were performed for

Unit 1. This inspection is documented in calculation CDQ-0303-970086 (RIMS R14

971105 102). LCEI-CI-C9, "Procedure for Walkdown of Structures for Maintenance

Rule," was the procedure utilized to perform SMP inspections and requires the

documentation of defects in accordance with the requirements of the procedure. There

were two defects noted from the inspection of the Unit 1 reactor building, and these two

defects were noted as: (1) a personnel lock door that appeared to not be airtight and

(2) rust was noted on some of the torus reinforcement steel between bays 12-13, 13-14,

and 14-15. These defects were dispositioned as not affecting structural function. The

SMP requires a reinspection on a five-year frequency. The 2002 SMP inspection is

documented in calculation CDQ-0303-2003-0260 (RIMS R14 030211 102). During the

2002 SMP inspections, there were four defects noted from the inspection of the Unit 1

reactor building and which were dispositioned as not affecting structural function. These

four defects were noted as: (1) a concrete pad at the floor around conduit was chipped,

(2) bolt missing from angle securing the structural plate partition wall to the concrete

floor, (3) in the southwest comer of a stairwell, mortar was missing at one end of the

masonry block, and (4) some concrete deterioration was noted in bay 7 of the torus area

(work in progress to repair the area was noted from walkdown). These defects noted

from the two inspection periods can be categorized as isolated conditions and do not

represent an adverse trend that will affect the functionally of structural components.

The component supports located in Unit 1, except for those that are required for Unit 2

or Unit 3 system operation, are not subject to periodic inspections during the shutdown

period. All component supports for safety-related systems required for Unit 1 operation

are to be inspected and existing configurations confirmed as part of the Unit 1 recovery

effort. The following plant procedures (walkdown instructions [WI]), are utilized:

WI-BFN-0-CEB-01 was used for piping and supports, WI-BFN-0-CEB-02 was used for

structural items, and WI-BFN-0-GEN-01 was used for both piping/supports and

structural steel as a general walkdown procedure. Additionally, the following procedures

were used to document baseline configurations for other component supports:

WI-BFN-0-CEB-03 - Small Bore Piping

WI-BFN-0-CEB-04 - Seismic Verification of A46 and IPEEE

WI-BFN-0-CEB-05 - Pipe Rupture/HELB

WI-BFN-0-CEB-06 - Seismically Induced Water Spray
3-440

The inspections would document as-built configurations or existing plant configurations

that did not conform to the acceptance criteria defined in the WI. These configurations

would be evaluated to design criteria requirements. If the evaluations determined that

the configuration did not meet the design criteria requirement, a plant modification would

be designed and issued under the plant work control process.

An electronic search of the site Corrective Action Program for PERs was performed to

identify any adverse conditions with component supports. The search did not result in

the identification of any adverse conditions.

The environment for the Unit 1 structures and component supports is consistent with the

operating environments of the Units 2 and 3 structures and component supports;

therefore, there is no difference in the Unit 1 structures and component supports from

Units 2 and 3 and no lay-up affects are applicable to Unit 1. 

The staff found the above response very plant-specific and reasonably detailed to justify the

applicant's assertion that the environment of the Unit 1 structures and component supports is

consistent with the operating environments of the Units 2 and 3 structures and component

supports; therefore, no layup effects are applicable to Unit 1 structures and component

supports. RAI 3.5-2 (related to Unit 1 layup issue) is considered resolved.

In RAI 3.5-3, the staff pointed out that, when the plant is operating, the containment drywell,

torus, and connecting vent assemblies are subjected to a relatively inert environment, and all

the requirements related to their inspections, and leak-rate testing are applicable. These

requirements ensure the leak tight and structural integrity of these components. Also, industry

operating experience problems, as reflected in NRC's generic letters, information notices, and

other industry published event reports are considered applicable. These activities may or may

not have been considered for Unit 1 during its long layup. In this context, the applicant was

requested to provide information that would describe the benchmark condition of the

containment pressure boundary related components prior to Unit 1 restart, and actions that will

be taken prior to the extended period of operation. The relevant regulatory requirements are

10 CFR 50,55a, and Appendix J of 10 CFR 50. The relevant generic letters are GL 87-05, GL

89-16, and GL 98-05. The relevant information notices are IN 86-99, IN 88-82, IN 89-06, IN

89-79, and IN 92-20.

In its letter dated July 19, 2004, the applicant responded that: 

For the Unit 1 containment drywell and torus, the environment during the extended

outage was the same as or bounded by the evaluated operating unit environments. LRA

Table 3.0.2 describes the containment environment for the drywell and torus that was

used in the AMR as "Atmospheric air, maximum average temperature 150 °F, humidity

up to 100 percent, potentially exposed to ionizing radiation, not exposed to weather.”

The applicant pointed out that "Inerting was not credited for elimination of aging effects

requiring aging management, and that the Unit 1 containment environment associated

with temperature and ionizing radiation are not as severe as the evaluated (operating)

environment conditions.” The torus was subject to the torus water environment during

the shutdown period. The torus was subsequently drained and is being refurbished as

part of the Unit 1 recovery effort. 
3-441

On the subject of containment inspections and leak-rate testing, the applicant stated

that 100 percent of the examinations required in Examination Categories of

Table IWE-2500-1 for the First Inspection Interval will be completed as pre-service

exams before Unit 1 restarts except those that may be excluded by 10 CFR 50.55a and

where specific written relief has been granted by the staff. The requirements of ASME

Section XI In-Service Inspection Subsection IWE, 1992 Edition with the 1992 Addenda

will be implemented on Unit 1. Type A, B, and C leak rate testing required by 10 CFR 50

Appendix J will also be performed prior to Unit 1 restart.

In addition, the applicant addressed the relevant information notices and generic letters as

follows:

 • NRC GL 87-05: Request Additional Information Assessment - Degradation of Mark I

Drywells

The applicant provided the staff with the results of the ultrasonic testing for corrosion

degradation of the drywell liner plate, RIMs No. L44 880830 801, dated August 30, 1988. The

results of the ultrasonic testing state that each unit's drywell was ultrasonically tested near the

sand cushion area during 1987. The results from these tests showed that the nominal thickness

was maintained on each drywell. On Unit 1, no reading below the nominal thickness of one inch

was measured, indicating that the integrity of the drywell liner plate was maintained.

 • NRC GL 89-16: Installation of a Hardened Wet Well Vent. BFN will be installing the

hardened well vent as part of the Unit 1 recovery effort. This generic letter does not

address aging effects or aging management considerations.

 • NRC IN 86-99: Degradation of Steel Containments. See response to GL 87-05

 • NRC IN 88-82: Torus Shells with Corrosion and Degraded Coatings on BWR

Containments. In 1983, Engineering Change Notice (ECN) P0555 was issued to

completely inspect and recoat the torus as necessary. The Unit 1 work was completed

on this ECN. 

 • NRC IN 89-06: Bent Anchor Bolts in Boiling Water Reactor Torus Supports. Based on

the configuration of the BFN torus supports, it has been determined that BFN tie down

bolts would not be subject to the effects that occurred at plant Hatch. This information

notice does not address aging effects or aging management considerations.

 • NRC IN 92-20: Inadequate Local Leak Rate Testing. The vent line bellows at BFN are of

a different design (single-ply bellows) than the Quad Cities bellows identified in IN

92-20. The design of the BFN penetration bellows allows full pressure to be transmitted

to all portions of the bellows during Appendix J testing. 

In addition to the above information, the applicant addressed the staff's RAIs related to the

Unit 1 primary containment during the AMR of other two units. They are discussed in SER

Section 3.5. 

On the basis of its review of the information provided in the LRA, as supplemented by letters

dated February 19, 2004, and a teleconference held between the staff and the applicant on
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April 14, 2004, the staff found that the applicant identified appropriate AMPs for managing the

aging effects of the Unit 1 containment, structures, and component supports during the

extended shutdown. In addition, the staff found the program descriptions in the UFSAR

supplement acceptable.

3.7.6.3 Conclusion

On the basis of its review, the staff concluded that the applicant had adequately identified the

aging effects and the AMPs credited for managing the aging effects for the Unit 1 containment,

structures, and component supports during the extended shutdown, so that there is reasonable

assurance that the intended functions of these Unit 1 structural components will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR 54.29(a). 

The staff also reviewed the applicable UFSAR supplement program descriptions and concluded

that the UFSAR supplement provides an adequate description of the AMPs credited for

managing aging in these components, as required by 10 CFR 54.21(d).
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3.8 Conclusion for Aging Management

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 UFSAR supplement program summaries and concluded that the

UFSAR supplement adequately describes the AMPs credited for managing aging as required

by 10 CFR 54.21(d).

With regard to these matters, the staff 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 BFN CLB 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 discusses the identification of time-limited aging analysis (TLAAs). The applicant

discusses the TLAAs in license renewal application (LRA) Sections 4.2 through 4.7. Safety

evaluation report (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).

The TLAAs are certain plant-specific safety analyses that are based on an explicitly assumed

40-year plant life. Pursuant to 10 CFR 54.21(c)(1), the applicant for license renewal must

provide a list of TLAAs, as defined in 10 CFR 54.3.

In its letters dated June 9, 2005, and June 15, 2005, the applicant determined that LRA

Sections 4.7.2, 4.7.3, and 4.7.5 should not be considered TLAAs; therefore, they were deleted

from the application (See SER Sections 4.7.2, 4.7.3, 4.7.5).

In addition, pursuant to 10 CFR 54.21(c)(2), an applicant may 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 Browns Ferry Nuclear Plant

(BFN) 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). The CLB includes the updated final safety analysis report (UFSAR), engineering

calculations, technical reports, engineering work requests, licensing correspondence, and

applicable vendor reports. The applicant listed the following applicable TLAAs in LRA

Table 4.1.1, “List of Time-Limited Aging Analyses”:

 • neutron embrittlement of the reactor vessel and internals

 • metal fatigue

 • environmental qualification of electrical equipment

 • loss of prestress in concrete containment tendons

 • primary containment fatigue

 • reactor building crane load cycles

 • corrosion – flow reduction

 • dose to seal rings for the high-pressure coolant injection and reactor core isolation

cooling containment isolation check valves

 • radiation degradation of drywell expansion gap foam
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 • corrosion – minimum wall thickness

 • irradiation assisted stress corrosion cracking of reactor vessel internals

 • stress relaxation of core plate hold-down bolts

 • emergency equipment cooling water weld flaw evaluation

Pursuant to 10 CFR 54.21(c)(2), the applicant stated that it had not identified any exemptions

granted under 10 CFR 50.12 that were based on a time-limited aging analysis (TLAA), as

defined in 10 CFR 54.3.

4.1.2 Staff Evaluation

In LRA Section 4.1, the applicant identified the TLAAs applicable to BFN. The staff reviewed the

information to determine if the applicant had provided adequate information to meet the

requirements of 10 CFR 54.21(c)(1) and 10 CFR 54.21(c)(2).

As defined in 10 CFR 54.3, TLAAs are analyses that meet the following six criteria:

 1. Involve systems, structures, and components that are 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 (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); and

 6. Are contained or incorporated by reference in the CLB.

The applicant provided a list of common TLAAs from U.S., Nuclear Regulatory Commission

Regulatory Guide (NUREG)-1800, “Standard Review Plan for Review of License Renewal

Applications for Nuclear Power Plants,” (SRP-LR) dated July 2001. The applicant listed those

TLAAs that are applicable to BFN, in LRA Table 4.1.1, “List of Time-Limited Aging Analyses.”

As required by 10 CFR 54.21(c)(2), an applicant must provide a list of all the exemptions

granted under 10 CFR 50.12 that are based on a TLAA and evaluated and justified for

continuation through the period of extended operation. In its LRA, the applicant stated that each

active exemption was reviewed to determine whether the exemption was based on a TLAA. The

applicant did not identify any TLAA-based exemptions. On the basis of the information provided

by the applicant with regard to the process used to identify TLAA-based exemptions, as well as

the results of the applicant’s search, the staff concluded that the applicant identified no

TLAA-based exemptions that are justified for continuation through the period of extended

operation, in accordance with 10 CFR 54.21(c)(2).
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4.1.3 Conclusion

On the basis of its review, the staff concluded that the applicant provided an acceptable list of

TLAAs, as required by 10 CFR 54.21(c)(1). The staff also confirmed that no exemptions to

10 CFR 50.12 have been granted on the basis of a TLAA, as required by 10 CFR 54.21(c)(2).

4.2 Neutron Embrittlement of Reactor Vessel and Internals

During plant service, neutron irradiation reduces the fracture toughness of ferritic steel in the

reactor vessel (RV) beltline region of light-water nuclear power reactors. Areas of review to

ensure that the RV has adequate fracture toughness to prevent brittle failure during normal and

off-normal operating conditions are (1) upper-shelf energy (USE), (2) adjusted reference

temperature (ART), (3) a low-pressure coolant injection (LPCI) reflood thermal shock analysis,

(4) heatup and cooldown (pressure-temperature limits) curves, (5) Boiling Water Reactor

Vessel and Internals Project (BWRVIP)-05 analysis for elimination of circumferential weld

inspection, and (6) analysis of the axial welds. The adequacy of the analyses for these six

areas is reviewed for the period of extended operation. 

The ART is defined as the sum of the initial (unirradiated) reference temperature (initial RTNDT),

the mean value of the adjustment in reference temperature caused by irradiation (delta RTNDT),

and a margin term. The delta RTNDT is the product of a chemistry factor (CF) and a fluence

factor. The chemistry factor is dependent upon the amount of copper and nickel in the material

and may be determined from tables in Regulatory Guide (RG) 1.99, Revision 2, “Radiation

Embrittlement of Reactor Vessel Materials,” or from surveillance data. The fluence factor is

dependent upon the neutron fluence. The margin term is dependent upon whether the initial

RTNDT is a plant-specific or a generic value and whether the CF was determined using the

tables in RG 1.99, Revision 2, or surveillance data. The margin term is used to account for

uncertainties in the values of the initial RTNDT, the copper and nickel contents, the fluence, and

the calculation methods. Revision 2 of RG 1.99 describes the methodology to be used in

calculating the margin term. The mean RTNDT is the sum of the initial RTNDT and the delta RTNDT,

without the margin term. The delta RTNDT and ART calculations meet the criteria of

10 CFR 54.3(a); therefore, they are considered as TLAAs.

The ART values are used in the analysis for the adjusted reference temperature for the RV

material due to neutron embrittlement, the pressure-temperature limits analysis, and the reflood

thermal shock analysis. The mean RTNDT values are used in the analysis of the circumferential

weld examination relief and the axial weld failure probability. 

Appendix G of 10 CFR Part 50 provides the staff’s criteria for maintaining acceptable levels of

USE for the RV beltline materials of operating reactors throughout the licensed lives of the

facilities. The Rule requires RV beltline materials to have a minimum USE value of 75 ft-lb in

the unirradiated condition and to maintain a minimum USE value above 50 ft-lb throughout the

life of the facility, unless it can be demonstrated through analysis that lower values of USE

would provide acceptable margins of safety against fracture equivalent to those required by the

American Society of Mechanical Engineers (ASME) Code Section XI, Appendix G. The Rule

also mandates that the methods used to calculate USE values account for the effects of

neutron irradiation on the USE values for the materials and incorporate any relevant RV
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surveillance capsule data that are reported through implementation of a plant’s 10 CFR Part 50

Appendix H RV Material Surveillance Program.

RG 1.99, Revision 2, provides an expanded discussion regarding the calculation of Charpy USE

values and describes two methods for determining Charpy USE values for RV beltline

materials, depending on whether a given RV beltline material is represented in the plant’s

reactor vessel material surveillance 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 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

the percentage drop in Charpy USE is dependent upon the amount of copper in the material

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

(1/4t), the neutron fluence used in the Charpy USE analysis is the neutron fluence at the 1/4t

depth location.

The applicant described its evaluation of this TLAA in LRA Section 4.2, “Neutron Embrittlement

of the Reactor Vessel and Internals.” In order to demonstrate that neutron embrittlement does

not significantly impact boiling water reactor (BWR) RV and vessel internals integrity during the

license renewal term, the applicant included discussion of the following topics related to neutron

embrittlement in LRA Section 4.2:

 • reactor vessel materials upper-shelf energy reduction due to neutron embrittlement

(LRA Section 4.2.1)

 • adjusted reference temperature for reactor vessel materials due to neutron

embrittlement (LRA Section 4.2.2)

 • reflood thermal shock analysis of the reactor vessel (LRA Section 4.2.3)

 • reflood thermal shock analysis of the reactor vessel core shroud (LRA Section 4.2.4)

 • reactor vessel thermal limit analyses - operating pressure-temperature limits (LRA

Section 4.2.5)

 • reactor vessel circumferential weld examination relief (LRA Section 4.2.6)

 • reactor vessel axial weld failure probability (LRA Section 4.2.7)

 • irradiation assisted stress corrosion cracking (IASCC) of the recator vessel and its

internals (LRA Section 4.7.6)

 • stress relaxation of the core plate hold-down bolts (LRA Section 4.7.7)

4.2.1 Reactor Vessel Materials Upper Shelf Energy Reduction due to Neutron

Embrittlement

4.2.1.1 Summary of Technical Information in the Application

In LRA Section 4.2.1, the applicant provided USE values for the limiting beltline materials. USE

is the standard industry parameter used to indicate the maximum toughness of a material at

high temperature. Appendix G of 10 CFR Part 50 requires the predicted end of life (EOL)
2TVA by letter dated January 7, 2005, agreed to decouple the power uprate licensing

request from License Renewal Application. The safety review of this item will be further

evaluated as part of the EPU review. 

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Charpy impact test USE value for RV materials to be at least 50 ft-lb (absorbed energy), unless

an approved analysis supports a lower value. The applicant stated that the initial unirradiated

test data are not available for the BFN RVs to demonstrate a minimum 50 ft-lb USE by standard

methods. Therefore, EOL fracture energy was evaluated by using the equivalent margin

analysis (EMA) methodology described in General Electric (GE) NEDO-32205-A, “10 CFR 50

Appendix G Equivalent Margin Analysis for Low Upper-Shelf Energy in BWR-2 through BWR-6

Vessels,” which has been approved by the staff. According to the applicant, this analysis

confirmed that an adequate margin of safety against fracture, equivalent to 10 CFR 50,

Appendix G requirements, does exist. The EOL USE calculations satisfy the criteria of

10 CFR 54.3(a). As such, these calculations are a TLAA.

The RVs were originally licensed for 40 years with an assumed neutron exposure of less than

1019 n/cm2 (E > 1.0 MeV). The CLB calculations use calculated fluences that are lower than this

limiting value. The applicant stated that the design basis value of 1019 n/cm2 bounds calculated

fluences for the original 40-year license term for each unit. The tests performed on RV

materials provided limited Charpy impact data. It was not possible to develop original Charpy

impact test USE values using the methods of 10 CFR Part 50, Appendix H and ASTM E23,

“Methods for Notched Bar Impact Testing of Metallic Materials,” invoked by 10 CFR Part 50

Appendix G. Therefore, alternative methods approved by the staff in NEDO-32205-A were used

to demonstrate compliance with the 10 CFR Part 50, Appendix G USE requirement.

Fluences were calculated for the RVs for the extended 60-year [54 EFPY (Effective Full-Power

Year) for Unit 1; 52 EFPY for Units 2 and 3] licensed operating periods, using the methodology

of NEDC-32983P, “General Electric Methodology for Reactor Pressure Vessel Fast Neutron

Flux Evaluation,” which was approved by the staff in an SER dated September 14, 2001. The

applicant used bounding fluence calculation, for each unit which included an extended power

uprate2 (EPU). The applicant provided the results for one bounding calculation for each RV and

determined the peak surface fluence of 1.95 x 1018 n/cm2 and peak 1/4t fluence of 1.35 x 1018

n/cm2 for Unit 1 vessel, and peak surface fluence of 2.3 x 1018 n/cm2 and peak 1/4t fluence of

1.59 x 1018 n/cm2 for Units 2 and 3 vessels. Peak fluences were calculated at the vessel inner

surface (inner diameter), for purposes of evaluating USE. The value of neutron fluence was

also calculated for the 1/4t location into the vessel wall measured radially from the inside

diameter using Equation 3 from Paragraph 1.1 of RG 1.99, Revision 2. This 1/4t depth is

recommended in the ASME Section XI, Appendix G, subarticle G-2120 as the maximum

postulated defect depth. The applicant evaluated the EOL USE by an EMA using the 54 EFPY

calculated fluence for Unit 1 and the 52 EFPY calculated fluence for Units 2 and 3. As

documented in the staff’s SER, BWRVIP-74-A provided a generic EMA which demonstrated

that BWR/3-6 plates and BWR/2-6 welds showing that percentage of reductions in USE of

equal to or less than 23.5 percent and 39 percent, respectively, would meet the requirements of

10 CFR Part 50, Appendix G. The applicant provided results of the EMA for limiting welds and

plates on the three RVs, which are summarized in LRA Tables 4.2.1.1 through 4.2.1.6. The

applicant stated that the results are acceptable because the limiting USE percentage drop is

less than the BWRVIP-74-A percentage drop acceptance criterion in all cases.
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4.2.1.2 Staff Evaluation

Appendix G to 10 CFR Part 50, Section IV.A.1 requires, in part, that the reactor pressure vessel

(RPV) beltline materials have Charpy USE values in the transverse direction for base metal and

along the weld for weld material of no less than 50 ft-lb, unless it is demonstrated in a manner

approved by the Director, Office of Nuclear Reactor Regulation, that lower values of Charpy

USE will ensure margins of safety against fracture equivalent to those required by ASME Code

Section XI, Appendix G. 

By letter dated April 30, 1993, the Boiling Water Reactor Owners Group (BWROG) submitted

NEDO-32205-A to demonstrate that BWR RPVs could meet margins of safety against fracture

equivalent to those required by Appendix G of the ASME Code Section XI for Charpy USE

values less than 50 ft-lb. In a letter dated December 8, 1993, the staff concluded that the topical

report demonstrated that the evaluated materials have the margins of safety against fracture

equivalent to ASME Code Section XI, Appendix G in accordance with 10 CFR Part 50,

Appendix G. In that report, the BWROG derived through statistical analysis the unirradiated

USE values for materials that originally did not have documented unirradiated Charpy USE

values. Using these statistically-derived Charpy USE values, the BWROG predicted the USE

values through 40 years of operation in accordance with RG 1.99, Revision 2. According to this

RG, the decrease in USE is dependent upon the amount of copper in the material and the

neutron fluence predicted for the material. The BWROG analysis determined that the minimum

allowable Charpy USE value in the transverse direction for base metal and along the weld for

weld material was 35 ft-lb.

GE performed an update to the USE EMA, which is documented in Electric Power Research

Institute (EPRI) TR-113596, “BWR Vessel and Internals Project (VIP) BWR Reactor Pressure

Vessel Inspection and Flaw Evaluation Guidelines,” BWRVIP-74, September 1999. The staff

review and approval of EPRI TR-113596 was documented in a letter dated October 18, 2001,

from Mr. C.I. Grimes to Mr. C. Terry. The analysis in EPRI TR-113596 determined the reduction

in the unirradiated Charpy USE resulting from neutron irradiation using the methodology in

RG 1.99, Revision 2. Using this methodology and a correction factor of 65 percent for

conversion of the longitudinal properties to transverse properties, the lowest Charpy USE at

54 EFPY for all BWR/3-6 plates was projected to be 45 ft-lb. The correction factor for specimen

orientation in plates is based on NRC Branch Technical Position MTEB 5-2. The EMA

acceptance criteria specified in the staff approved report BWRVIP-74, “BWR Vessel and

Internals Project (BWRVIP), BWR Reactor Pressure Vessel Inspection and Flaw Evaluation

Guidelines,” are based on the percentage reduction in the unirradiated charpy USE values

resulting from neutron radiation using the methodology in RG 1.99, Revision 2. The acceptance

criteria that are specified in the BWRVIP-74 report indicate that the maximum allowable

percentage reduction in USE value is 23.5 percent for the plates, and 39 percent for welds

except for Linde 80 weld. Linde 80 welds are discussed later in this SER. 

The staff’s review of LRA Section 4.2.1 identified an area in which additional information was

necessary to complete the review of the reactor vessel materials USE reduction due to neutron

embrittlement evaluation. The applicant responded to the staff’s request for additional

information (RAI) as discussed below.
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In RAI 4.2.1-1, dated December 1, 2004, the staff requested that the applicant provide the initial

USE values, percentage reduction in USE values, percentage of copper, and 1/4t fluence at the

end of the period of extended operation (including power uprate conditions) for all the plates

and non-Linde 80 weld metals in the beltline region of the RVs. Since the analysis in the

BWRVIP-74 is a generic analysis, the applicant submitted plant-specific information in LRA

Tables 4.2.1.1 through 4.2.1.6 for BFN to demonstrate that the beltline plates and non-Linde 80

weld metals of the RVs meet the criteria in the BWRVIP-74 report at the end of the license

renewal period. In its response, by letter January 31, 2005, the applicant stated that the initial

USE values are not available for BFN; however, BFN has used the EMA method to

demonstrate that the BFN vessels will maintain adequate fracture toughness throughout the

period of extended operation. The LRA bounding value for EFPY is 54 EFPY for Unit 1 and 52

EFPY for Units 2 and 3. The values for all beltline materials for BFN are listed in Tables 4.2.1-1

through 4.2.1-3 of the applicant’s response. The staff has verified the copper contents given in

Tables 4.2.1-1 to 4.2.1-3 and concluded that applicant’s response for all the beltline materials

with the corresponding data in Reactor Vessel Integrity Data Base (RVID) is acceptable. 

The applicant stated that the percentage reduction in the USE value for the limiting beltline

plate base materials and non-Linde 80 beltline welds for all the units is less than the

aforementioned acceptance criteria specified in BWRVIP-74. The staff also verified the

reduction in the unirradiated USE values due to neutron radiation for the beltline base metals

and non-Linde 80 beltline welds for all the units using the methodology in RG 1.99, Revision 2,

and found that all the beltline materials meet the acceptance criteria specified in the staffapproved report BWRVIP-74, and 10 CFR Part 50, Appendix G. Therefore, the staff’s concern

described in RAI 4.2.1-1 is resolved.

The BWRVIP-74 establishes criteria for Linde 80 welds and other types of welds and base

metals in the BWR RPVs. The criteria for Linde 80 welds require that the fracture toughness of

the Linde 80 weld shall be established by using J-R curve based on copper and neutron fluence

values. By letter dated November 21, 2005, the applicant revised LRA Table 4.2.1.1 to indicate

that the limiting beltline circumferential weld for the BFN Unit 1 was made with Linde 80 flux.

The applicant in its letter dated November 21, 2005, also provided the fracture toughness data

(J-R curve based on the limiting copper and the neutron fluence at the end of the period of

extended operation, which includes power uprate) and the Japplied values for the Linde 80 weld,

and concluded that the subject weld will maintain adequate fracture toughness during the

extended period of operation. The staff verified the applicant’s data and concluded that the BFN

Unit 1 limiting circumferential Linde 80 weld would meet the acceptance criteria specified in the

staff-approved BWRVIP-74 report and 10 CFR Part 50, Appendix G for the period of extended

operation. 

4.2.1.3 UFSAR Supplement

As required by 10 CFR 54.21(d), applicants for license renewal must include a UFSAR

supplement summary description of the “programs and activities for managing the effects of

aging and the evaluation of TLAA for the period of extended operation.” The applicant provided

UFSAR supplement summary description of RV materials USE reduction due to neutron

embrittlement in LRA Section A.3.1.1. On the basis of its review and the RAI response above,

the staff concluded that the UFSAR supplement summary adequately describes the TLAA on

RV materials USE reduction due to neutron embrittlement and is, therefore, acceptable.
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4.2.1.4 Conclusion

The staff reviewed the applicant’s RAI response and TLAA on USE, as summarized in LRA

Section 4.2.1, and determined that the RV beltline materials at BFN will continue to comply with

the staff’s USE requirements of 10 CFR Part 50, Appendix G throughout the periods of

extended operation for the BFN units. The staff therefore concluded that the applicant’s TLAA

for USE is in compliance with the requirements of 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 periods of extended operation as required by 10 CFR 54.21(c)(1). The staff also concluded

that the UFSAR supplement contains an appropriate summary description of the TLAA on USE

for the period of extended operation, as required by 10 CFR 54.21(d).

4.2.2 Adjusted Reference Temperature for Reactor Vessel Materials due to Neutron

Embrittlement

4.2.2.1 Summary of Technical Information in the Application

In LRA Section 4.2.2, the applicant summarized the ART determination for the RV materials

due to neutron embrittlement. The ART is defined as the sum of the initial (unirradiated)

reference temperature (initial RTNDT), the mean value of the adjustment in reference

temperature caused by irradiation (delta RTNDT), and a margin (M) term. The margin term is

defined in RG 1.99, Revision 2. As addressed in RG 1.99, Revision 2, delta RTNDT is a function

of neutron fluence. Since neutron fluence changes with time, the determination of delta RTNDT

(and, therefore, ART) meets the criteria of 10 CFR 54.3(a) for being a TLAA. 

As described in UFSAR Section 4.2, the RVs were licensed for 40 years with an assumed

neutron exposure of less than 1019 n/cm2 (E > 1.0 MeV). The applicant stated that the CLB

calculations use calculated fluences that are lower than this limiting value. The design basis

value of 1019 n/cm2 bounds calculated fluences for the original 40-year license term for all three

units. The ART values were determined using the embrittlement correlations defined in

RG 1.99, Revision 2.

The applicant calculated fluences for the RVs for the extended 60-year (54 EFPY for Unit 1;

52 EFPY for Units 2 and 3) licensed operating periods using the methodology of

NEDC-32983P, “General Electric Methodology for Reactor Pressure Vessel Fast Neutron Flux

Evaluation,” which was approved by the staff in an SER dated September 14, 2001. One

bounding calculation was performed for each reactor vessel. Peak fluences, which included

consideration of EPU conditions, were calculated at the vessel inner surface (inner diameter)

for purposes of evaluating USE and ART. The neutron fluence values were also calculated for

the 1/4t location into the vessel wall measured radially from the inside diameter using equation

3 from Paragraph 1.1 of RG 1.99, Revision 2. This 1/4t depth is recommended in the ASME

Code Section XI, Appendix G, Subarticle G-2120 as the maximum postulated defect depth. The

applicant calculated ART values for beltline materials 54 EFPY (Unit 1) and 52 EFPY (Units 2

and 3) based on the embrittlement correlation found in RG 1.99, Revision 2. The peak fluence,

and ART values for the 60-year (54 EFPY (Unit 1) and 52 EFPY (Units 2 and 3) license

operating period are presented in LRA Table 4.2.2-1. The applicant claimed that the limiting

ARTs allow P-T limits that will provide reasonable operational flexibility.
1TVA by letter dated January 7, 2005, agreed to decouple the power uprate licensing

request from License Renewal Application. The safety review of this item will be further

evaluated as part of the EPU review. 

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4.2.2.2 Staff Evaluation

The applicant calculated the 54 EFPY (Unit 1) and 52 EFPY (Units 2 and 3) fluences for the

RVs using the methodology of NEDC-32983P. Since this methodology is approved by the NRC,

the calculated fluences provided in the LRA are acceptable. The applicant provided the results

for one bounding calculation for each RV and determined the peak surface fluence of 1.95 x

1018 n/cm2 and peak 1/4t fluence of 1.35 x 1018 n/cm2 for, the Unit 1 vessel, and peak surface

fluence of 2.3 x 1018 n/cm2 and peak 1/4t fluence of 1.59 x 1018 n/cm2 for, the Units 2 and 3

vessels. LRA Table 4.2.2.1 shows bounding fluence values for BFN for 54, 52 and 52 EFPYs of

the operation, respectively.

The staff’s review of LRA Section 4.2.2 identified areas in which additional information was

necessary to complete the review of the ART values for RPV materials due to neutron

embrittlement evaluation. The applicant responded to the staff’s RAI as discussed below. 

In RAIs 4.2.2(A), and 4.2.2(B), dated December 1, 2004, the staff requested that the applicant

provide an explanation addressing the following issues:

 a. The staff requested that the applicant explain why Unit 1 was assumed to achieve 54

EFPYs of operation in a 60-year span given its operating history. Additionally, the staff

requested that the applicant provide an explanation for having a peak surface fluence

value of 1.95 x 1018 n/cm2 (E > 1.0 MeV) for Unit 1, while Units 2 and 3 achieve 2.3 x

1018 n/cm2 (E > 1.0 MeV) at the end of 60 years.

After reviewing the applicant’s response, dated January 31, 2005, the staff determined

that the applicant performed fluence calculations for Unit 1 assuming 54 EFPY of

operation and for Units 2 and 3 assuming 52 EFPY of operation. Based on the peak

surface and 1/4t fluence values, the applicant calculated USE and ART values for the

limiting beltline material for each unit. The applicant stated that the reason the reported

peak fluence for Unit 1 is lower than the fluence values for Units 2 and 3 is that the

maximum delta RTNDT and ART occurs in the circumferential weld material for Unit 1,

which is located away from the peak vessel fluence location, whereas for both Units 2

and 3 maximum delta RTNDT and ART occurs in the axial weld materials which

corresponds to the peak fluence. Therefore, the reported peak fluence for Unit 1 has an

applied axial correction factor of 0.81 and Units 2 and 3 do not have the axial correction

factor. The applicant also indicated that 54 EFPY was selected for BFN units as a

bounding value as part of the EPU1 evaluation. For consistency with the EPU evaluation,

the 54 EFPY value was incorporated into the LRA. The ART values are listed in

Tables 4.2.2-1 through 4.2.2-6 of the applicant’s response.

The staff reviewed the applicant’s response and found the explanation for using the

fluence values cited for Units 1, 2, and 3 acceptable because it accounts for differences

in weld location and neutron flux for each unit. The staff found that this approach is

acceptable as it identifies the maximum ART values for all three units. Therefore, the

staff’s concern described in RAI 4.2.2 (A) is resolved.
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 b. The staff requested that the applicant provide the initial RTNDT and ART values at 1/4t

and vessel ID surface at the end of the period of the extended operation for all the

materials in the beltline region of the BFN RVs.

The applicant provided information on the above items in Tables 4.2.2-1 to 4.2.2-6 of its

response dated January 31, 2005. The staff verified the percentages of copper and

nickel and the initial RTNDT given in the applicant’s response for all the beltline materials

with the corresponding data in RVID and found them acceptable. The staff also verified

the accuracy of the ART values for all the beltline materials using the methodology in

RG 1.99, Revision 2 and found them acceptable. Therefore, the staff’s concern

described in RAI 4.2.2 (B) is resolved.

4.2.2.3 UFSAR Supplement

As required by 10 CFR 54.21(d), applicants for license renewal must include a UFSAR

supplement summary description of the “programs and activities for managing the effects of

aging and the evaluation of TLAA for the period of extended operation.” The applicant provided

UFSAR supplement summary description of ART for RV materials due to neutron embrittlement

in LRA Section A.3.1.2. On the basis of its review, the staff concluded that the UFSAR

supplement summary adequately describes the TLAA on ART for RV materials due to neutron

embrittlement and is, therefore, acceptable.

4.2.2.4 Conclusion

The staff reviewed the applicant’s TLAA on the calculation of ART values, as summarized in

LRA Section 4.2.2 and the RAI response dated January 31, 2005, and determined that the

applicant’s calculation of the ART values for the RV beltline materials, as projected through the

periods of extended operation for BFN, Units 1, 2, and 3, is in conformance with the

recommended guidelines of RG 1.99, Revision 2. The staff therefore concluded that the

applicant’s TLAA for calculation of the ART values meet the requirements of

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 periods of extended operation as required

by 10 CFR 54.21(c)(1). The staff also concluded that the UFSAR supplement contains an

appropriate summary description of the TLAA on ART calculations for the period of extended

operation, as required by 10 CFR 54.21(d).

4.2.3 Reflood Thermal Shock Analysis of the Reactor Vessel

4.2.3.1 Summary of Technical Information in the Application

The applicant stated that UFSAR Section 3.3.5 includes an EOL thermal shock analysis

performed on the RVs for a design basis loss of coolant accident (LOCA) followed by a LPCI

system initiation. The effects of embrittlement assumed in this thermal shock analysis will

change with an increase in the licensed operating period. The applicant stated that this analysis

satisfies the criteria of 10 CFR 54.3(a). As such, this analysis is a TLAA.

For the current operating period, a thermal shock analysis was originally performed on the RV

components. The analysis assumed a design basis LOCA followed by LPCI system initiation

and accounted for the full effects of neutron embrittlement at the end of the current license term
4-11

of 40 years. The current analysis assumes EOL material toughness, which in turn depends on

EOL ART values. The critical location for fracture mechanics analysis is at one quarter of the

vessel thickness (from the inside, 1/4t). For this event, the peak stress intensity occurs

approximately 300 seconds after the LOCA. The applicant stated that the analysis shows that

300 seconds into the thermal shock event, the temperature of the vessel wall at 1.5 inches

deep (which is 1/4t) is approximately 400 °F. The ART values, described in LRA Section 4.2.2

and tabulated in Table 4.2.2.1, list the ART values for the limiting weld metal of the RVs. The

highest calculated RV beltline material ART value is 167.7 °F (Unit 1). Using the equation for KIC

presented in ASME Section XI Appendix A and the maximum ART value, the material reaches

upper shelf (a KIC value of 200 ksi %in) at 272 °F, which is well below the 400 °F, 1/4t

temperature predicted for the thermal shock event at the time of peak stress intensity.

Therefore, the applicant claimed that the projected analysis is valid for the period of extended

operation.

4.2.3.2 Staff Evaluation

The analysis assumes EOL material toughness, which in turn depends on EOL ART. The

critical location for fracture mechanics analysis is at the 1/4t location. For the reflood thermal

shock analysis of the RV, the peak stress intensity occurs at approximately 300 seconds after

the LOCA. At that time, the temperature at 1/4t is approximately 400 °F, which is much higher

than the 54 EFPY ART value167.7 °F for the limiting material of all the three BFN vessels.

Therefore, the staff concurred with the applicant that the revised thermal shock analysis of the

BFN vessels is valid for the period of extended operation because the ART for the limiting

beltline plate material is 167.7 °F for Unit 1, which is below the 400 °F at 1/4t temperature

predicted for the thermal shock event at the time of peak stress intensity. The reflood thermal

shock analysis is, therefore, bounding and valid for the period of extended operation. 

4.2.3.3 UFSAR Supplement

As required by 10 CFR 54.21(d), applicants for license renewal must include a UFSAR

supplement summary description of the “programs and activities for managing the effects of

aging and the evaluation of TLAA for the period of extended operation.” The applicant provided

UFSAR supplement summary description of reflood thermal shock analysis of the RV in LRA

Section A.3.1.3. On the basis of its review, the staff concluded that the UFSAR supplement

summary adequately describes the TLAA on reflood thermal shock analysis of the RV and is,

therefore, acceptable.

4.2.3.4 Conclusion

The staff reviewed the applicant’s TLAA on reflood thermal shock analysis of the RV for a

design basis LOCA and concluded that the applicant has demonstrated that the limiting beltline

material will have adequate fracture toughness when exposed to stresses due to reflood

thermal shock due to LOCA. The staff determined that this revised analysis for the period of

extended operation meets the requirements of 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 periods of extended operation as required by 10 CFR 54.21(c)(1).
4-12

4.2.4 Reflood Thermal Shock Analysis of the Reactor Vessel Core Shroud

4.2.4.1 Summary of Technical Information in the Application

LRA Section 4.2.4 states that the radiation embrittlement may affect the ability of RV internals,

particularly the core shroud, to withstand a LPCI thermal shock transient. The applicant stated

that the analysis of core shroud strain due to reflood thermal shock is based on the calculated

lifetime neutron fluence. In the thermal shock analysis of the RV core shrouds, the applicant

considered the location on the inside surface of the core shroud opposite the midpoint of the

fuel centerline as the location most susceptible to damage during a LPCI thermal shock

transient because it receives the maximum irradiation. This analysis satisfies the criteria of

10 CFR 54.3(a). As such, this analysis is a TLAA. 

The applicant stated that it used the approved fluence methodology discussed in LRA

Section 4.2.2, and the 54 EFPY fluence at the most irradiated point on the core shroud was

calculated to be 5.34 x 1021 n/cm2 (E > 1 MeV) for BFN units. The maximum thermal shock

stress due to a LPCI transient in this region will be 155,700 psi equivalent to 0.57 percent

strain. This strain range of 0.57 percent was calculated at the midpoint of the shroud when it is

exposed to 54 EFPY fluence. The applicant compared the calculated strain range with the

measured values of percentage of elongation for annealed Type 304 stainless steel irradiated

to 8 x 1021 n/cm2 (E > 1 MeV). The measured value of percent elongation for stainless steel

weld metal is 4 percent for a temperature of 297 °C (567 °F) with a neutron flux of 8 x 1021 n/cm2

(E > 1 MeV), while the average value for base metal at 290 °C (554 °F) is 20 percent. The

applicant concluded that the measured value of elongation bounds the calculated thermal shock

strain amplitude of 0.57 percent and that the calculated thermal shock strain at the most

irradiated location is acceptable considering the embrittlement effects for the period of extended

operation. 

4.2.4.2 Staff Evaluation

In the thermal shock analysis of RV core shrouds, the applicant considered the location on the

inside surface of the core shroud opposite the midpoint of the fuel centerline as a location most

susceptible to damage during a LPCI thermal shock transient because it receives the maximum

irradiation. This fluence is calculated using the methodology of NEDC-32983P, “General

Electric Methodology for Reactor Pressure Vessel Fast Neutron Flux Evaluation,” which has

been approved by the staff. 

The staff’s review of LRA Section 4.2.4 identified areas in which additional information was

necessary to complete the review of the reflood thermal shock analysis of the reactor vessel

core shroud evaluation. The applicant responded to the staff’s RAI as discussed below.

In RAI 4.2.4-1(A), dated December 1, 2004, the staff stated that in LRA Section 4.2.4, “Reflood

Thermal Shock Analysis of the RV Core Shroud and Repair Hardware,” the applicant stated

that the total integrated neutron flux at the end of 54 EFPY at the shroud inside surface is

expected to be 5.34 x 1021 n/cm2 (E > 1 MeV). Therefore, the staff requested that the applicant

provide an explanation of whether this value is bounding at the inside shroud surface for all
1TVA by letter dated January 7, 2005, agreed to decouple the power uprate licensing

request from License Renewal Application. The safety review of this item will be further

evaluated as part of the EPU review. 

4-13

three units. If so, submit information whether the neutron fluence values are estimated based

on the implementation of EPU1.

In its response, by letter January 31, 2005, the applicant stated that the calculation of shroud

fluence, 5.34 x 1021 n/cm2 (E > 1 MeV) is based on the inner diameter peak flux of 3.14 x 1012

n/cm2-sec (E > 1 MeV) for 54 EFPY, which is the lifetime used for Unit 1. Since lifetime used for

BFN Units 2 and 3 is 52 EFPY, 5.34 x 1021 n/cm2 (E > 1 MeV) fluence from Unit 1 is bounding

for all the BFN units. The fluence value for the shroud inner diameter was based on the

implementation of EPU conditions. After the review, the staff concurred with the applicant, and

accepted the conservative bounding fluence value of 5.34 x 1021 n/cm2 (E > 1 MeV) for all the

three units.

RAI 4.2.4-1(B) and the applicant’s response are addressed in SER Section 4.7.6.2 under core

shroud subsection.

In RAI 4.2.4-1(C), dated December 1, 2004, the staff stated that the applicant calculated

thermal strain resulting from the LPCI reflood thermal shock transient in the core shroud region.

The applicant compared the calculated thermal strain with the measured values of percentage

of elongation of annealed Type 304 stainless steel irradiated to 8 x 1021 n/cm2 (E > 1.0 MeV). In

a previous analysis performed by Dresden/Quad Cities, the applicant used the percentage

reduction in area as a criterion to evaluate the thermal strain. Therefore, the staff requested

that the applicant provide information on the measured percentage reduction in area values for

the irradiated Type 304 stainless steel. The applicant should compare the results of the analysis

obtained from using the reduction in area, with the ones using the percentage of elongation,

and justify which of these properties is more appropriate to use in evaluating the local thermal

shock strain associated with the reflood thermal shock event at the most irradiated core shroud

region.

In its response, by letter January 31, 2005, the applicant submitted the following reduction in

area and elongation values for irradiated stainless steel materials: 

Reduction in Area

Fluence (n/cm2, E>1MeV) Test Temperature (°F) Reduction in Area (%)

 1 x 1021 550 40

6.9 x 1021 750 52.5
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Elongation

 Material Fluence n/cm2,

(E>1MeV)

 Test Temperature (°F) Elongation 

 (%)

Base 8 x 1021 554 20

Weld 8 x 1021 567 4

The applicant stated that the bounding shroud fluence (Unit 1) is 5.34 x 1021 n/cm2 (E >1 MeV)

for BFN, and the listed ductility values bound all three BFN shrouds. As described in LRA

Section 4.2.4, the maximum thermal shock stress results in a calculated thermal shock strain

amplitude of 0.57 percent. Both reduction in area and elongation values, which are values at

failure, are significantly in excess of the calculated thermal shock strain at the most irradiated

location. While the analysis indicates that either measure of ductility is acceptable for the period

of extended operation, reduction in area is a more appropriate measure of ductility for the

reflood thermal shock event. The strain associated with the reflood thermal shock event is very

localized and is constrained by the surrounding bulk material. As such, it is similar to the triaxial

stress condition present in the neck region (where the area reduction is taking place) during a

tensile test. The percentage reduction in area is a measure of this triaxial stress state and, as

such, is the most appropriate property for evaluating the effect of thermal shock on the RV core

shroud. This staff position was previously approved for Dresden and Quad Cities LRA SER

(NUREG-1796). The staff concluded that the thermal shock strain associated with the LOCA is

less than the reduction in area or elongation, which would be expected to fail the shroud at the

highest fluence point. Therefore, the staff concluded that the core shroud will have sufficient

ductility during the reflood thermal shock transient during the period of extended operation. The

staff accepts the applicant’s analysis for the BFN units. 

4.2.4.3 UFSAR Supplement

As required by 10 CFR 54.21(d), applicants for license renewal must include a UFSAR

supplement summary description of the “programs and activities for managing the effects of

aging and the evaluation of TLAA for the period of extended operation.” The applicant provided

UFSAR supplement summary description of reflood thermal shock analysis of the RV core

shroud in LRA Section A. On the basis of its review, the staff concluded that the UFSAR

supplement summary adequately describes the TLAA on reflood thermal shock analysis of the

RV core shroud and is, therefore, acceptable.

4.2.4.4 Conclusion

The staff reviewed the applicant’s TLAA on reflood thermal shock analysis of the RV core

shroud and the applicant’s responses to the RAIs and concluded that the applicant has

demonstrated that the calculated thermal shock strain at the most irradiated portion of the core

shroud is acceptable. The staff also accepted the applicant’s conservative methodology in

establishing the integrity of the most irradiated location of the core shroud during a

low-pressure coolant injection thermal shock event. The staff determined that the revised

analysis for the period of extended operation meets the requirements of 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 periods of extended operation as required by 10 CFR 54.21(c)(1).
4-15

4.2.5 Reactor Vessel Thermal Limit Analyses: Operating Pressure-Temperature Limits

4.2.5.1 Summary of Technical Information in the Application

In LRA Section 4.2.5, the applicant addressed the RV thermal limit analysis. The ART value is

the sum of initial RTNDT + delta RTNDT + margins for uncertainties at a specific location. Neutron

embrittlement increases the ART value. Thus, the minimum metal temperature at which an RV

is allowed to be pressurized increases. The ART value of the limiting beltline material is used to

correct the beltline P-T limits to account for irradiation effects. Appendix G of 10 CFR Part 50

requires RV thermal limit analyses to determine operating P-T limits for three categories of

operation: (1) hydrostatic pressure tests and leak tests, referred to as Curve A; (2) non-nuclear

heatup/cooldown and low-level physics tests, referred to as Curve B; and (3) core critical

operation, referred to as Curve C. P-T limits are developed for three vessel regions: the upper

vessel region, the core beltline region, and the lower vessel bottom head region. The

calculations associated with generation of the P-T curves satisfy the criteria of 10 CFR 54.3(a).

As such, this topic is a TLAA.

The applicant stated that the BFN Technical Specifications Section 3.4.9 contains P-T limit

curves for heatup, cooldown, criticality, and inservice leakage and hydrostatic testing.

According to the applicant, limits are also imposed on the maximum rate of change of reactor

coolant temperature. The P-T limit curves are currently calculated for 12 EFPY (Unit 1),

17.2 EFPY (Unit 2) and 13.1 EFPY (Unit 3) operating periods. The applicant stated that new

P-T limits will be calculated and submitted for approval prior to the start of extended operation. 

4.2.5.2 Staff Evaluation

The applicant plans to calculate vessel P-T limit curves for all BFN units and submit them to the

staff for approval before the start of the period of extended operation using an approved fluence

methodology. By letter dated December 6, 2004, the applicant submitted updated P-T curves

for Unit 1, which are currently being reviewed by the staff. The applicant stated that the P-T

curves for Units 2 and 3 were approved by the staff as documented in safety evaluations dated

March 10, 2004. The applicant’s CLB allows the development of P-T limit curves consistent with

the 2000 Edition, 2001 Addenda of Section XI of the ASME Code. The applicant stated that it

will manage the P-T limits using approved fluence calculations when there are changes in

power of core design in conjunction with surveillance capsule results from the BWRVIP

integrated surveillance program. The staff found the applicant’s plan to manage the P-T limits

acceptable because the change in P-T curves will be implemented by the license amendment

process (i.e., modifications of technical specifications) and will meet the requirements of

10 CFR 50.60 and 10 CFR Part 50, Appendix G.

4.2.5.3 UFSAR Supplement

As required by 10 CFR 54.21(d), applicants for license renewal must include a UFSAR

supplement summary description of the “programs and activities for managing the effects of

aging and the evaluation of TLAA for the period of extended operation.” The applicant provided

UFSAR supplement summary description of RV thermal limit analyses: operating temperature

and pressure limits in LRA Section A.3.1.5. On the basis of its review, the staff concluded that
4-16

the UFSAR supplement summary adequately describes the TLAA on reactor vessel thermal

limit analyses: operating P-T limits and is, therefore, acceptable.

4.2.5.4 Conclusion

The staff reviewed the applicant’s TLAA on P-T limits, as summarized in LRA Section 4.2.5 and

determined that the applicant will generate the P-T limits for the periods of extended operation

for BFN. The staff therefore concluded that the applicant’s TLAA for the BFN P-T limits will

meet the requirements of 10 CFR 54.21(c)(1)(ii) when the P-T limits for the periods of extended

operation are generated and incorporated into the BFN technical specifications and that the

safety margins established and maintained during the current operating term will be maintained

during the periods of extended operation as required by 10 CFR 54.21(c)(1). The staff also

concluded that the UFSAR 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).

4.2.6 Reactor Vessel Circumferential Weld Examination Relief

4.2.6.1 Summary of Technical Information in the Application

LRA Sections 4.2.6 and A.3.1.6 discuss inspection of the RV circumferential welds. These

sections of the LRA indicate that the applicant will use an approved relief from ultrasonic testing

of RV circumferential shell welds. The applicant stated that the relief from RV circumferential

weld examination requirements under GL 98-05 is based on probabilistic assessments that

predict an acceptable probability of failure per reactor operating year. The analysis is based on

RV metallurgical conditions as well as flaw indication sizes and frequencies of occurrence that

are expected at the end of a licensed operating period. The applicant stated that Units 2 and 3

have received this relief for the remainder of their current 40-year licensed operating periods.

Unit 1 submitted a relief request (currently under review by the staff) for the remainder of its

40-year licensed operating period. The circumferential weld examination relief analyses meet

the requirements of 10 CFR 54.3(a). As such, they are a TLAA.

The basis for this relief request was an analysis that satisfied the limiting conditional failure

probability for the circumferential welds at the expiration of the current license, based on topical

report BWRVIP-05, “Reactor Vessel Shell Weld Inspection Guidelines,” and the extent of

neutron embrittlement. The anticipated changes in metallurgical conditions expected over the

extended licensed operating period require an additional analysis for the period of extended

operation and approval by the staff to extend this relief request.

The staff evaluation of BWRVIP-05 utilized the favor code to perform a probabilistic fracture

mechanics (PFM) analysis to estimate the RPV shell weld failure probabilities. Three key

assumptions of the PFM analysis were (1) the neutron fluence was the estimated end-of-license

mean fluence, (2) the chemistry values were mean values based on vessel types, and (3) the

potential for beyond design basis events (DBEs) was considered. LRA Table 4.2.6.1 provides a

comparison of Units 2 and 3 RV limiting circumferential weld parameters to those used in the

staff evaluation of BWRVIP-05 for the first two key assumptions. Data provided in LRA

Table 4.2.6.1 were supplied from Tables 2.6.4 and 2.6.5 of the final safety evaluation of the

BWRVIP-05 report.
4-17

For Units 2 and 3, the fluence is equivalent to that used in the staff analysis. However, Units 2

and 3 weld materials have significantly lower copper values (0.09 vs. 0.31) than those used in

the NRC analysis. As a result, the shifts in reference temperature for Units 2 and 3 are lower

than the 64 EFPY shift from the staff SER analysis. In addition, the unirradiated reference

temperatures for both units are significantly lower. The combination of initial RTNDT and delta

RTNDT without margin yields mean RTNDT values for Units 2 and 3 that are considerably lower

than the staff mean analysis values. Based on this analysis, the applicant concluded that the

RV conditional failure probability is bounded by the staff analysis. The applicant claimed that

the procedures and training used to limit cold over-pressure events will be the same as those

approved by the staff when the applicant requested the relief for the current license term for

Units 2 and 3. 

4.2.6.2 Staff Evaluation

The technical basis for relief is discussed in the staff’s final SER concerning the BWRVIP-05

report, which is enclosed in a July 28, 1998, letter from Mr. G.C. Laines (NRC) to Mr. C. Terry

(BWRVIP Chairman). In this letter, the staff concluded that since the failure frequency for RV

circumferential welds in BWR plants is significantly below the criterion specified in RG 1.154,

“Format and Content of Plant-Specific Pressurized Thermal Shock Safety Analysis Reports for

Pressurized Water Reactors,” and below the core damage frequency of any BWR plant, the

continued inspection would result in a negligible decrease in an already acceptably low value of

RV failure. Therefore, elimination of the inservice inspection (ISI) for RV circumferential welds is

justified. The staff’s letter indicated that BWR applicants may request relief from ISI

requirements of 10 CFR 50.55a(g) for volumetric examination of circumferential RV welds by

demonstrating that (1) at the expiration of the license, the circumferential welds satisfy the

limiting conditional failure probability for circumferential welds in the staff’s July 28, 1998

evaluation, and (2) the applicants have implemented operator training and established

procedures that limit the frequency of cold over-pressure events to the frequency specified in

the staff’s SER. The letter indicated that the requirements for inspection of circumferential RV

welds during an additional 20-year license renewal period would be reassessed, on a

plant-specific basis, as part of any BWR LRA. Therefore, the applicant must request relief from

inspection of circumferential welds during the license renewal period per 10 CFR 50.55a.

Section A.4.5 of the BWRVIP-74 report indicates that the staff’s SER of the BWRVIP-05 report

conservatively evaluated the BWR RVs to 64 EFPY, which is 10 EFPY greater than what is

realistically expected for the end of the license renewal period. The staff used the mean RTNDT

value for materials to evaluate failure probability of BWR circumferential welds at 32 and 64

EFPY in the staff SER dated July 28, 1998. The neutron fluence used in this evaluation was the

neutron fluence at the clad-weld (inner) interface. 

Since the staff analysis discussed in the BWRVIP-74 report is a generic analysis, the applicant

submitted plant-specific information to demonstrate that the beltline materials meet the criteria

specified in the report. To demonstrate that the vessels for Units 2 and 3 have not become

embrittled beyond the basis for the relief, the applicant, in LRA Table 4.2.6.1, supplied a

comparison of 52 EFPY material data for the limiting BFN circumferential welds with that of the

64 EFPY reference case in Appendix E of the staff’s SER of the BWRVIP-05 report. The BFN

material data included amounts of copper and nickel, chemistry factor, the neutron fluence,

delta RTNDT, initial RTNDT, and mean RTNDT of the limiting circumferential weld at the end of the
4-18

renewal period. The staff verified the data for the copper and nickel contents and the initial

RTNDT values for Units 2 and 3 beltline materials by comparing them with the corresponding

data in the RVID maintained by the staff. The 52 EFPY mean RTNDT value for Units 2 and 3 is

25 °F. The staff checked the applicant’s calculations for the 52 EFPY mean RTNDT values for the

circumferential welds using the data presented in LRA Table 4.2.6.1 and found them accurate.

These 52 EFPY mean RTNDT values for Units 2 and 3 are less than the 64 EFPY mean RTNDT

value of 129.4 °F used by the staff for determining the conditional failure probability of a

circumferential weld. The 64 EFPY mean RTNDT value from the staff SER dated July 28, 1998,

is for a Babcock and Wilcox (B&W) weld, because B&W welded the circumferential welds in the

vessels. Since the BFN 52 EFPY mean RTNDT values are less than the 64 EFPY value from the

staff SER dated July 28, 1998, the staff concluded that the BFN RV conditional failure

probabilities are bounded by the staff analysis. 

The applicant stated that the procedures and training used to limit cold over-pressure events

will be the same as those approved by the staff when the applicant requested relief for the

current license period, but it did not explicitly cite a document that supports this statement. The

applicant stated that the procedure and training requirements identified in the applicant’s

request to use the BWRVIP-05 report are provided in the document, “Safety Evaluation by the

Office of Nuclear Reactor Regulation Related to Alternative to Inspection of Reactor Pressure

Vessel Circumferential Welds, BFN Power Station, Units 2 and 3," (attached to staff letter to

TVA; “Browns Ferry Nuclear Plant Unit 2, Relief Request 2-ISI-9, Alternatives for Examination

of Reactor Pressure Vessel Shell Welds (TAC No. MA8424),” August 14, 2000; and staff letter

to the applicant, “Browns Ferry Nuclear Plant Unit 3, Relief Request 3-ISI-1, Revision 1,

Alternatives for Examination of Reactor Pressure Vessel Shell Welds (TAC No. MA5953),”

November 18, 1999. The applicant further stated that LRA Section 4.2.6, and associated LRA

Section A.3.1.6, reference the safety evaluation request letters identified above. The staff found

the response acceptable because the applicant identified the requested references and

commits to include them in LRA Sections 4.2.6 and A.3.1.6. 

By letter dated May 12, 2004, the applicant submitted a relief request concerning the

examination of the Unit 1 RV circumferential welds for the current license period. 

In RAI 4.2.6-1, dated December 1, 2004, the staff requested that the applicant provide the RV

circumferential weld examination relief analyses for Unit 1. In its response, by letter January 31,

2005, the applicant submitted the following relief analyses related to the Unit 1 RV

circumferential weld examination:

The following table provides a comparison of the BFN Unit 1 RV limiting circumferential

weld parameters to those used in the NRC evaluation of BWRVIP-05 for the first two

key assumptions. Data provided in this table was supplied from Tables 2.6.4 and 2.6.5

of the Final Safety Evaluation of the BWRVIP-05 Report (NRC letter from Gus C. Lainas

to Carl Terry, Niagara Mohawk Power Company, BWRVIP Chairman, “Final Safety

Evaluation of the BWRVIP Vessel and Internals Project BWRVIP-05 Report,” (TAC No.

M93925), July 28, 1998.
4-19

 Group B & W 

 64 EFPY

 BFN Unit 1

54 EFPY

Cu % 0.31 0.27

Ni % 0.59 0.6

 CF 196.7 184

Fluence at clad/weld interface 

1019 n/cm2

 0.19 0.2

Delta RTNDT without margin (°F) 109.4 104

Initial RTNDT (°F) 20 20

Mean RTNDT (°F) 129.4 124

P (F/E) NRC 4.83 x 10-4 -------------------------

P (F/E) BWRVIP --------------------- -----------------------

The fluence assumed for Unit 1 is very conservative based on an extended shutdown

period from 1985 to a scheduled restart in 2007, which will result in less than 32 EFPY

of vessel exposure through the end of the extended period of operation. However, TVA

conservatively chose to use the higher exposure of 54 EFPY to simplify the basis for the

Unit 1 vessel evaluations. As shown in the table, the Unit 1 unirradiated weld RTNDT is

identical to the reference B&W plant unirradiated weld RTNDT used in the NRC analysis,

and the Unit 1 fluence value is approximately equivalent to that used in the NRC

analysis. However, because the Unit 1 chemistry factor is less than the reference B&W

plant, the mean RTNDT values for Unit 1 at 54 EFPY are bounded by the 64 EFPY Mean

RTNDT assumed by the NRC in its analysis. Accordingly, Unit 1 is bounded by the

conditional failure probability calculated by the Staff for the limiting B&W vessel. An

extension of this relief for the 60-year period will be submitted to the NRC for approval

prior to entering the period of extended operation.

The staff verified the accuracy of the of the mean RTNDT for the limiting beltline circumferential

weld at Unit 1 and found it acceptable. In the staff’s evaluation of the BWRVIP-05 report, a

fluence of 0.19 x 1019 n/cm2 for B&W RVs was used for 64 EFPY and the corresponding delta

RTNDT value is 109.4 °F. The delta RTNDT value for the limiting beltline weld metal of Unit 1 is

less than the limiting delta RTNDT value in the staff’s evaluation of BWRVIP-05 report, which is

conservative. Therefore, the applicant’s calculated mean RTNDT value for the limiting beltline

weld metal is acceptable and meets the requirements specified in staff’s approved SER for the

BWRVIP-05 report. 

The staff’s SER for the BWRVIP-05 report provides a limiting conditional failure probability of

4.83 x 10-4 per reactor-year for a limiting plant-specific mean RTNDT of 129.4 °F for B&W

fabricated RVs. The low temperature over-pressure (LTOP) transient frequency is the

frequency of the transient occurring, determined as 10-3 per reactor-year in the evaluation of

BWRVIP-05 report. The conditional failure probability is the probability of failure, if the event
4-20

were to occur. The vessel failure frequency is the product of conditional failure probability and

LTOP frequency. Comparing the information in the RVID with that submitted in the analysis, the

staff confirmed that the mean RTNDT of the circumferential welds at Unit 1 is projected to be

124 °F at the end of the period of extended operation (54 EFPY). In this evaluation, the

chemistry factor, delta RTNDT, and mean RTNDT were calculated consistent with the guidelines of

RG 1.99, Revision 2. Since the calculated value of mean RTNDT for the circumferential welds at

Unit 1 is lower than that for the limiting plant-specific case for B&W fabricated RVs, the vessel

failure frequencies of the Unit 1 circumferential welds is less than 4.83 x 10-7 per reactor-year. 

The staff found that the applicant’s evaluation for this TLAA is acceptable because the BFN

54 EFPY conditional failure probabilities for the RV circumferential welds are bounded by the

staff analysis in the staff SER dated July 28, 1998, and the applicant will be using procedures

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

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

the applicant is still required to request relief for the circumferential weld examination for the

period of extended operation in accordance with 10 CFR 50.55a.

4.2.6.3 UFSAR Supplement

The applicant’s UFSAR supplement summary description for the TLAA on RV circumferential

weld examination relief appropriately describes that the conditional failure probabilities for the

RV circumferential welds are bounded by the staff analysis in the staff SER dated July 28,

1998, and the applicant will be using procedures and training to limit cold over-pressure events

during the period of extended operation for Units 2 and 3. Since the UFSAR supplement

summary description adequately describes the TLAA for Units 2 and 3, the staff concluded that

the UFSAR supplement summary description for the TLAA on RV circumferential weld

examination relief for Units 2 and 3 is acceptable. In addition, in a letter dated May 25, 2005,

the applicant stated that the UFSAR supplement summary description also includes Unit 1 as

shown in the revised supplement A.3.1.6.

4.2.6.4 Conclusion

The staff reviewed the applicant’s TLAA on RV circumferential weld examination relief, as

summarized in LRA Section 4.2.6, and determined that the applicant appropriately explained

that the conditional failure probabilities for the RV circumferential welds are bounded by the

staff analysis in the SER on the BWRVIP-05 report, dated July 28, 1998, and that the applicant

will be using procedures and training to limit cold over-pressure events during the period of

extended operation for BFN. However, the staff concluded that the LRA Section A.3.1.6 should

include circumferential weld examination analysis for Unit 1. The staff, therefore, concluded that

the applicant’s LRA Section 4.2.6 on TLAA, and LRA Section A.3.1.6 for the BFN RV

circumferential weld examination relief will meet the requirements of 10 CFR 54.21(c)(1)(ii),

except as noted above.
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4.2.7 Reactor Vessel Axial Weld Failure Probability

4.2.7.1 Summary of Technical Information in the Application

LRA Section 4.2.7 discusses the BWRVIP recommendations for inspection of RV shell welds

and contains generic analyses supporting a staff SER conclusion that the axial weld failure rate

is no more than 5 x 10-6 per reactor year. The applicant stated that the supporting evaluations

described in the LRA only apply to Units 2 and 3. The axial weld failure probability analysis

meets the requirements of 10 CFR 54.3(a). As such, it is a TLAA.

The applicant compared the limiting axial weld properties at 52 EFPY for Units 2 and 3 with the

limiting axial weld properties provided in the supplement to NRC SER for BWRVIP-05. The

limiting axial welds at Units 2 and 3 are all electroslag welds with similar chemistry. The Units 2

and 3 limiting weld chemistry, chemistry factor, and 52 EFPY mean RTNDT values are within the

limits of the values assumed in the analysis performed by the staff in the BWRVIP-05 SER

supplement. The applicant concluded that the probability of failure for the axial welds is

bounded by the staff evaluation.

4.2.7.2 Staff Evaluation

In its July 28, 1998, letter to Mr. C. Terry, the BWRVIP Chairman, the staff identified a concern

about the failure frequency of axially-oriented welds in BWR RVs. In response to this concern,

in letters dated December 15, 1998, and November 12, 1999, the BWRVIP supplied

evaluations of axial weld failure frequency. The staff’s SER on these analyses is enclosed in a

March 7, 2000, letter from Mr. J. Strosnider (NRC) to Mr. C. Terry, (BWRVIP Chairman). The

staff performed a generic analysis using Pilgrim Nuclear Station SER as a model for BWR RVs

that were fabricated with electroslag welds, and demonstrated that a mean RTNDT of 114 °F

resulted in a failure frequency of 5 x 10-6 per reactor-year of operation. The applicant

calculated, and the staff confirmed, that the limiting axial weld mean RTNDT value for Units 2 and

3 at 52 EFPY is 108 °F, which supports the conclusion that the failure frequencies for Units 2

and 3 will be less than 5 x 10-6 per reactor-year of operation at the end of their period of

extended operation. Therefore, this analysis is acceptable. 

In RAI 4.2.7-1, dated December 1, 2004, the staff requested that the applicant provide an

evaluation for the RV axial weld failure probability analyses for Unit 1 for the current license

period, and the period of extended operation. In its response to RAI 4.2.7-1, by letter dated

January 31, 2005, the applicant provided the following evaluation on the RV axial weld failure

probability analysis for Unit 1:

The table provided below compares the limiting axial weld 54 EFPY properties for Unit 1

against the values taken from Table 2.6.5 found in the NRC SER for BWRVIP-05 and

associated supplement to the SER (NRC letter from Jack R. Strosnider, to Carl Terry,

BWRVIP Chairman, “Supplement to Final Safety Evaluation of the BWR Vessel and

Internals Project BWRVIP-05 Report,” (TAC No. MA3395), March 7, 2000). The SER

supplement required the limiting axial weld to be compared with data found in Table 3 of

the document. For Unit 1 the comparison was made to the ‘Mod 2’ plant information.

The supplemental SER stated that the ‘Mod 2’ calculations most closely match the 5 x

10-6 RV failure frequency.
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Effects of Irradiation on RV Axial Weld Properties BFN Unit 1:

 Value NRC BWRVIP-05 SER 

MOD 2 

 BFN Unit 1

54 EFPY

 Cu % 0.219 0.24

 Ni % 0.996 0.37

 CF ------ 141

Fluence at clad/weld

interface 

1019 n/cm2

 0.148 (Peak Axial Fluence) 0.24

)RTNDT without margin (0F) 116 86

RTNDT(U) (°F) -2 23

Mean RTNDT (°F) 114 109

P (F/E) NRC 5.02 x 10-6 Not Calculated

The limiting axial weld is an electroslag weld with similar chemistry. The Unit 1 limiting

weld chemistry, chemistry factor, and 54 EFPY mean RTNDT values are within the limits

of the values assumed in the analysis performed by the NRC staff in the BWRVIP-05

SER supplement and the 64 EFPY limits and values obtained from Table 2.6.5 of the

SER. Therefore, the probability of failure for the axial welds is bounded by the NRC

evaluation.

In this evaluation, the chemistry factor delta RTNDT and mean RTNDT were calculated consistent

with the guidelines of RG 1.99, Revision 2. The applicant calculated, and the staff confirmed,

that the limiting axial weld mean RTNDT value for Unit 1 at 54 EFPY is 109 °F. This value is lower

than that for the limiting mean RTNDT value of 114 °F in the staff’s evaluation of BWRVIP-05.

Therefore, the staff concluded that the failure frequencies for Unit 1 axial welds will be less than

5 x 10-6 per reactor-year of operation. The probability of failure for the axial welds is bounded by

the staff evaluation.

4.2.7.3 UFSAR Supplement

As required by 10 CFR 54.21(d), applicants for license renewal must include a UFSAR

supplement summary description of the “programs and activities for managing the effects of

aging and the evaluation of TLAA for the period of extended operation.” The applicant provided

UFSAR supplement summary description of RV axial weld failure probability in LRA

Section A.3.1.7. On the basis of its review, the staff concluded that the UFSAR supplement

summary adequately describes the TLAA on RV axial weld failure probability and is, therefore,

acceptable. In addition, in a letter dated May 25, 2005, the applicant stated that the UFSAR

supplement summary description also includes Unit 1 as shown in the revised supplement

A.3.1.7.
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4.2.7.4 Conclusion

The staff reviewed the applicant’s TLAA on the evaluation of RV axial weld failure probabilities,

as summarized in LRA Section 4.2.7, and determined that the applicant appropriately describes

that the analyses of the conditional failure probabilities for the BFN Units 2 and 3 RV axial welds

is bounded by the NRC analysis in the staff SER on the BWRVIP-05 report, dated July 28,

1998. However, the UFSAR supplement summary description in LRA Section A.3.1.7 should

include the analysis on the conditional failure probabilities for the Unit 1 RV axial welds. The

staff therefore concluded that the applicant’s LRA Sections 4.2.7, and A.3.1.7 related to the

analysis of the conditional failure probabilities for the BFN units RV axial welds are acceptable.

The staff concluded that the analysis of the RV axial weld failure probability for the BFN units

will meet the requirements of 10 CFR 54.21(c)(1)(ii), except as noted above.

4.3 Metal Fatigue

A metal component subjected to cyclic loading at loads less than the static design load may fail

due to fatigue. Metal fatigue of components may have been evaluated based on an assumed

number of transients or cycles for the current operating term. The validity of such metal fatigue

analysis is reviewed for the period of extended operation. The GALL Report identifies fatigue

aging related effects that require evaluation as possible TLAAs, pursuant to 10 CFR 54.21(c).

Each of these is summarized in the SRP-LR and presented in LRA Section 4.

4.3.1 Reactor Vessel Fatigue Analysis

4.3.1.1 Summary of Technical Information in the Application

In LRA Section 4.3.1, “Reactor Vessel Fatigue Analyses,” the applicant stated that the original

pressure vessel stress report included ASME Code Section III fatigue analyses of the RV

components based on a set of design basis transients and corresponding cycles, which are

listed in UFSAR Section 4.2.5. The analyzed components consisted of the vessel support skirt,

shell, upper and lower heads, closure flanges, nozzles and penetrations, nozzle safe ends, and

closure studs. The original 40-year analysis demonstrated that the cumulative usage factors

(CUFs) for these components are below the ASME Code Section III limiting value of 1.0. A

re-analysis was performed for BFN to determine the CUFs of these components under EPU

and Maximum extended load line limit analysis conditions, for 60 years of operation. LRA

Table 4.3.1.1 lists the results of this re-analysis for seven bounding reactor vessel components.

These components are the recirculation outlet nozzle, recirculation inlet nozzle, feedwater

nozzle, core spray nozzle, the support skirt, the closure stud bolts, and the vessel shell. This

table shows that for Units 2 and 3, the recirculation outlet nozzles, the feedwater nozzles, the

support skirts and the closure stud bolts, all have 60-year projected CUFs that exceed the

ASME Code Section III Class 1 limiting value of 1.0. These results also bound the projected

CUFs for Unit 1. 

The applicant stated that fatigue aging of the seven components listed in LRA Table 4.3.1-1 will

be managed by the Fatigue Monitoring Program (LRA Section B.3.2) for the period of extended

operation.
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The applicant also stated that the original ASME Code analysis of the reactor vessel also

included fatigue analyses of the feedwater nozzles and the control rod drive (CRD) hydraulic

system return line nozzles. After several years of operation, these nozzles were found to be

susceptible to cracking caused by a number of factors, including rapid thermal cycling. The

CRD hydraulic system return line nozzles were therefore capped and removed from service. As

such, they are no longer susceptible to rapid thermal cycling. A re-analysis was performed on

the feedwater nozzles and modifications were implemented to reduce or eliminate the effects of

the high thermal cycling, based on generic BWROG guidance. 

Based on its evaluation, the applicant concluded that, for some components, the fatigue

analyses of the reactor vessel will remain valid for the period of extended operation, in

accordance with 10 CFR 54.21(c)(1)(i), or that for the remaining vessel components, the effects

of aging will be adequately managed for the period of extended operation, in accordance with

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

4.3.1.2 Staff Evaluation

The staff reviewed the technical information in LRA Section 4.3.2, pertaining to the fatigue

analysis of reactor vessel components. The CLB fatigue analyses of components associated

with the reactor vessels were identified as TLAAs, in accordance with the provisions of

10 CFR 54.3(a) and the components listed in the appropriate tables in the GALL Report. The

applicant listed the bounding CUFs associated with these TLAAs and indicated that the CUFs

for four vessel components would exceed the ASME Code Section III Class 1 limiting value of

1.0 during the period of extended operation. The applicant, therefore, committed to monitor the

fatigue of these vessel components as part of the Fatigue Monitoring Program, which provides

for monitoring fatigue stress cycles to ensure that the CUF limit of 1.0 is not exceeded. The

staff found this acceptable and concurred with the applicant that the effects of aging of the

reactor vessel components for BFN will be adequately managed with the Fatigue Monitoring

Program for the period of extended operation, in accordance with 10 CFR 54.21(c)(1)(iii) The

staff also found acceptable that, for those components where the CUF did not exceed 1.0, the

fatigue analyses were projected to remain valid to the end of the period of extended operation,

in accordance with 10 CFR 54.21(c)(1)(ii).

In accordance with 10 CFR 54.21(d), the applicant’s supplement for the UFSAR regarding the

reactor vessel fatigue TLAAs is provided in LRA Section A.3.2.1. The staff reviewed this

supplement and found it acceptable because it provides a reasonable summary of the

information presented in LRA Section 4.3.1.

4.3.1.3 UFSAR Supplement

As required by 10 CFR 54.21(d), applicants for license renewal must include a UFSAR

supplement summary description of the “programs and activities for managing the effects of

aging and the evaluation of TLAA for the period of extended operation.” The applicant provided

a UFSAR supplement summary description of reactor vessel fatigue analyses in LRA

Section A.3.2.1. On the basis of its review, the staff concluded that the UFSAR supplement

summary adequately describes the reactor vessel fatigue TLAAs and is, therefore, acceptable.
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4.3.1.4 Conclusion

The staff reviewed the applicant’s TLAA on the reactor vessel fatigue analyses, as summarized

in LRA Section 4.3.1, and determined that the metal fatigue assessments at Units 1, 2, and 3

will continue to comply with the staff’s requirements throughout the period of extended

operation. The staff, therefore, concluded that the applicant’s TLAA for reactor vessel fatigue

analyses meets the requirements of 10 CFR 54.21(c)(1)(ii), (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 UFSAR supplement contains an appropriate summary description of the TLAA on reactor

vessel fatigue analyses for the period of extended operation, as required by 10 CFR 54.21(d).

4.3.2 Fatigue Analysis of Reactor Vessel Internals

4.3.2.1 Summary of Technical Information in the Application

In LRA Section 4.3.2, “Fatigue Analysis of Reactor Vessel Internals,” the applicant stated that

the original fatigue evaluation of the reactor vessel internals was performed using ASME Code

Section III as a guide. The evaluation determined that the most significant fatigue loading

occurs at the jet pump diffuser-to-baffle-plate weld location. The fatigue analysis of this location

was the only fatigue analysis actually performed. Since this analysis was based on a number of

cycles for a 40-year life, it is considered a TLAA. The calculated CUF was 0.35, less than the

ASME Code Section III Class 1 allowable CUF of 1.0. Since the original fatigue analysis was

based on a 40-year design life, the calculation for the jet pump diffuser-to-baffle-plate weld was

projected for a 60-year life by multiplying the CUF by 1.5, which resulted in a CUF less than the

ASME Code allowable of 1.0. 

The applicant also stated that at Unit 3, a lower section of the core spray line was replaced, and

a repair was installed to address cracking found at the location of the core spray-to-T-box weld.

Fatigue calculations were performed for several components of the core spray line using ASME

Code Section III as a guide, since the core spray line is not classified as an ASME Code

Section III component. However, these analyses are considered as TLAAs since they were

based on a 40-year life. A fatigue evaluation of the lower core spray line sectional replacement

was performed, resulting in a maximum calculated CUF of 0.45, based on a 40-year design life.

An explicit fatigue calculation was also performed for the T-box repair, based on a 40-year

design life. The CUF was calculated to be 0.022. The fatigue calculation for the core

spray-to-T-box weld repair was evaluated for a lifetime of 60 years by multiplying the 40-year

CUF by 1.5, which resulted in a 60-year CUF that is less than the ASME Section III Class 1 limit

of 1.0. The fatigue analysis is, therefore, acceptable for the period of extended operation, in

accordance with 10 CFR 54.21(c)(1)(ii). The applicant also concluded that these results are

applicable for BFN.

The applicant stated that the core spray-to-T-box weld location is also included for inspection as

part of the Boiling Water Reactor Vessel Internals Program (LRA Section B.2.1.12). These

inspections will be used to manage the effects of potential cracking of these welds.

For the lower core spray sectional replacement, the design life was specified as 40 years.

However, since this modification was installed more than 20 years into the current licensing
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period, the applicant concluded that these fatigue calculations will remain valid for the period of

extended operation.

Based on the revised fatigue analyses, the applicant concluded that, in accordance with

10 CFR 54.21(c)(1)(i), the fatigue analyses for the reactor internals remain valid for the period

of extended operation or, in accordance with10 CFR 54.21(c)(1)(ii), the fatigue analyses have

been projected to the end of the period of extended operation. The applicant also stated that, in

accordance with 10 CFR 54.21(c)(1)(iii), the effects of aging on the intended function(s) of the

reactor vessel internals for the BFN units will be adequately managed for the period of

extended operation.

4.3.2.2 Staff Evaluation

The staff reviewed the technical information in LRA Section 4.3.2 pertaining to the fatigue

analysis of reactor vessel internals. Based on the reported CUFs corresponding to the reported

fatigue analyses, the staff concurred with the applicant that the fatigue analyses for the reactor

vessel internals remain valid for the period of extended operation, in accordance with

10 CFR 54.21(c)(1)(i), or that the fatigue analyses have been projected to the end of the period

of extended operation, in accordance with10 CFR 54.21(c)(1)(ii). The staff also found

acceptable that the effects of aging on the intended function(s) of the reactor internals for BFN

will be adequately managed with the Fatigue Monitoring Program for the period of extended

operation, in accordance with 10 CFR 54.21(c)(1)(iii).

In accordance with 10 CFR 54.21(d), the applicant’s supplement for the UFSAR regarding the

fatigue analyses of reactor vessel internals is provided in LRA Section A.3.2.2. The staff

reviewed this supplement and found it acceptable. It provides a reasonable summary of the

information presented in LRA Section 4.3.2.

4.3.2.3 UFSAR Supplement

As required by 10 CFR 54.21(d), applicants for license renewal must include a UFSAR

supplement summary description of the “programs and activities for managing the effects of

aging and the evaluation of TLAA for the period of extended operation.” The applicant provided

a UFSAR supplement summary description of the fatigue analysis of reactor vessel internals in

LRA Section A.3.2.2. On the basis of its review, the staff concluded that the UFSAR

supplement summary adequately describes the reactor vessel internals fatigue TLAAs and is,

therefore, acceptable.

4.3.2.4 Conclusion

The staff reviewed the applicant’s reactor vessel internals fatigue TLAAs, as summarized in

LRA Section 4.3.2, and determined that the metal fatigue assessments at BFN Units 1, 2, and 3

will continue to comply with the staff’s requirements throughout the period of extended

operation. The staff, therefore, concluded that the applicant’s evaluation of reactor vessel

internals fatigue TLAAs meets the requirements of 10 CFR 54.21(c)(1)(i) - (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 UFSAR supplement contains an appropriate summary description of the
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TLAA on fatigue analysis of reactor vessel internals for the period of extended operation, as

required by 10 CFR 54.21(d).

4.3.3 Piping and Component Fatigue Analysis

4.3.3.1 Summary of Technical Information in the Application

In LRA Section 4.3.3, “Piping and Components Fatigue Analysis,” the applicant stated that the

reactor coolant pressure boundary (RCPB) and non-RCPB piping was designed to USA

Standard (USAS) B31.1. This code does not require an explicit fatigue analysis. However, the

RCPB and non-RCPB piping within the scope of license renewal that is designed to USAS

B31.1 requires the application of a stress reduction factor to the allowable thermal stress range

if the number of full range cycles exceeds 7000. 

The applicant indicated that the assumed thermal cycle count for the analyses can be

approximated by the thermal cycles used in the reactor vessel fatigue analysis. These thermal

cycles are listed in UFSAR Section 4.2.5. The total count of all these listed thermal cycles is

fewer than 1100 over the 40-year plant life. For the 60-year extended operating period, the

number of assumed operating cycles would be increased to 1650, considerably fewer than the

7000 cycle threshold in USAS B31.1. In accordance with 10 CFR 54.21(c)(1)(i), the applicant

concluded that the existing piping analyses within the scope of licence renewal will remain valid

for the period of extended operation. 

4.3.3.2 Staff Evaluation

The staff reviewed the technical information in LRA Section 4.3.3, pertaining to the fatigue

analysis of piping and components. The applicant indicated that the RCPB and non-RCPB

piping and components at BFN, within the scope of license renewal, were designed to USAS

B31.1-1967. Although this Code does not require explicit fatigue analysis, it considers fatigue

implicitly in the design calculations by applying a stress range reduction factor to the allowable

thermal stress range, which depends on the number of design thermal expansion cycles. The

staff, therefore, concurred with the applicant that qualifications of piping to this code are

considered TLAAs, in accordance with the provisions of 10 CFR 54.21(c)(1). 

In the application of USAS B31.1-1967, the applicant approximated the number of thermal

expansion cycles over a 40-year plant life by the thermal cycles used in the reactor vessel

fatigue analysis. These thermal cycles are listed in UFSAR Section 4.2.5. For a 60-year plant

life, the total count of all significant full thermal cycles was determined as fewer than 1650,

which is substantially less than the 7000-cycle full thermal stress range limit in USAS B31.1.

The staff concurred with the applicant that an adequate margin of safety for the RCPB and

non-RCPB systems will be maintained for the period of extended operation, because the

projected number of thermal operating cycles to the end of the period of extended operation is

fewer than the design cycle limit of 7000 cycles, and the stress range limits in the current piping

calculations therefore remain valid. The staff, therefore, concurred with the applicant that the

existing piping analyses, within the scope of license renewal, will remain valid for the period of

extended operation in accordance with 10 CFR 54.21(c)(1)(i).
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In accordance with 10 CFR 54.21(d), the applicant’s supplement for the UFSAR regarding the

piping and component fatigue analyses is provided in LRA Section A.3.2.3. The staff reviewed

this supplement and found it acceptable because it provides a reasonable summary of the

information presented in LRA Section 4.3.3.

4.3.3.3 UFSAR Supplement

As required by 10 CFR 54.21(d), applicants for license renewal must include a UFSAR

supplement summary description of the “programs and activities for managing the effects of

aging and the evaluation of TLAA for the period of extended operation.” The applicant provided

UFSAR supplement summary description of piping and component fatigue analysis in LRA

Section A.3.2.3. On the basis of its review, the staff concluded that the UFSAR supplement

summary adequately describes the piping and component fatigue TLAA and is, therefore,

acceptable.

4.3.3.4 Conclusion

The staff reviewed the applicant’s piping and component fatigue TLAA, as summarized in LRA

Section 4.3.3, and determined that the metal fatigue assessments at BFN Units 1, 2, and 3 will

continue to comply with the staff’s requirements throughout the period of extended operation.

The staff therefore concluded that the applicant’s piping and component fatigue TLAA meets

the requirements of 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 UFSAR

supplement contains an appropriate summary description of the piping and component fatigue

TLAA for the period of extended operation, as required by 10 CFR 54.21(d).

4.3.4 Effects of Reactor Coolant Environment On Fatigue Life of Components and Piping

(Generic Safety Issue 190)

4.3.4.1 Summary of Technical Information in the Application

In LRA Section 4.3.4, “Effects of Reactor Coolant Environment on Fatigue Life of Components

and Piping (Generic Safety Issue 190),” the applicant described the actions taken to address

the issue of environmentally assisted fatigue. Generic Safety Issue (GSI) 190 addresses the

effects of reactor coolant environment on the fatigue life of components and piping. Although

GSI 190 is resolved, SRP-LR Section 4.3.1.2 states that for licence renewal, the applicant’s

consideration of the effects of coolant environment on component fatigue life is an area of

review. 

The applicant stated that plant-specific calculations were performed for the following fatigue

sensitive component locations, identified in NUREG/CR 6260 for older-vintage BWRs:

 • reactor vessel shell and lower head

 • reactor vessel feedwater nozzle

 • reactor recirculation piping (outlet and inlet nozzles)

 • core spray system (nozzle and safe end)

 • residual heat removal (RHR) line Class 1 piping
4-29

 • feedwater line Class 1 piping

The applicant stated that for each location listed above, detailed environmental fatigue

calculations for 60 years were performed using the appropriate environmental fatigue life

correction factor (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 the appropriate Fen relationships from NUREG/CR 5704 “Effects of LWR Coolant

Environments on Fatigue Design Curves of Austenitic Stainless Steels,” for stainless steel, as

appropriate for the material. These evaluations are consistent with the recommendations in

SRP-LR Section 4.3.2.2 for addressing the effects of the reactor coolant environment by

assessing the effects on a sample of critical components. The 60-year CUF for the reactor

recirculation piping was determined as 4.181, and the 60-year CUF for the feedwater line

Class 1 piping was calculated as 1.489. In accordance with 10 CFR 54.21(c)(1)(iii), the

applicant stated that all necessary plant transients will be tracked using the Fatigue Monitoring

Program, to ensure that CUF values will remain below 1.0 for the period of extended operation.

For the locations where the CUF is expected to exceed 1.0 for the 60-year period, the applicant

stated that additional fatigue analyses will be performed prior to the period of extended

operation, and appropriate action will be taken if the EOL CUF values above 1.0 are projected. 

4.3.4.2 Staff Evaluation

The staff reviewed the technical information in LRA Section 4.3.4 pertaining to the effects of

reactor coolant environment on the fatigue analysis of components and piping.

GSI-166, “Adequacy of the Fatigue Life of Metal Components," raised concerns regarding the

conservatism of the fatigue curves used in the design of the RCS components. Although

GSI-166 was resolved for the current 40-year design life of operating components, the staff

identified GSI-190, "Fatigue Evaluation of Metal Components for 60-year Plant Life," to address

license renewal. The NRC closed GSI-190 in December, 1999, concluding that: 

The results of the probabilistic analyses, along with the sensitivity studies performed, the

iterations with industry (Nuclear Energy Institute (NEI) and EPRI), and the different

approaches available to the licensees to manage the effects of aging, lead to the

conclusion that no generic regulatory action is required, and that GSI-190 is closed.This

conclusion is based primarily on the negligible calculated increases in core damage

frequency in going from 40 to 60 year lives. However, the calculations supporting

resolution of this issue, which included consideration of environmental effects, and the

nature of age-related degradation indicate the potential for an increase in the frequency

of pipe leaks as plants continue to operate. Thus, the staff concluded that, consistent

with existing requirements in 10 CFR 54.21, licensees should address the effects of

coolant environment on component fatigue life as aging management programs are

formulated in support of license renewal.

The applicant evaluated the component locations listed in NUREG/CR-6260 that are applicable

to an older-vintage BWR plant for effect of the environment on the fatigue life of the

components. 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
4-30

steels, and those 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. These calculations showed that two locations were projected to exceed the CUF

limiting value of 1.0 prior to the end of the period of extended operation. In accordance with

10 CFR 54.21(c)(1)(iii), the applicant committed to track all necessary plant transients, using

the BFN Fatigue Monitoring Program, to ensure that the CUF values will remain below 1.0 for

the period of extended operation. For those locations where the CUF is expected to exceed 1.0

for the 60-year period, the applicant stated that additional analyses will be performed prior to

the period of extended operation, and appropriate action will be taken if the end-of-life CUF

values are projected to be above 1.0. 

The staff found the environmental fatigue effects assessment acceptable, since this evaluation

is consistent with the recommendations in SRP-LR Section 4.3.2.2 for addressing the effects of

the reactor coolant environment by assessing the effects on a sample of critical components.

The staff also found acceptable the applicant’s commitment to use the Fatigue Monitoring

Program to assure that the CUFs at the critical locations will not exceed the limiting CUF value

of 1.0 during the period of extended operation, in accordance with 10 CFR 54.21(c)(1)(iii). 

In accordance with 10 CFR 54.21(d), the applicant included a section addressing the effects of

reactor coolant environment on fatigue life of components and piping (Issue 190) in LRA

Section A.3.2.4. The applicant committed to include the locations that have projected CUF

values greater than 1.0 in the Fatigue Monitoring Program. The staff found this supplement

acceptable because it provides a reasonable summary of the information presented in LRA

Section 4.3.4.

4.3.4.3 UFSAR Supplement

As required by 10 CFR 54.21(d), applicants for license renewal must include a UFSAR

supplement summary description of the “programs and activities for managing the effects of

aging and the evaluation of TLAA for the period of extended operation.” The applicant provided

a UFSAR supplement summary description of GSI 190 in LRA Section A.3.2.4. On the basis of

its review, the staff concluded that the UFSAR supplement summary adequately describes the

TLAA on GSI 190 and is, therefore, acceptable.

4.3.4.4 Conclusion

The staff reviewed the applicant’s TLAA on GSI 190, as summarized in LRA Section 4.3.4, and

determined that the metal fatigue assessments at BFN Units 1, 2, and 3 will continue to comply

with the staff’s requirements throughout the period of extended operation. The staff therefore

concluded that the applicant’s TLAA for GSI 190 meets the requirements of

10 CFR 54.21(c)(1)(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 UFSAR supplement contains an

appropriate summary description of the TLAA on GSI 190 for the period of extended operation,

as required by 10 CFR 54.21(d).
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4.4 Environmental Qualification

The 10 CFR 50.49 Environmental Qualification (EQ) Program has been identified as a TLAA for

the purposes of license renewal. The TLAA of EQ electrical components includes all long-lived,

passive and active electrical and instrumentation and controls (I&C) components that are

important to safety and located in a harsh environment. The harsh environments of the plant

are those areas that are subjected to the environmental effects of a LOCA or a high-energy line

break (HELB). The EQ equipment comprises SR and Q-list equipment; nonsafety-related

(NSR) equipment, the failure of which could prevent satisfactory accomplishment of any SR

function; and necessary post-accident monitoring equipment.

As required by 10 CFR54.21(c)(1), the applicant must provide a list of EQ TLAAs in the LRA.

The applicant shall demonstrate that one of the following is true for each type of EQ equipment:

(1) the analyses remain valid for the period of extended operation; (2) the analyses have been

projected to the end of the period of extended operation; or (3) the effect of aging on the

intended function(s) will be adequately managed for the period of extended operation.

4.4.1 Summary of Technical Information in the Application

The EQ Program for Units 2 and 3 was established to verify that all plant equipment within the

scope of 10 CFR 50.49 is qualified for its application and meets its specified performance

requirements when subjected to the conditions predicted to be present when it must perform its

safety function up to the end of its qualified life. The EQ Program for Unit 1 will be established

to ensure compliance with 10 CFR 50.49. The EQ Program complies with the requirements of

10 CFR 50.49(e)(5) for aging considerations that affect functionality and make provisions to

replace the components or establish ongoing qualification when the demonstrated qualified life

has expired. The EQ-related equipment is identified in a controlled equipment data base with a

qualification binder that is maintained with records on performance specifications, electrical

characteristics, and environmental conditions.

The EQ Program manages thermal, radiation and cyclic aging as applicable for all electrical

components within the scope of 10 CFR 50.49. Compliance with 10 CFR 50.49 provides

evidence that the component will perform its intended functions during and after a DBE after

experiencing the effects of in-service aging. 

The applicant chose Option (iii) of 10 CFR 54.21(c)(1) in its TLAA evaluation to demonstrate

that aging effects of the EQ equipment identified in this TLAA will be managed during the

period of extended operation by the EQ Program activities. Maintaining qualification through the

extended license renewal period requires that existing EQ evaluations be reanalyzed. A

summary of the applicant’s application of these 10 CFR 50.49(f) methodologies to the EQ

evaluations for the period of extended operations follows:

Analytical Methods - The analytical models used in the re-analysis of an aging

evaluation are the same as those applied during the initial qualification. The Arrhenius

methodology is an acceptable thermal model for performing an aging evaluation. The

analytical method used for a radiation aging evaluation is to demonstrate 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
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establishing the 60-year normal radiation dose is to multiply the 40-year normal radiation

dose by 1.5 (i.e., 60 years/40 years). The result is added to the accident radiation dose

to obtain the total integrated dose for the component. Cyclical aging will be reevaluated

for those components subject to this effect.

Data Collection and Reduction Methods - Reducing excess conservatism in the service

conditions used in the aging evaluation is one method that can be used in a re-analysis.

Evaluations based on actual plant temperature data will, in certain cases, yield desired

results for extended service life. Should the applicant opt to use this approach, plant

temperature data can be obtained in several ways, including plant monitors,

measurements taken by plant personnel, and temperature sensors on various plant

equipment. Similar methods of reducing excess conservatism in the component service

conditions may be also be used for radiation and cyclical aging.

Underlying Assumptions - Environmental excursions identified during plant operation or

maintenance activities that could affect the qualification of an EQ component will be

evaluated. Should unexpected adverse conditions be identified, the affected EQ

component is evaluated and appropriate corrective actions taken, which may include

changes to the qualification basis and conclusions reached, or restructuring of the

affected component’s EQ requirements.

Acceptance Criteria and Corrective Actions - If the qualification cannot be extended by

re-analysis using the above methodologies, the component will be refurbished, replaced,

or requalified prior to exceeding the period for which the current qualification remains

valid. 

The applicant stated that the 10 CFR 50.49 EQ Program is consistent with the guidance

provided for resolution in the NRC Regulatory Issue Summary 2003-09, “Environmental

Qualification of Low-Voltage Instrumentation and Control Cables.” The regulatory issue

summary states:

For license renewal, a re-analysis (based on the Arrhenius methodology) to extend the

life of the cables by using the available margin based on a knowledge of the actual

operating environment compared to the qualification environment, coupled with

observations of the condition of the cables during walk-downs, was found to be an

acceptable approach. Monitoring I&C cable condition could provide the basis for

extending cable life.

The EQ Program allows re-analysis for maintaining qualification using the methods described

above. In addition, the EQ Program has the following procedural requirements in place to

monitor and track aging effects.

 • Detecting degradation of materials or equipment performance by requiring preventive

maintenance and periodic surveillance.

 • Failure trend evaluations related to equipment and environments.

 • Notification of environmental excursions and subsequent evaluation of components.

 • Review of licensing, industry, and other generic industry operating experience.
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4.4.2 Staff Evaluation

A site-wide EQ Program required by 10 CFR 50.49 has been developed for BFN, and

implemented on Units 2 and 3, and it is expected to be implemented on Unit 1 to ensure

compliance with 10 CFR 50.49. This item is discussed in SER Section 2.6.1.4.

The staff’s review of LRA Section 4.4 identified areas in which additional information was

necessary to complete the review of the EQ evaluation. The applicant responded to the staff’s

RAI as discussed below.

In RAI 4.4-2, dated November 4, 2004, the staff stated that the provisions of 10 CFR 50,

Appendix A, General Design Criteria (GDC) 4 require that all equipment (electrical and

mechanical) related to safety be designed to accommodate the environmental effects of

postulated accidents. Similarly, Standard Review Plan (SRP) 3.11 (NUREG-0800) applies

equally to mechanical and electrical equipment. Therefore, the staff requested the applicant to

provide a discussion of the materials for mechanical equipment in the LRA that are required to

be evaluated as an EQ TLAA that are sensitive to environmental effects (e.g., seals, gaskets,

lubricants, fluids for hydraulic systems, diaphragms, and wear cycle aging from lubricant

deterioration) and the aging analyses that will be, or have been, conducted to satisfy the

requirements of 10 CFR 54.21(c)(1) for the period of extended operation. 

In its response, by letter December 20, 2004, the applicant stated that BFN was licensed before

the establishment of NRC GDC-4, “Environmental and Dynamic Effects of Design Basis,” and

NUREG-0800. Consequently, neither GDC-4 nor SRP 3.11 are part of BFN’s CLB. Therefore,

the applicant does not have a formal mechanical equipment qualification program. As part of

the application review process, the applicant performed searches of Industry Guidance

(SRP-LR and NEI 95-10), the UFSAR, the Operating Licenses and License Conditions,

Technical Specifications, Technical Requirements Manuals, and Licensing Basis Program

Documents such as In-Service Inspection and EQ for possible TLAA’s. For the type of

mechanical equipment described above, the only TLAA found was “Dose to Seal Rings for the

High Pressure Coolant Injection and Reactor Core Isolation Cooling Containment Isolation

Check Valves,” SER Section 4.7.3. On the basis of its review, the staff found that the applicant

had adequately addressed the concern and the issue is resolved.

In RAI 4.4-1, dated November 4, 2004, the staff requested the applicant to provide a list of

components covered under EQ TLAA. In its response, by letter December, 9, 2004, the

applicant provided the list of components covered under the EQ TLAA. On the basis of its

review, the staff found that the applicant had adequately addressed the concern and the issue

is closed.

The staff reviewed the information in LRA Section 4.4 to determine whether the applicant

demonstrated that the effects of aging on the intended function(s) of electrical components will

be adequately managed through its existing EQ Program, together with other plant

programs/processes, during the period of extended operation as required by

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

The applicant’s program activities establish, demonstrate, and document the level of

qualification, qualified configuration, maintenance, surveillance, and replacement requirements
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necessary to meet 10 CFR 50.49. Qualified life is determined for equipment within the scope of

the EQ Program and appropriate actions, 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. 

On the basis of its review, the staff concluded that the applicant had addressed the issues

associated with GSI-168. The applicant will continue to manage the effects of aging through the

EQ Program for the period of extended operation. The staff found that the applicant had

satisfactorily addressed GSI-168 for license renewal, as required by 10 CFR 54.21(c)(1)(iii).

The staff issued Regulatory Issue Summary (RIS) 2003-09 on May 2, 2003, to inform

addressees of the results of the technical assessment of GSI-168. This RIS requires no action

on the part of the addressees. Therefore, the staff considers GSI-168 issue to be resolved. 

4.4.3 UFSAR Supplement

As required by 10 CFR 54.21(d), applicants for license renewal must include a UFSAR

supplement summary description of the “programs and activities for managing the effects of

aging and the evaluation of the TLAA for the period of extended operation.” The applicant

provided a UFSAR supplement summary description of EQ in LRA A.3.3. On the basis of its

review, the staff concluded that the UFSAR supplement summary adequately describes the

TLAA on EQ and is, therefore, acceptable.

4.4.4 Conclusion

On the basis of its review, the staff concluded that the applicant demonstrated that the effect of

aging on the intended function(s) of electrical and I&C components will be adequately managed

for the period of extended operation by the existing EQ Program as required by

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

4.5 Loss of Prestress in Concrete Containment Tendons

The BFN containments do not have prestressed tendons. As such, this topic is not a TLAA

applicable for BFN.

4.6 Primary Containment Fatigue

Cyclic loads acting on the primary containment and the attached piping and components

include reactor building interior temperature variation during the heatup and cooldown of the

RCS, a postulated LOCA, annual outdoor temperature variations, thermal loads on containment

penetrations due to high-energy piping lines (such as steam and feedwater lines), seismic

loads, and pressurization due to periodic Type A integrated leak-rate tests.

Metal containment penetration sleeves (including dissimilar metal welds) and penetration

bellows may be designed in accordance with the requirements of Section III of the ASME Boiler

and Pressure Vessel Code. If a plant’s code of record requires a fatigue analysis, then this

analysis may be a TLAA and must be evaluated in accordance with 10 CFR 54.21(c)(1) to

ensure that the effects of aging on the intended functions of the containment sleeves and

bellows will be adequately managed for the period of extended operation.
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In LRA Section 4.6, the applicant referenced UFSAR Section C.5.1, which states that the

primary containment vessels for Units 1 and 2 were designed in accordance with the ASME

Code Section III 1965 Edition with Addenda up through Winter 1966. The primary containment

vessel for Unit 3 was designed in accordance with the ASME Code Section III1965 Edition with

Addenda up through Summer 1967. Subsequently, while performing large-scale testing for the

Mark III containment system and in-plant testing for the Mark I containment system, new

hydrodynamic loads were identified for the suppression chamber (also referred to as the torus),

that were not included in the original structural analyses. These additional loads result from

blowdown into the suppression chamber during a postulated LOCA, and from main steam relief

valve operation during plant transients. The results of structural analyses for BFN under these

effects were reported in the BFN Torus Integrity Long-Term Program Plant Unique Analysis

Report (PUAR). This program is described in UFSAR Section C.5.3. The applicant indicated

that modifications of the suppression chamber and the suppression chamber vents, including

the vent headers and downcomers, were required in order to re-establish the original design

safety margins. The safety margins for these components were determined based on the

allowable stresses stated in Subsection NE of the 1977 ASME Boiler and Pressure Vessel

Code, Section III, including Summer 1977 Addenda. 

As part of the review of the Torus Integrity Long-term Program PUAR, the applicant identified

the following fatigue analyses as TLAAs:

 • fatigue of the torus, vents, and downcomers

 • fatigue of torus-attached piping and safety relief valve discharge lines

 • fatigue of vent line and process penetration bellows

In analyzing and determining the disposition of these TLAAs for the period of extended

operation, the applicant applied the following criteria:

 1. The applicant stated that locations with a 40-year CUF of 0.666 are not considered as

having adequate analytical or event margin when linearly extrapolated to 60 years. A

CUF limit of 0.4 was chosen as providing this margin. Disposition option

10 CFR 54.21(c)(1)(i) was therefore applied to locations with a calculated 40-year CUF

less than 0.4. 

 2. For locations where the 40-year CUF is greater than 0.4, the applicant stated that

fatigue will be managed by the Fatigue Monitoring Program described in LRA

Section B.3.2. Disposition option 10 CFR 54.21(c)(1)(iii) will, therefore, be applied to

these locations.

4.6.1 Fatigue of Suppression Chamber, Vents, and Downcomers

4.6.1.1 Summary of Technical Information in the Application

The applicant stated that the BFN Torus Integrity PUAR includes fatigue analyses of the torus

and torus vents, including the vent headers and downcomers. These analyses assumed a

limited number of main steam safety relief valve (SRV) actuations and are, therefore, TLAAs.

Based on recorded plant data extrapolated to 40 years, the BFN Torus Integrity PUAR

assumed 500 SRV actuations during 40 years of normal operations and the contribution from
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the postulated worst-case LOCA. The worst-location and the corresponding fatigue CUFs were

determined as follows: 

 • 0.681, at the intersection of the vent headers with the downcomers 

 • 0.373, at the downcomer/tiebar intersection 

 • 0.37, for the torus restraint snubbers

Since only the SRV loads contribute to fatigue during normal operation, normal operation may

continue so long as the CUF contribution from SRV actuations has not exceeded 1.0 minus the

CUF contribution expected from the postulated worst-case LOCA phenomena.

The applicant indicated that, based on operating experience, the total number of SRV

actuations is not expected to exceed 500 actuations for any unit during the period of extended

operation. This expectation is based on an estimate of the total number of SRV actuations

expected for each unit until the end of the period of extended operation. The applicant

described the methodology used for estimating the total number of SRV actuations. It was

based on estimating the number of SRV actuations from the start up of each unit through

August 2003, an estimate of the number of valve actuations expected for the remainder of the

current licensing term and for the requested period of extended operation. 

The applicant stated that, based on this methodology, the number of SRV actuations from the

startup of each unit through August 2003 was estimated to be 146 actuations for Unit 1, 254

actuations for Unit 2 (worst case), and 188 actuations for Unit 3. (These estimates included

both planned and unplanned SRV actuations.) The estimated total number of SRV actuations

from August 2003 until the end of the period of extended operation was projected to be 239 for

Unit 2. Thus, the estimated total number of SRV actuations at the end of the period of extended

operation for Unit 2 is 493. This is the worst-case estimate of the total number of SRV

actuations expected at the end of the period of extended operation. Thus, the assumed number

of 500 SRV actuations for the three units is considered to be conservative. 

To ensure that corrective actions are taken before any CUF approaches 1.0, the applicant

indicated that, in accordance with 10 CFR 54.3(c)(1)(iii), the applicant will manage the high CUF

locations for the period of extended operation by monitoring the SRV actuations using the

Fatigue Monitoring Program.

 

4.6.1.2 Staff Evaluation

The staff reviewed the LRA regarding the fatigue TLAAs of the torus, vents and downcomers.

The staff also reviewed the applicant’s disposition of these TLAAs and found it acceptable

because it specified the threshold limit of CUF equals 0.4 for 40 years of operation as a

criterion for determining if the fatigue analyses performed under the PUAR will remain valid for

the period of extended operation. The staff concurred with the applicant that this criterion will

provide additional analytical or event margin over the minimum CUF value of 0.666 for the

period of extended operation. Those locations, by not exceeding the threshold criterion, will

therefore remain valid for the period of extended operation, in accordance with

10 CFR 54.21(c)(1)(i). In accordance with 10 CFR 54.21(c)(1)(iii), for locations where the CUF

exceeds the criterion above, the staff found the applicant’s commitment to manage the effects

of fatigue for the period of extended operation with the Fatigue Monitoring Program acceptable
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because it will provide assurance that the monitored CUF at a location will not exceed the

ASME Code Section III CUF limiting value of 1.0; or, if the CUF is projected to exceed this limit,

the applicant committed to take appropriate corrective action to assure that this limit will not be

exceeded, as stated in LRA Section 4.6, in accordance with the Fatigue Monitoring Program.

As described in LRA Section B.3.2, the Fatigue Monitoring Program will include an

enhancement to monitor the fatigue of the torus and torus vents, and the vent headers and

downcomers, using an EPRI-licensed cycle counting and fatigue usage tracking computer

program. The applicant also committed to implement this enhancement prior to the period of

extended operation. 

In accordance with 10 CFR 54.21(d), the applicant’s supplement for the UFSARs regarding the

suppression chamber, vents, and downcomers fatigue TLAAs is provided in LRA Section A.3.4

“Containment Fatigue.” The staff reviewed this supplement and found it acceptable because it

provides a reasonable summary of the information presented in LRA Section 4.6.1.

4.6.1.3 UFSAR Supplement

As required by 10 CFR 54.21(d), applicants for license renewal must include a UFSAR

supplement summary description of the “programs and activities for managing the effects of

aging and the evaluation of TLAA for the period of extended operation.” The applicant provided

a UFSAR supplement summary description of metal fatigue analyses of suppression chamber,

vents, and downcomers in LRA Section A.3.4.

4.6.1.4 Conclusion

On the basis of its review, the staff concluded that the UFSAR supplement summary

adequately describes the metal fatigue TLAAs of suppression chamber, vents, and

downcomers and is, therefore, acceptable.

4.6.2 Fatigue of Torus Attached Pipe and Safety Relief Valve Discharge Lines

4.6.2.1 Summary of Technical Information in the Application

In LRA Section 4.6.2, the applicant stated that there are thirteen Target Rock dual-mode

MSRVs to allow blowdown from the main steam piping in the drywell to the suppression pool via

individual discharge lines passing through the main vents. These lines enter the suppression

chamber through penetrations in the suppression chamber vent header and the steam is

discharged to the suppression pool water through T-quenchers attached to the ends of the

lines. There are, in addition, a number of other external piping systems attached to the

suppression chamber shell.

The torus integrity PUAR indicates that an evaluation of the fatigue effects of Mark I

containment cyclic “new loads” on main steam relief valve discharge lines internal to the

suppression chamber and on torus-attached piping external to the suppression chamber was

performed using a program developed by the Mark I Owners Group. 

The fatigue analyses assumed 500 SRV actuations for a 40-year plant lifetime, and included

the effects of both mechanical and thermal expansion load cycling. These analyses are,
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therefore TLAAs. The analyses concluded that the worst location on the main steam safety

relief valve (MSRV) discharge lines would have a fatigue CUF of less than 0.35 at the end of 40

years of operation. The analyses also concluded that the worst location on the torus attached

piping would have a fatigue CUF of less than 0.103 at the end of 40 years of operation. The

applicant concluded that, for the MSRV discharge lines and T-quenchers, the MSRV discharge

line penetrations, the torus attached piping systems, and the associated penetration locations,

the predicted 60-year CUF will, therefore be less than 0.666 (worst-case CUF is 0.35 x 60/40 =

0.53). The applicant thus concluded that the MSRV discharge lines and the torus-attached

piping fatigue analyses will remain valid for the period of extended operation, in accordance

with 10 CFR 54.21(c)(1)(i).

4.6.2.2 Staff Evaluation

The staff reviewed the technical information in LRA Section 4.6.2 regarding the fatigue TLAAs

of the torus attached piping and the SRV discharge lines. The staff reviewed the applicant’s

disposition of these TLAAs and found it acceptable because the applicant selected a threshold

limit of CUF equals 0.4 for 40 years of operation as a criterion for determining whether the

fatigue analyses performed under the PUARs will remain valid for the period of extended

operation. Based on this criterion, the staff concurred with the applicant’s disposition of these

TLAAs, since it demonstrated that the highest 40-year CUFs will not exceed the threshold limit

of 0.40. These locations will therefore remain valid for the period of extended operation, in

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

In accordance with 10 CFR 54.21(d), the applicant’s supplement for the UFSARs regarding the

fatigue TLAAs of the torus attached piping and the SRV discharge lines is provided as part of

LRA Section A.3.4. The staff reviewed this supplement and found it acceptable because it

provides a reasonable summary of the information presented in LRA Section 4.6.2.

4.6.2.3 UFSAR Supplement

As required by 10 CFR 54.21(d), applicants for license renewal must include a UFSAR

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 a UFSAR supplement summary description of fatigue of torus attached

pipe and SRV discharge lines in LRA Section A.3.4.

4.6.2.4 Conclusion

On the basis of its review, the staff concluded that the UFSAR supplement summary

adequately describes the metal fatigue TLAA of torus attached pipe and SRV discharge lines

and is, therefore, acceptable.

4.6.3 Fatigue of Vent Line and Process Penetration Bellows

4.6.3.1 Summary of Technical Information in the Application

The applicant stated in LRA Section 4.6.3 that the torus vent line bellows are flexible expansion

joints allowing movement of the main vent pipes through the torus wall without developing
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significant interaction loads, and maintaining the required pressure boundary. The analysis of

the suppression chamber bellows is described in the PUAR and was performed in accordance

with Standards of the Expansion Joint Manufacturers Association, Inc. The design life of the

bellows is stated in UFSAR Section C.5.2 as 7000 thermal cycles over the 40-year life for the

plant and the fatigue analyses are, therefore, TLAAs.

Containment pipe penetrations that must accommodate pipe thermal movement also have

expansion bellows. Containment process piping expansion joints between the drywell shell

penetrations and process piping are the only ones subject to significant thermal expansion and

contraction. The design life of these bellows is also stated as 7000 operating thermal cycles

over the design life at containment normal, test, and limiting design pressures throughout the

40-year life for the plant and are, therefore, TLAAs.

For the suppression chamber vent line bellows and the containment penetration bellows,

thermal cycles are imposed by the thermal expansion cycles experienced by the attached

piping. The assumed thermal cycle count for the analyses used in the codes associated with

the piping and components can be conservatively approximated by the full thermal cycles (not

including power reductions) used in the reactor vessel fatigue analysis listed in UFSAR

Section 4.2.5. The applicant stated that the total count of all full thermal cycles (not including

power reductions) is less than 1100 for a 40-year plant life. For the 60-year plant life, the

number of thermal cycles for piping analyses would be proportionally increased to less than

1650, which is less than 25 percent of the 7000-cycle design life.

Since the suppression chamber bellows and the containment penetration bellows metal fatigue

analyses have a large design fatigue life margin, the applicant concluded that the analyses will

remain valid for the period of extended operation, in accordance with 10 CFR 54.21(c)(1)(i).

4.6.3.2 Staff Evaluation

The staff reviewed the technical information in LRA Section 4.6.3 regarding the metal fatigue

TLAAs of the vent line bellows and the containment process piping penetration bellows. The

staff concurred with the applicant’s disposition of this TLAA and found it acceptable because it

demonstrated, in accordance with 10 CFR 54.21(c)(1)(i), that the number of full thermal cycles

expected by the end of the period of extended operation will not exceed the 7000-cycle

design-life of these bellows.

In accordance with 10 CFR 54.21(d), the applicant’s supplement for the UFSAR regarding the

metal fatigue TLAAs of the vent line and process penetration bellows is provided in LRA

Section A.3.4. The staff reviewed this supplement and found it acceptable. It provides a

reasonable summary of the information presented in LRA Section 4.6.3.

4.6.3.3 UFSAR Supplement

As required by 10 CFR 54.21(d), applicants for license renewal must include a UFSAR

supplement summary description of the “programs and activities for managing the effects of

aging and the evaluation of TLAA for the period of extended operation.” The applicant provided

a UFSAR supplement summary description of metal fatigue analyses of vent line and process

penetration bellows in LRA Section A.3.4.
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4.6.3.4 Conclusion

On the basis of its review, the staff concluded that the UFSAR supplement summary

adequately describes the metal fatigue TLAAs of vent line and process penetration bellows and

is, therefore, acceptable.

4.7 Other Plant-Specific Analyses

In LRA Section 4.7, the applicant provided its evaluation of plant-specific TLAAs. The TLAAs

evaluated include the following:

 • reactor building crane load cycles

 • corrosion – flow reduction

 • dose to seal rings for the high pressure coolant injection and reactor core isolation

cooling containment isolation check valves

 • radiation degradation of drywell expansion gap foam

 • corrosion – minimum wall thickness

 • irradiation assisted stress corrosion cracking of reactor vessel internals

 • stress relaxation of core plate hold-down bolts

 • emergency equipment cooling water weld flaw evaluation

4.7.1 Reactor Building Crane Load Cycles

4.7.1.1 Summary of Technical Information in the Application

The applicant stated in Section 4.7.1 that the 125-ton reactor building overhead crane serves

three reactor units and includes a 5-ton auxiliary load hoist. The crane is designed to meet the

design loading requirements of the Crane Manufacturers Association of America (CMAA)

Specification 70. For cyclic loading, CMAA 70 specifies that a crane classified as Service Class

A1 is limited to 100,000 loading cycles over the design life. The applicant’s analysis identifies

that the total number of expected cycles for this crane over the entire life including construction,

the 60-years of operation for all three units, and the decommissioning, has been conservatively

estimated at less than 21,00 loading cycles. Of these, less than 1000 lifts are expected to be

more than 90 percent of the rated capacity. The applicant concluded that the analysis of the

125-ton reactor building crane qualifies the passive structural components for extended life in

accordance with CMAA 70 Service Class A1 requirements.

4.7.1.2 Staff Evaluation

During its review of the applicant’s analysis the staff determined that additional information was

needed to complete its review. The staff identified that TVA letter dated September 28, 1982, in

response to NUREG-0612, stated that the structural and rotating parts of the crane were

designed for infinite life. In RAI 4.7.1-1, the applicant was requested to clarify if infinite life is still

valid or to explain the derivation of the total number of loading cycles estimated. In this RAI, the

applicant was also requested to explain the difference between the 21,000 cycles estimated in
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LRA Section 4.7.1 and the 7,500 cycles estimated in LRA Section B.2.1.20. Further, the

applicant was requested to clarify if additional loading cycles caused by vibration during crane

operation are considered in the analysis or are the basis for not including loading cycles

induced by vibration. By letter dated January 12, 2005, the applicant explained that its letter

dated September 28, 1982, is based on an endurance limit of 40 percent of the tensile strength

which, although reasonable, is not in accordance with CMMA 70; therefore, the results of the

evaluation for license renewal supercede the September 28, 1982, results provided to the NRC.

The applicant also clarified that the 7,500 lifts are full-load equivalent cycles, and that the

estimated load lifts are less than 1,000 near-rated lifts, less than 10,000 moderate-load lifts,

and less than 10,000 light-load lifts. In regard to vibration, the applicant’s response clarified that

a review of operating experience indicates that vibration in the structural components has not

been noticed or reported for the reactor building crane. The applicant identified that

non-structural vibration and wear issues have been reported. For example, motor generator

vibration has been reported, measured, and promptly corrected. The staff determined that the

applicant’s response satisfactorily answers the staff’s technical concerns, and all items related

to RAI 4.7.1-1 are resolved.

Based on its review of the applicant’s analysis included in the LRA and additional clarifications

provided by the applicant in response to RAI 4.7.1-1, the staff concurred with the applicant that

the reactor building crane has been evaluated and is qualified for the period of extended

operation. The crane is qualified for a 100,000-cycle design life, which exceeds the estimated

load cycles for the life of the crane including life extension. Hence counting actual load cycle is

is not required for the reactor building crane because estimated load cycles are well below the

limits for the crane established by CMAA 70. Therefore, fatigue life is not significant to the

operation of this equipment, and the analysis is valid for the period of extended operation. The

applicant provided a satisfactory validation of 10 CFR 54.21(c)(1)(i). The staff also reviewed the

UFSAR Supplement A.3.5.1 and determined that the UFSAR Supplement includes an

appropriate summary description of the reactor building crane load cycles TLAA evaluation for

the period of extended operation, as required by 10 CFR 54.21(d).

4.7.1.3 UFSAR Supplement

As required by 10 CFR 54.21(d), applicants for license renewal must include a UFSAR

supplement summary description of the “programs and activities for managing the effects of

aging and the evaluation of TLAA for the period of extended operation.” The applicant provided

UFSAR supplement summary description of reactor building crane load cycles in LRA

Section A.3.5.1. On the basis of its review, the staff concluded that the UFSAR supplement

summary adequately describes the TLAA on reactor building crane load cycles and is,

therefore, acceptable.

4.7.1.4 Conclusion

On the basis of its review, the staff concluded that the applicant has provided an acceptable

demonstration, pursuant to 10 CFR 54.21(c)(1)(i) that the analyses remain valid for the reactor

building crane load cycles TLAA. The staff also concludes that the UFSAR supplement contains

an appropriate summary description of the reactor building crane load cycles TLAA evaluation

for the period of extended operation, as required by 10 CFR 54.21(d). Therefore, the staff has

reasonable assurance that the safety margins established and maintained during the current
4-42

operating term will be maintained during the period of extended operation, as required by

10 CFR 54.21 (c)(1).

4.7.2 Corrosion – Flow Reduction

LRA Section 4.7.2 originally considered a design calculation that addresses concerns whether

the flow reduction due to corrosion in carbon steel piping used in raw water systems is a TLAA.

In a letter dated June 15, 2005, the applicant provided additional information. The functional

basis for determining the acceptability is based on periodic flow testing as described in the

Technical Instruction 0-TI-171 RHRSW Sump Pump Flow Test, Surveillance Instruction

0-SI-4.5.C.1(4) EECW System Annual Flow Rate Test, Surveillance Instruction

1/2/3-SI-4.5.C.1(3) RHRSW Pump and Header Operability and Flow Test, and Surveillance

Instructions 0-SI-4.11.B.1.g for Fire Protection Piping. Based on its further review, the applicant

determined that the calculation should not be considered to be a TLAA; therefore, this section is

deleted from the application.

4.7.3 Dose to Seal Rings for the High Pressure Coolant Injection and Reactor Core

Isolation Cooling Containment Isolation Check Valves

Although this TLAA was included in the initial LRA, the applicant by its letter dated June 9,

2005, made a review of the safety determination per 10 CFR 54.3, and stated as follows:

LRA Section 4.7.3 originally considered a design calculation that determines the dose to

seal rings on the high-pressure coolant injection system and reactor core isolation

cooling system testable check valves to be a TLAA. After further review, the applicant

determined that the calculation is used to validate the seal design, but is not relied on to

make a safety determination. The ability of the valve to perform its safety function is

verified by Type C leak testing performed per BFN Technical Instruction 0-TI-360,

"Containment Leak Rate Programs." Based on this further review, the applicant

determined that the calculation should not be considered to be a TLAA, and that

Section 4.7.3, “Dose To Seal Rings For The High Pressure Coolant Injection And

Reactor Core Isolation Cooling Containment Isolation Check Valves,” should be deleted

from the LRA.

The staff concurred with the applicant’s assessment that this is not a TLAA and its

determination not to include it in the safety evaluation.

4.7.4 Radiation Degradation of Drywell Expansion Gap Foam

4.7.4.1 Summary of Technical Information in the Application

In LRA Section 4.7.4, the applicant stated that the steel drywell shell is enclosed in reinforced

concrete for shielding purposes and to provide additional resistance to deformation and

buckling of the drywell over areas where the concrete backs up the steel shell. The drywell is

separated from the reinforced concrete by a gap of approximately 2 inches and filled with

polyurethane foam. 
1TVA by letter dated January 7, 2005, agreed to decouple the power uprate licensing

request from License Renewal Application. The safety review of this item will be further

evaluated as part of the EPU review. 

4-43

4.7.4.2 Staff Evaluation

In RAI 4.7.4-1, dated December 10, 2004, the staff stated that LRA Table 3.5.2.2 lists the aging

management review (AMR) results of expansion joint (elastomer, polyurethane foam) as a

TLAA and refers the TLAA to LRA Section 4.7. LRA Section 4.7.4, “Radiation Degradation of

Drywell Expansion Gap Foam,” states that an analysis of the effect of dose on the foam

showed that the material properties will remain within the limits assumed by the original design

analysis for the additional 20 years of extended operation. Therefore, the staff requested the

applicant to provide a more detailed discussion of the analysis,1 including a discussion of the

method and assumptions adopted in the analysis, the type of data extrapolation applied, and

the quantitative results obtained to justify the applicant's assertion that the requirements of

10 CFR 54.21(c)(1)(i) are fully met.

In its response, by letter dated January 31, 2005, the applicant stated that:

The TLAA analysis determines that the total dose to the polyurethane foam located

between the drywell steel and the reactor building concrete will result in a total dose of

less than 1.0E8 rads. The material properties of the polyurethane foam will remain

within the limits assumed by the original analysis for a total dose of less than 1.0 E08

rads. 

The analysis model consists of the standard geometry sphere with a steel clad of 0.825

inches (drywell steel thickness). The radius of the sphere is 33.5 feet. Computer code

QAD-P5Z, which is a point kernel variation of QAD-P5F, was used to determine dose

and/or exposure rates. The computer code PARINT integrated the dose rates over time.

The principle gamma source from normal operation is N-16; therefore the photon

spectrum for normal operation is for N-16 with an arbitrary 1 Ci activity as input. The

resultant dose rate was then scaled to the appropriate power level. The STP computer

code determined the time dependent photon spectra. STP is the standard TVAN

computer code for source term development. Gamma and neutron attenuation are

considered.

Actual power conditions are utilized in the TLAA analysis. This applies for roughly the

first 25% of plant life during which time each unit was down for a significant amount of

time. For conservatism, it is assumed that EPU starts October 24, 2003, even though

Unit 1 has yet to be restarted. Prior to October 24, 2003, Units 2 and 3 are at 105%

(uprate) conditions. For an additional conservatism, Permali neutron shielding has not

been included in the TLAA analysis.

The foam will only receive the significant dose from the drywell. The drywell is

surrounded by a minimum of 5 feet of concrete. It is clear that the drywell sources will

have a greater impact than any sources in the reactor building. The reactor building

source impact will be negligible compared to the drywell. 
4-44

The maximum dose for 60 year operation at EPU conditions without Permali neutron

shielding occurs for Unit 2 and is 9.92E+07 which is less than a total dose of 1.0E08

rads used in the original analysis. Therefore, the material properties of the polyurethane

foam will remain within the limits assumed by the original analysis.

In addition, the staff requested the applicant to provide tests or other research publication

based justification for making the following assertion that: "The material properties of the

polyurethane foam will remain within the limits assumed by the original analysis for a total dose

of less than 1.0 E08 rads."

In its letter dated May 24, 2005, the applicant responded with the following:

The basis for asserting that the polyurethane foam will maintain its material properties

when exposed to radiation dosage is BFN UFSAR Section 5.2.3.2 which states in part

“... Irradiation tests have shown that no change in the resilient characteristics will take

place for exposures up to 10

8R.” This is in accordance with BFN’s current licensing

basis. Additionally, this same information is presented in Section 4.7.4, “Summary

Description,” of the LRA.

The staff found that the applicant provided adequate engineering analysis results and related

material test data to fully resolve the RAI. Therefore, the staff’s concern described in 

RAI 4.7.4-1 is resolved.

4.7.4.3 UFSAR Supplement

UFSAR Section 5.2.3.2 states that irradiation tests have shown that no change in the resilient

characteristics will take place for exposures up to 1.0x108 rads. This test-based material

performance data, in conjunction with the above-discussed TLAA analysis results, form the

basis for the staff’s determination that the effects of aging due to radiation degradation of

drywell expansion gap foam will be adequately managed. The applicant provided UFSAR

supplement summary description of drywell expansion gap foam in LRA Section A.3.5.3. On the

basis of its review, the staff concluded that the UFSAR supplement summary adequately

describes the TLAA in LRA Section 4.7.4, “Radiation Degradation of Drywell Expansion Gap

Foam.”

4.7.4.4 Conclusion

The staff reviewed the applicant’s TLAA on radiation degradation of drywell expansion gap

foam, as summarized in LRA Section 4.7.4, including information submitted in response to the

staff’s RAI and determined that the effects of aging due to radiation degradation of drywell

expansion gap foam will be adequately managed. Therefore, the staff concluded that the

applicant has demonstrated that the effects of aging due to radiation degradation of drywell

expansion gap foam 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(c)(1)(iii). 
4-45

4.7.5 Corrosion – Minimum Wall Thickness

Although this TLAA was included in the initial LRA, the applicant by its letter dated June 15,

2005, made a review of the safety determination per 10 CFR 54.3, and stated as follows:

LRA Section 4.7.5 originally considered a design calculation that shows corrosion/erosion

resulting in decreasing pipe wall thickness to be a TLAA. The functional basis for ensuring the

wall thickness acceptability is accomplished by inspection, testing, and monitoring activities

performed by plant procedures implementing SPP-9.7, Corrosion Control Program. Based on

its further review, the applicant determined that the calculation should not be considered a

TLAA; therefore, this section is deleted from the application.

The staff concurred with the applicant’s assessment that this is not a TLAA and with its

determination not to include in the safety evaluation.

4.7.6 Irradiation Assisted Stress Corrosion Cracking of Reactor Vessel Internals

4.7.6.1 Summary of Technical Information in the Application

The applicant in LRA Section 4.7.6 provided the following description for the TLAA on IASCC in

austenitic stainless steel RV internal components:

Austenitic stainless steel reactor internal components exposed to neutron fluence

greater than 5 x 1020 n/cm2 (E > 1 MeV) are considered susceptible to Irradiation

Assisted Stress Corrosion Cracking (IASCC) in the BWR environment. As described in

the SER (ML003776810, 12/07/2000) to BWRVIP-26, “BWR Top Guide Inspection and

Flaw Evaluation Guidelines,” IASCC of reactor internals is considered a TLAA. Fluence

calculations have been performed for the RV and internals. Four components have been

identified as being susceptible to IASCC for the period of extended operation: (1) Top

Guide; (2) Shroud; (3) Core Plate and (4) In-core Instrumentation Dry Tubes and Guide

Tubes.

The top guide, shroud, core plate and in-core instrumentation dry tubes and guide tubes

are considered susceptible to IASCC. The aging effect associated with IASCC, crack

initiation and growth, will require aging management. Three components, top guide,

shroud and incore instrumentation dry tubes and guide tubes, have been evaluated by

the BWRVIP, as described in the Inspection and Evaluation Guidelines for each

component: BWRVIP-26 (Top Guide), BWRVIP-76 (Shroud), and BWRVIP-47 (in-core

instrumentation dry tubes and guide tubes). BFN implements the BWRVIP

recommendations, as described in B.2.1.5 (Chemistry Control Program) and B.2.1.12

(BWR Vessel Internals Program). The core plate has been determined to be susceptible

to IASCC and this is considered a plant-specific TLAA. BFN will manage this TLAA with

two aging management programs: Chemistry Control Program (B.2.1.5) and BWR

Vessel Internals Program (B.2.1.12). For the period of extended operation, the BWR

Vessel Internals Program will perform inspections of the core plate in the regions of the

highest fluence.
4-46

4.7.6.2 Staff Evaluation

The staff reviewed the information provided by the applicant in the LRA and determined that the

austenitic stainless steel materials that are located in the following RV internal components are

exposed to neutron fluence greater than 5 x 1020 n/cm2 (E > 1 MeV) and are considered

susceptible to IASCC in the BWR environment: (1) top guide, (2) shroud, (3) core plate, and (4)

in-core instrumentation dry tubes and guide tubes. The applicant stated that the aging effects

due to IASCC in the aforementioned components are managed by two aging management

programs (AMPs): (1) Chemistry Control Program, and (2) Boiling Water Reactor Vessel

Internals Program. The Boiling Water Reactor Vessel Internals Program in turn addresses

several BWRVIP inspection programs that are designed for various RV internal components. In

addition, the Boiling Water Reactor Vessel Internals Program invokes the ASME Section XI

Subsections IWB, IWC, and IWD Inservice Inspection Program. The applicant claimed that

implementation of these AMPs provides reasonable assurance that the aging effects due to

IASCC will be managed so that the systems and components within the scope of this program

will continue to perform their intended functions, consistent with the CLB, for the period of

extended operation. The applicant committed to implement the relevant BWRVIP programs to

manage aging effects that are associated with each of the aforementioned components. The

staff, in the following paragraphs, discusses the effectiveness of these AMPs in managing the

aging effect due to IASCC in each of the aforementioned components.

Top Guide - In addition to the implementation of the Chemistry Control Program, and the

Boiling Water Reactor Vessel Internals Program, the applicant committed to invoke the

inspection guidelines that are specified in the BWRVIP-26, “Boiling Water Reactor Top Guide

Inspection and Flaw Evaluation Guidelines,” which has been approved by the staff. The

implementation of these additional guidelines and the AMPs is consistent with the GALL

AMP XI.M9. The staff found that, by implementing a proper chemistry program as dictated by

the Chemistry Control Program, the oxidizing nature of the RCS water can be controlled and,

thereby, the corrosion of the top guide can be controlled. 

In RAI B.2.1.12-1(A), dated December 1, 2004, the staff indicated that the BWRVIP-26 report

lists 5 x 1020 n/cm2 (E > 1.0 MeV) as the threshold fluence beyond which components may be

susceptible to IASCC. According to the generic analysis in BWRVIP-26, the location on the top

guide that will see a fluence equal to or greater than 5 x 1020 n/cm2 (E > 1.0 MeV) is the grid

beams. This is location 1, as identified in BWRVIP-26, Table 3-2, "Matrix of Inspection

Options.” In its evaluation of the top guide assembly in BWRVIP-26, GE assumed a lower

allowable stress value, acknowledging the high fluence value at this location. The conclusion of

GE’s analysis, and the fact that a single failure at this location has no safety consequence, was

that no inspection was necessary to manage IASCC in top guide grid beams.

The staff was concerned that multiple failures of the top guide grid beams are possible when

the threshold fluence for IASCC is exceeded. According to BWRVIP-26, multiple cracks have

been observed in top guide beams at Oyster Creek Nuclear Power station. In order to exclude

the top guide grid beams from inspection when their fluence exceeds the threshold value, it

must be demonstrated that failure of all beams that exceed the threshold fluence will not impact

the safe shutdown of the reactor during normal, upset, emergency, and faulted conditions. If

this cannot be demonstrated, then an inspection program to manage this aging effect to

preclude loss of component intended function is required. 
4-47

In its response, by letter dated January 31, 2005, the applicant indicated that LRA Section 4.7.6

considered the fluence at the top guide as a TLAA. The applicant manages this TLAA with the

Chemistry Control Program and the BWRVIP. The BWRVIP implements the requirements of

NRC-accepted BWRVIP-26. The NRC letter to Carl Terry, BWRVIP Chairman, dated June 10,

2003, states the following: “The staff believes that a comprehensive evaluation of the impact of

IASCC and multiple failures of the top guide beams is necessary, and that an inspection

program for top guide beams for all BWRs should be developed by the BWRVIP to ensure that

all BWRs can meet the requirements of 10 CFR Part 54 throughout the period of extended

operation.” The applicant made a commitment, as part of the BWRVIP, to work to resolve these

issues generically. When resolved, the applicant will follow the BWRVIP recommendations

resulting from that resolution. Prior to the period of extended operation, the applicant will

develop a site-specific inspection program, if necessary, to manage the effects of IASCC in the

top guide. 

The staff determined that the applicant was required to submit, for NRC review and approval, a

site-specific AMP that addresses potential multiple failures of the top guide grid beams. The

applicant, in its response dated May 25, 2005, indicated that it will perform inspections of the

guide beams similar (in inspection methods, scope and frequency of inspection) to the

inspections specified in the BWRVIP-47, “BWR Lower Plenum Inspection and Flaw Evaluation

Guidelines,” for the control rod guide tube components. The applicant stated that the extent of

examination and its frequency will be based on a ten percent sample of the total population,

which includes all grid beam and beam-to-beam crevice slots, within 12 years and five percent

of the population is to be completed within six years. The applicant stated that the program to

inspect the top guide grid beams will be implemented prior to the end of the current license

period. The sample locations selected for examination will be in areas that are exposed to

highest neutron fluence. The staff found this response acceptable because it defines a

representative population of IASCC susceptible locations, and selects locations in the top guide

that are exposed to the highest neutron fluences. In addition, the proposed inspection

requirements were previously accepted by the staff in the SE related to the license renewal of

Peach Bottom Atomic Power Station, Units 2 and 3. The staff considered this RAI resolved.

Core Shroud - In addition to the implementation of the ASME Section XI, Subsections IWB,

IWC, and IWD Inservice Inspection Program, Chemistry Control Program, and BWR Vessel

Internals Program, the applicant committed to implement the inspection guidelines of

BWRVIP-76 “Boiling Water Reactor Core Shroud Inspection and Flaw Evaluation Guidelines.”

The staff’s review of this report is not complete. The applicant proposed to evaluate the staff

SER and complete SER action items. The staff requested that the applicant make a

commitment to follow all the requirements and limitations that may be specified in the staff SE

on the BWRVIP-76 report. The staff found that, by implementing a proper chemistry program

as dictated by the Chemistry Control Program, the oxidizing nature of RCS water can be

controlled and, thereby, the corrosion of the core shroud can be controlled. In addition,

implementation of the Inservice Inspection Program mandated by ASME Section XI,

Subsections IWB, IWC, and IWD Inservice Inspection Program, and additional inspection

guidelines required by BWRVIP-76, will adequately identify any cracking in a timely manner so

that proper repair and other mitigation techniques can be implemented to restore the function of

the core shroud. Since the implementation of these additional guidelines and AMPs is

consistent with the GALL AMP XI.M9, and Table IV.B1.1-a through IV.B1.1-g, the staff found

that the applicant had demonstrated that the effects of aging will be adequately managed so
4-48

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).

In RAI 4.2.4-1(B), dated December 1, 2004, the staff stated that in LRA Section 4.2.4, the

applicant stated that the maximum 54 EFPY fluence at the inside surface of the core shroud is

5.34 x 1021 n/cm2 (E > 1.0 MeV). Therefore, the staff requested that the applicant address the

aging effect due to IASCC in the core shroud component.

In its response, by letter January 31, 2005, the applicant stated that the core shrouds are

classified as “Category C,” based on the core shroud classification criteria contained in

Appendix B of the BWR Vessel Internals Program. The BWR Vessel Internals Program

requires inspection of core shroud welds in accordance with “Category C” core shroud

inspection requirements contained in BWRVIP-76. The staff reviewed this response and

accepted it (pending the approval of the BWRVIP-76 report) because implementation of the

BWR Vessel Internals Program and the Chemistry Control Program would adequately manage

the aging effect due to IASCC in the core shroud components and is consistent with GALL

AMP XI.M9 and XI.M2. 

Core Plate - The applicant proposed to implement the ASME Section XI, Subsections IWB,

IWC, and IWD Inservice Inspection Program, Chemistry Control Program, and BWR Vessel

Internals Program. The BWR Vessel Internals Program in turn invokes the inspection guidelines

of the BWRVIP-25, “Boiling Water Reactor Core Plate Inspection and Flaw Evaluation

Guidelines,” which has been approved by the staff. The staff found that by implementing a

proper chemistry program as dictated by the Chemistry Control Program, the oxidizing nature of

the RCS water can be controlled and, thereby, the corrosion of the core plate can be controlled.

In addition, implementation of the Inservice Inspection Program mandated by the ASME

Section XI, Subsections IWB, IWC, and IWD Inservice Inspection Program, and additional

inspection guidelines required by BWRVIP-25, will adequately identify any cracking in a timely

manner so that proper repair and other mitigation techniques can be implemented to restore the

function of the core plate. Since the implementation of these additional guidelines and AMPs is

consistent with the GALL AMP XI.M9, and Table IV.B1.1-a through IV.B1.1-g, 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).

In-core Instrumentation Dry Tubes and Guide Tubes - In addition to the implementation of the

ASME Section XI, Subsections IWB, IWC, and IWD Inservice Inspection Program, the

Chemistry Control Program, and BWR Vessel Internals Program, the applicant committed to

invoke the inspection guidelines specified in BWRVIP-47, “Boiling Water Reactor Lower

Plenum Inspection and Flaw Evaluation Guidelines,” which has been approved by the staff. The

staff found that by implementing a proper chemistry program as dictated by the Chemistry

Control Program, the oxidizing nature of the RCS water can be controlled and, thereby, the

corrosion of the in-core instrumentation dry tubes and guide tubes can be controlled. In

addition, implementation of the Inservice Inspection Program mandated by the ASME

Section XI, Subsections IWB, IWC, and IWD Inservice Inspection Program, and additional

inspection guidelines required by BWRVIP-47, will adequately identify any cracking in a timely

manner, so that proper repair and other mitigation techniques can be implemented to restore

the function of the in-core instrumentation dry tubes and guide tubes. Since the implementation

of these additional guidelines and AMPs is consistent with the GALL Report, the staff found that
4-49

the applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21(a)(3).

4.7.6.3 UFSAR Supplement

Section LRA A.3.5.5 includes the following UFSAR Supplement summary description for the

TLAA on IASCC of the RV internals.

Austenitic stainless steel RV internal components exposed to a neutron fluence greater

than 5 x 10

20 n/cm 2

(E > 1 MeV) are considered susceptible to irradiation assisted stress

corrosion cracking (IASCC) in the BWR environment. Fluence calculations have been

performed for the RV and internals. Four components have been identified as being

susceptible to IASCC for the period of extended operation: (1) Top Guide; (2) Shroud;

(3) Core Plate and (4) In-core Instrumentation Dry Tubes and Guide Tubes. Three

components (top guide, shroud and in-core instrumentation dry tubes and guide tubes)

have been evaluated by the BWRVIP, as described in the Inspection and Evaluation

Guidelines for each component: BWRVIP-26 (Top Guide), BWRVIP-76 (Shroud), and

BWRVIP-47 (incore instrumentation dry tubes and guide tubes). BFN implements the

BWRVIP recommendations. The Chemistry Program and the BWR Vessel Internals

Program will be used to manage the core plate.

The applicant’s UFSAR supplement summary description for the TLAA on IASCC of the RV

internals appropriately describes the implementation of relevant AMPs that would enable the

applicant to effectively manage this aging effect. The staff, however, requires that the applicant

revise the UFSAR supplement to indicate that the inspection guidelines of the BWRVIP-25

“Boiling Water Reactor Core Plate Inspection and Flaw Evaluation Guidelines,” will be

implemented to effectively manage the aging effect on core plate. The applicant, in its response

dated May 25, 2005, revised LRA Section A 3.5.5 of the UFSAR supplement summary

description which describes that the inspection guidelines that are specified in the BWRVIP-25

report will be implemented for managing the aging effect on core plate. The staff considered

this acceptable.

4.7.6.4 Conclusion

The staff reviewed the applicant’s TLAA on IASCC of the RV internals, as summarized in LRA

Section 4.7.6, and determined that, except for the top guide grid beams, the applicant

appropriately describes that by implementing the ASME Section XI, Subsections IWB, IWC,

and IWD Inservice Inspection Program, the Chemistry Control Program and BWR Vessel

Internals Program, and relevant additional BWRVIP guidelines related to RV internal

components, the aging effect due to IASCC will be adequately managed for the period of

extended operation. The license renewal action items related to the implementation of the

BWRVIP-25, BWRVIP-26, and BWRVIP-47 guidelines are discussed in SER Section 3.1 on

AMR. In addition, the staff believes that the implementation of these additional guidelines and

AMPs is consistent with the GALL AMP XI.M9, and Table IV.B1. Therefore, the staff concluded

that the applicant had demonstrated that the effects of aging due to IASCC in the RV internals

with the exception of the top guide grid beams, as stated above, 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(c)(1)(iii). 
4-50

4.7.7 Stress Relaxation of the Core Plate Hold-Down Bolts

4.7.7.1 Summary of Technical Information in the Application

The core plate hold-down bolts connecting the core plate to core shroud are initially preloaded

during installation. These bolts are subject to stress relaxation due to thermal and irradiation

effects. The loss of preload over time due to stress relaxation is considered a TLAA and

evaluated accordingly. In the LRA, the applicant stated that it evaluated the loss of preload of

the core plate hold-down bolts for the 40-year lifetime and concluded that all core plate

hold-down bolts will maintain some preload throughout the life of the plant. This conclusion was

based on an analysis of loss of preload for core plate hold-down bolts, referenced in

BWRVIP-25, Appendix B, "BWR Core Plate Inspection and Flaw Evaluation Guidelines."

(Reference 5). For the 60-year lifetime, the applicant estimated the expected loss of preload to

be less than 20 percent. With this loss of preload, the applicant stated that the core plate will

maintain sufficiently high preload at the end of the period of extended operation to prevent

sliding under both normal and accident conditions. Based on this assumption, the applicant

concluded that the loss of preload is acceptable for the period of extended operation, in

accordance with the requirements of 10 CFR 54.21(c)(1)(ii).

4.7.7.2 Staff Evaluation

To complete its review, the staff requested additional information regarding the data and

analyses that were used to determine that the loss of preload due to stress relaxation at the end

of the period of extended operation would be less than 20 percent. The staff also requested that

the applicant show that the hold-down bolts would meet the required ASME Code Section III

stress acceptance criteria at the end of the period of extended operation.

In RAI 4.7.7-1, dated March 3, 2005, the staff requested that the applicant demonstrate the

applicability of BWRVIP-25, (Reference 5) Appendix A, core plate hold-down bolt analysis to

the BFN units, based on the configuration and the geometry of the BFN core plate hold-down

bolts and the reactor environment (temperature and neutron fluence) assumed in the report. 

In its response, by letter dated May 31, 2005, the applicant stated that the BFN core plate

corresponds to that in BWRVIP-25, Figure 2-4, and that BFN was specifically considered in the

original BWRVIP-25 evaluation, incorporating typical values of temperature and fluence. An

analysis was initially performed for a 40-year plant life, and subsequently for a 60-year plant life,

as discussed in BWRVIP-25, Appendix B, paragraph B.4, which addressed license renewal.

This initial BWRVIP-25 based analysis assumed 20 percent hold-down bolt preload relaxation

over a 60-year plant life.

To address EPU conditions in conjunction with license renewal, the applicant stated that a

plant-specific calculation was performed for the BFN units. This calculation was based on the

BFN fluence calculation which was performed considering EPU operating power and time

conditions. The applicant stated that the applicable maximum bolt fluence was determined to be

5 x 1019 n/cm2 (E > 1MeV) at the end of the 60-year plant life. The resulting hold-down bolt load

relaxation was determined to be 15 percent, based on General Electric Nuclear Energy (GENE)

design documents.
4-51

The staff reviewed this response and concluded that additional information was needed to

complete its evaluation. The additional information was requested in the follow-up to RAI

4.7.7-1 which is discussed later. 

In RAI 4.7.7-2, dated March 3, 2005, the staff requested that the applicant:

 (a) Identify the temperature of the bolts during the normal operation and the projected bolt

neutron fluence at the end of the period of extended operation.

 (b) Explain how it was determined that the effects of temperature and neutron fluence result

in a 20 percent loss of preload.

 (c) Provide a detailed description of the methodology and data used at BFN to perform the

analysis as described in (b), and include the basis for the relaxation curves. 

In its response to RAI 4.7.7-2, dated May 31, 2005, the applicant responded as follows:

 (a) The normal operating temperature for the core plate bolts is 550 °F. For the BFN units,

the projected fluence was determined to be 5 x 1019 n/cm2 (E > 1MeV) for a 60-year

lifetime, (assuming a 90 percent capacity factor) for the bolt at the peak radial location.

The arrangement of the bolts around the periphery of the core plates assures that many

of the bolts experience a significantly lower lifetime fluence.

 (b) The plant-specific evaluation used GENE proprietary relaxation curves from a GENE

material design document for irradiated stainless steel properties at 550 °F, that was

developed in the1970s time frame. The document was based on a combination of

GENE internal reports and industry data to evaluate bolt stress relaxation.

 (c) The BFN calculation was performed based on the BFN-specific core plate geometry,

fluence and temperature. The BFN fluence conditions and the expected bolt stress

relaxation made use of either GENE methods or GENE design documents. In support of

the relaxation value used in the calculations, the applicant provided relaxation vs.

fluence data from BWRVIP-99, "Crack Growth Rates in Irradiated Stainless Steels In

BWR Internal Components." (Reference 6). This data was developed for type 316

stainless steel material, based on data found in the literature. The applicant justified the

application to type 304 stainless steel material on the basis that the two commercial

material alloys have the same single-phase austenitic microstructure and crystal

structure, with no precipitates present in either alloy, and the mechanical properties are

essentially identical at 550 °F.

The staff reviewed the information in this response and concluded that additional information

was needed to complete its evaluation. The additional information was requested in RAI 4.7.7-3

through 4.7.7-7 by letter dated June 22, 2005. 

In RAI 4.7.7-3, dated June 22, 2005, the staff requested that the applicant provide the data that

GENE used to develop the stress relaxation curves and explain how this data was utilized to

establish the curves.

In its response, by letter dated June 29, 2005, the applicant presented a mean design curve

developed by GENE using stress relaxation values of irradiated stainless steel materials. The

data was obtained from measurements made on springs and bent-beam specimens.
4-52

The staff's review of the applicant's response to RAI-4.7.7-3 is included in the staff's review of

RAI 4.7.7-4. 

In RAI 4.7.7-4, dated June 22, 3005, the staff stated that the applicant referenced BWRVIP-99

report, Figure 7-13, which shows data and modeling projections for stress relaxation versus

fluence values measured in displacements per atom (dpa) for 20 percent cold-worked type 316

stainless steel material. The staff requested that the applicant provide an explanation justifying

the applicability of the Type 316 stainless steel data to the Type 304 stainless steel core plate

hold-down bolts at the BFN units.

In its response, by letter dated June 29, 2005, the applicant stated that the stress relaxation

property of irradiated stainless steel materials does not vary with change in chemical

composition. To support this claim, the applicant provided Halden (in-situ tests in the Halden

reactor) data which show that there is very small variation in stress relaxation values between

Type 304, 316, and 348 stainless steel specimens. The stress relaxation data were obtained

from specimens that were exposed to 4.4 to 6 x 1020 n/cm2 (E > 1MeV) in 288 °C water. These

neutron fluence values are nearly 10 times higher than that of BFN core plate hold down bolts;

therefore, stress relaxation values for the BFN bolts will be less than the values that are

presented in the data. The applicant compared the Halden data with GENE data and concluded

that for a given neutron fluence value the corresponding stress relaxation value that is obtained

from the GENE data is more conservative than that from the Halden data. 

The staff reviewed the applicant's responses to RAIs 4.7.7-3 and 4.7.7-4 and concluded that

supporting data to the applicant's claim that the variation in chemical composition of stainless

steel materials has very little effect on the stress relaxation of the irradiated stainless steel

materials. Therefore, the staff concluded that the stress relaxation curves for the irradiated

Type 316 stainless steel material can be applicable to irradiated Type 304 stainless steel

materials. The staff reviewed the data in the applicant's response dated June 29, 2005, and

found that for a given neutron fluence value the corresponding stress relaxation value obtained

from GENE data is conservative and is acceptable. 

In RAI 4.7.7-5, dated June 22, 2005, the staff requested that the applicant provide the dpa

values for Type 304 core plate hold-down bolts that correspond to end-of-life fluence (54 EFPY)

using appropriate model for the BFN units.

The staff’s review of the applicant’s response to RAI 4.7.7-5 is included in the staff’s review of 

the follow-up to RAI 4.7.7-1. 

In RAI 4.7.7-6, dated June 22, 2005, the staff requested that the applicant provide justification

for the application of relaxation curves obtained based on data from torsion tests to axial

relaxation in bolts.

In its response, by letter dated June 29, 2005, the applicant stated that the GENE stress

relaxation data is obtained from test samples that include springs that represent torsional

loading, and bent-beam specimens that represent tension loading. The applicant presented

stress relaxation data that represented tension loading and another set representing shear

loading, and they both exhibit similar behavior as GENE stress relaxation curve, but at a lower

value. The data also indicated that the stress relaxation curve was not affected by the specimen
4-53

or type of loading. Therefore, the applicant concluded that the stress relaxation values that are

presented are applicable for torsional and axial loadings.

The staff reviewed the applicant's response and concluded that the stress relaxation curves and

the applicant's presented data on the stress relaxation values are applicable for torsional and

axial loadings.

In RAI 4.7.7-7, dated June 22, 2005, the staff requested that the applicant provide the

calculations referenced in Appendix B of BWRVIP-25 so that it can evaluate the stress

relaxation of the core plate hold-down bolts for the end-of-license fluence (54 EFPY) for the

BFN units.

In its response to RAIs 4.7.7-5 and 4.7.7-7, dated June 29, 2005, the applicant provided a

proprietary response in reply to the staff RAIs (ADAMS Accession No: ML052150189). In the

response the applicant stated that a plant-specific calculation was performed for the BFN units

using a neutron fluence value of 5 x 1019 n/cm2 (E > 1MeV) which is equivalent to 0.07

displacement damage (measured as dpa) at the peak fluence location. The dpa value is

calculated based on the calculated fast fluence and an effective dpa cross section (E > 1 MeV)

of approximately 1380 barns for steel. The GENE stress relaxation value for this neutron

fluence and dpa values is 15 percent, which is a conservative value, falls within the bounding

value of 20 percent that was specified in the BWRVIP-25 report. The staff's review of the

applicant's response to RAI-4.7.7-5 is included in the staff's review of the follow-up to

RAI 4.7.7-1.

The staff reviewed the information in the responses to RAI 4.7.7-3 through 4.7.7-7, and

concluded that additional information was needed to complete its evaluation. The additional

information was requested in follow-up to RAI 4.7.7-1 and 4.7.7-2 by letter dated August 2,

2005. 

In the follow-up to RAI 4.7.7-1, dated August 2, 2005, the staff indicated that in the data

provided by TVA in its submittal dated June 29, 2005, the applicant compared the stress

relaxation for the BFN core plate hold-down bolts to the stress relaxation data derived from

springs and stainless steel bent beam specimens. The staff requested that the applicant

provide information regarding the values of neutron flux and temperature at which the bent

beam and spring test specimens were exposed, and compare them to the neutron flux and

temperature values of the BFN core plate hold-down bolts. If these neutron flux and

temperature values are different from those for the spring and bent beam specimens, the staff

requested that the applicant evaluate the impact of these differences on the predicted stress

relaxation values of the BFN core plate hold-down bolts.

In its response to the follow-up to RAI 4.7.7-1, dated September 6, 2005, the applicant

addressed the effects of temperature and neutron flux on the stress relaxation values at which

the irradiation tests were conducted. In its response, the applicant stated that given the large

range of higher flux for which the properties are the same, the impact of the lower flux to which

the bolts are exposed is viewed to be negligible. In support, the applicant stated that the

temperature and fluxes associated with the design basis data are appropriate for use in

predicting stress relaxation in the BFN core plate bolts. The test data was all generated at

temperatures from 530 °F to 600 °F and, therefore, is fully representative of BWR operating

conditions. The nuclear spectrum is also similar to that for the core plate bolt region. While the
4-54

test data was generated at higher fluxes than present in the core plate region, the applicability

of the data for use in the core plate bolt assessment is supported by mechanistic understanding

as well as component test results. 

Since the temperatures at which the majority of the irradiation tests were conducted represent

the temperatures of the core plate hold-down bolts at the BFN units, the applicant claimed that

the stress relaxation data that was provided by GENE would be representative of the BFN core

plate hold-down bolts. The applicant further reiterated that the tests conducted at a neutron flux

value higher than that of the core plate hold down bolts can be applicable for evaluating the

stress relaxation data for the BFN's core plate hold-down bolts. 

The staff reviewed the applicant's responses to the aforementioned RAI and determined that

the applicant's justification for using the GENE methodology in the applicant’s response in

developing the stress relaxation curves is acceptable for the following reasons. GENE

developed the stress relaxation curve for irradiated austenitic stainless steel materials at

temperatures equivalent to the BWR normal operating temperatures and at a neutron fluence

value equivalent to 54 EFPY for the BFN units. The stress relaxation data demonstrates that

the impact of test temperature and neutron flux values for the test samples are not significant.

The stress relaxation curve indicates that the relaxation value for the neutron fluence equivalent

to 54 EFPY at the BFN units is 15 percent. The staff concluded that the stress relaxation value

of 15 percent is a conservative value and falls within the bounding value of 20 percent that was

provided in the generic analysis of the staff-approved BWRVIP-25 report.

In the follow-up to RAI 4.7.7-2, dated August 2, 2005, the staff requested that the applicant

show that, under design basis accident condition loading stated in Scenario 3 of BWRVIP-25,

Appendix A, the axial and bending stresses for the mean and highest loaded hold-down bolts

will not exceed the ASME Section III allowable stresses for Pm (primary membrane) and Pm + Pb

(primary membrane plus bending) as a result of a 20 percent reduction in the specified bolt

pre-load. The staff also requested that the applicant state clearly the assumptions on which the

analysis was based.

In its response to the follow-up RAI 4.7.7-2, dated September 6, 2005, the applicant indicated

that the BFN current licensing basis states that: "Two considerations important to the core

support evaluation are sliding of the core support and buckling of the supporting beams.

Evaluations have determined that the core support will not slide under postulated accident

conditions with preload on the hold-down bolts. Additional resistance to sliding is provided by

aligning pins which further stabilize the core support." The applicant also provided a

(proprietary) stress calculation of the hold-down bolts which demonstrated that the axial and

bending stresses met the stress criteria in BWRVIP-25, Appendix A.

The staff reviewed the applicant's response and identified the following concerns:

 • The analysis does not correspond to the plant-specific core plate/hold-down bolt

analysis recommended in Appendix A of BWRVIP-25. The applicant's analysis assumes

that the core plate is rigid. The recommended approach is based on an elastic finite

element analysis of the core plate/hold-down bolts. 

 • The applicant selected friction due to hold-down bolt preload as the means to prevent

sliding of the core plate under horizontal loading. BWRVIP-25 recommends the
4-55

installation of wedges to prevent sliding; it does not recommend high preload to induce

sufficient friction to prevent sliding. No basis for this choice was provided.

 • The analysis is based on stipulated high preload (including 20 percent relaxation) of the

hold-down bolts and a high static coefficient of friction to prevent sliding of the core plate

under accident basis horizontal loading. No basis was provided for this high static

coefficient of friction. Based on a comparison with values found in the literature, the

coefficient of friction used in the analysis is similar to that stipulated as friction between

dry metal surfaces. This value is not considered applicable to friction between the core

plate and its shroud support, which are immersed in a BWR hot water environment. The

staff believes that the static coefficient of friction in this environment is considerably

lower, similar to that for friction between lubricated metal surfaces. 

 • As a result of the assumed rigidity of the core plate and high coefficient of static friction,

and leading to the prevention of sliding under horizontal loading, the only stress state in

the hold-down bolts is axial, caused by the bolt pre-load and vertical loading on the core

plate. The core plate/hold-down bolt analysis in BWRVIP-25, Appendix A is based on

relatively low bolt pre-load and no friction. As a result, the core plate is restrained from

sliding by the hold-down bolts only, which induces bending stresses in the bolts. A low

coefficient of friction may show that core plate sliding under the horizontal loading may

not be prevented, thus inducing bending stresses in the hold-down bolts, in addition to

the axial stresses.

 • BWRVIP-25 indicates that "of special interest is the amount of bending induced in the

bolts when the core plate bows upward, or when load from the beams is no longer

transferred to the rim." This effect cannot be determined from the applicant's analysis if

the core plate is assumed rigid. 

 • The stipulated hold-down bolt preload in the applicant's analysis is considerably larger

that the preload in the analysis in BWRVIP-25, Appendix A. The effect of this preload on

the structural integrity of the core plate was not evaluated.

 • The finite element analysis of the core plate/hold-down bolts in Appendix A shows that

the axial and transverse bolt loads vary around the circumference of the core plate. The

axial loads in the highest loaded bolts are about twice the mean of the axial bolt loads.

The applicant's analysis, based on a rigid plate analysis, shows that all bolts are

uniformly loaded in tension and does not reflect the true distribution of the bolt loads.

 • BWRVIP-25 specifies the design basis accident loads that should be considered in a

plant-specific analysis. It is not clear that all applicable loads were considered in the

applicant's analysis.

Based on these concerns, the staff concluded that the applicant did not provide reasonable

assurance that the axial and bending stresses in the hold-down bolts will meet the ASME

Section III primary stress limits as stated in BWRVIP-25, Appendix A, under the BFN

plant-specific design basis accident loading and with 20 percent relaxation of hold-down bolt

preload. This was, therefore, identified by the staff as Open Item 4.7.7.

Follow-up teleconferences with the applicant were held on October 14 and 18, 2005, to address

the resolution of Open Item 4.7.7. This open item was included as one of four open items in an

interim evaluation by the Advisory Committee on Reactor Safeguards of BFN's license renewal

application and in the NRC's draft Safety Evaluation Report. By letter dated October 31, 2005,
4-56

the staff provided the applicant a summary and discussion of the teleconferences, in which the

staff position on this open item was summarized. The letter summarized the staff's concerns, as

follows:

The applicant did not use the staff-approved analysis that was used in BWRVIP-25 report for

the BFN units. The methodology used in the BWRVIP-25 report is more conservative. For BFN

units, the applicant used a less conservative methodology, such as using a high static

coefficient of friction value to ensure prevention of sliding of the core plate which eliminated the

bending stresses in the core plate hold-down bolts. The staff determined that the static

coefficient of friction used by the applicant is not supported by the available information

provided in the literature. 

The staff also questioned whether the applicant had considered using wedges to prevent core 

plate sliding, and if the wedges are installed, the aging management of core plate hold-down 

bolts will not be considered a TLAA item. The applicant stated that this option was evaluated

but it is costly to install wedges in each unit. This option was, therefore, withdrawn.

The staff identified and summarized the following concerns: 

 (1) The analysis is significantly different from the structural analysis in BWRVIP-25, and is

not based on a finite element model of the core plate. 

 (2) It is not clear that all loads listed in BWRVIP-25, such as fuel lift load, were included in

the analysis. 

 (3) The applicant selected friction due to high bolt preload (significantly larger than that

specified in BWRVIP-25) as the means to prevent side motion of the core plate.

BWRVIP-25 recommends the use of wedges to prevent side motion; it does not

recommend high bolt preload and friction.

 (4) The applicant analysis assumes a high static coefficient of dry friction as the mechanism

to prevent side motion of the core plate. The staff questions the basis for this

assumption for a core plate that is in a BWR water environment. 

 (5) BWRVIP-25, Appendix A, page 4-6 states that "of special interest is the amount of

bending induced in the bolts when the core plate bows upward, or when load from the

beams is no longer transferred to the rim." No such bending was evaluated in the

applicant's analysis. 

 (6) The BWRVIP-25 structural analysis shows a variation of the axial forces in the holddown bolts with location around the plate circumference, and that the axial force in the

highest-loaded bolt is about twice the mean axial bolt load. The applicant analysis shows

that all bolts are uniformly loaded in tension. This indicates that the highest stresses in

the hold-down bolts have not been determined. 

 (7) The effect of the large bolt preloads on the structural integrity of the core plate was not

evaluated.

The staff stated its position that, for the BFN units, the applicant should apply the

staff-approved methodology that was used in the BWRVIP-25 report.
4-57

By letter dated November 16, 2005, the applicant stated in Enclosures 3 and 9 the following

commitment for BFN for the core plate hold-down bolts:

The applicant will perform a BFN plant-specific analysis consistent with BWRVIP-25 to

demonstrate that the core plate hold-down bolts can withstand normal, upset, emergency, and

faulted loads, as applicable, considering the effects of stress relaxation until the end of the

period of extended operation. The installed core plate configuration and bolt preload will be

used for the plant-specific analysis. The analysis will use the plant-specific design basis loads

and load combinations. The analysis will incorporate detailed flux/fluence analyses and

improved stress relaxation correlations.

In accordance with BFN's CLB, the ASME Boiler and Pressure Code, Section III will be used as

a guide in determining limiting stress intensities for reactor vessel internals. For those

components for which stresses exceed the ASME Code allowables, either the elastic stability of

the structure or the resulting deformation or displacement will be examined to determine if the

safety design basis is satisfied. Appropriate corrective action will be taken if the plant-specific

analysis does not satisfy the above criteria. The installation of core plate wedges to eliminate

the need for the enhanced inspections of the core plate hold-down bolts as recommended by

BWRVIP-25 is considered an acceptable corrective action.

The analysis or the corrective action taken to resolve this issue will be submitted to the staff for

review two years prior to the period of extended operation.

The staff reviewed the applicant's commitment and concluded that it provides adequate

assurance that the 60-year stress relaxation of the core plate hold-down bolts due to neutron

exposure will not compromise the structural integrity and operability of the core plate to the end

of the period of extended operation. Open Item 4.7.7 is, therefore, closed.

4.7.7.3 UFSAR Supplement

In a letter dated November 16, 2005, the applicant revised LRA Section A.3.5.6 to include the

UFSAR supplement summary description for the TLAA on stress relaxation of the core plate

hold-down bolts. On the basis of its review of the UFSAR supplement, the staff concluded that

the summary description of the applicant's actions to address stress relaxation of the core plate

hold-down bolts is adequate.

4.7.7.4 Conclusion

The staff concluded that the applicant's commitment to provide a revised analysis, two years

prior to the start of the period of extended operation, regarding the stress relaxation TLAA of

the core plate hold-down bolts, and that the analysis will remain valid for the period of extended

operation, in accordance with 10 CFR 54.21(c)(1)(ii), is acceptable. The staff also concluded

that the UFSAR supplement contains an appropriate summary description of this TLAA

evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).
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4.7.8 Emergency Equipment Cooling Water Weld Flaw Evaluation

4.7.8.1 Summary of Technical Information in the Application

The TLAA of the EECW weld flaw evaluation is discussed in LRA Section 4.7.8. The applicant

performed an analysis on 17 selected EECW system piping welds that have flaws. The original

analysis included a stress evaluation of the flawed welds and fatigue crack growth calculations.

The fatigue crack growth calculations were based on a conservative projection of 125 cycles for

the remaining 25 years of the 40-year plant operating life based on five cycles per year. A cycle

occurs when piping, including a subject weld, is removed from service then returned to service.

This projection was derived from a very conservative estimate that each weld could experience

up to five cycles per year. Review of the system function indicated that continuous operation is

intended; however, some interruptions have been required for maintenance and other

considerations. The applicant considers the fatigue crack growth portion of this analysis to be a

TLAA.

As part of the LRA, the applicant found, based on current and recent plant operating

experience, that it is unusual for any of these weld locations to experience more than one cycle

in any given year. For the TLAA, the applicant assumed two cycles per year for the past and the

foreseeable future. The cycle count of two cycles per year was applied to the 25 remaining

operating years (projected when the calculations were performed), plus the 20 years of

extended operation, resulting in a total cycle count of 90. This is less than the estimated cycle

count used for qualification in the original calculation. Therefore, the applicant’s position is that

in accordance with 10 CFR 54.21(c)(1)(i), the analyses remain valid for the period of extended

operation.

4.7.8.2 Staff Evaluation

As required by 10 CFR 54.21, applicants for license renewal must manage time-dependent

aging effects by one of three acceptable methods:

 1. Demonstrate that the TLAA on the aging effect for the current operation term remains

valid for the period of extended operation.

 2. Demonstrate that the TLAA on the aging effect for the current operation term and has

been projected to the end of the period of extended operation.

 3. Demonstrate that the effect of aging on the intended functions will be adequately

managed for the period of extended operation.

In RAI 4.7.8-1, dated November 4, 2004, the staff requested that the applicant provide

background information, including the code class, flaw inspection history, flaw sizes, and a

description of any analysis including the method that was used to determine the flaw evaluation.

In its response, by letter dated December 9, 2004, the applicant stated, in part:

The flawed EECW welds are on BFN Seismic Class I piping that was designed to the

B31.1-1967 Power Piping Code. For the BFN ASME Section XI program the welds are

classified as ASME Class 3. Design conditions for the EECW system are 200 psig and

200 °F. All of the related piping is qualified by analysis. This analysis satisfies BFN
4-59

Design Criteria No. BFN -50-C-7103 which supplements B31.1 analysis requirements by

invoking plant condition dependent stress equations from ASME Section III, 1971

Edition, Summer 1973 Addenda. The stress analyses of the piping systems are also

considered a Time Limited Aging Analysis (TLAA) which is addressed in the Application

TLAA Section 4.3.3. 

History of Discovery – A weld inspection program was initiated at BFN to determine the

effects of MIC on the stainless steel piping girth butt welds in the EECW system, as a

result of MIC discoveries at other plants. The inspection program was implemented by

performing radiography on a sample of EECW piping welds. Radiography had not been

performed on these welds during installation, as it was not required by the applicable

code and specifications. The inspection identified defects in 33 welds. The 33 welds

which had identified defects were reviewed by the ISI Level III interpreter and 27 of the

welds were rejected because they did not meet ISI flaw acceptance standards. The ISI

Level III interpreter determined that the other welds did meet flaw acceptance

standards. 

Analysis Performed – Two analyses were performed in association with the qualification

of the remaining 27 EECW welds with welding defects.

The applicant performed a bounding fracture mechanics analysis for the scope of stainless

steel EECW pipe sizes encompassing the 27 welds that had been rejected based on ASME

Section XI acceptance standards. Of the 27 welds, 10 were found to be acceptable using the

bounding fracture mechanics analysis. The remaining 17 welds are the subject of the TLAA.

For the 17 welds identified in LRA Section 4.7.8, the applicant indicated that a location-specific

fracture mechanics analysis was performed. The weld-specific analysis applied essentially the

same approach and considerations as the bounding analysis except that location-specific

stresses determined for ASME Code Section III, Subsection NC-3652, Equations 9 and 10 in

the piping analyses of record were used to calculate both the ASME Code Section XI allowable

flaw size and the fatigue crack growth due to cyclic load for the 25 years remaining in the plant

life. The applicant found that for the controlling location (i.e., maximum thermal stress) in each

pipe size applicable to the 17 welds, fatigue crack growth for the 25-year period was

insignificant. Although the staff did not perform a detailed review of the applicant’s analysis, the

staff found the applicant’s approach acceptable. The remaining issue is whether the applicant’s

demonstration that the TLAA on the aging effect for the current operation term remains valid for

the period of extended operation.

The applicant stated in its LRA that, based on current and recent plant experience, it is unusual

for any of these weld locations to experience more that one cycle in any given year.

The applicant stated that review of the EECW system indicates that continuous operation is

intended; however, some interruptions have been required for maintenance and other

considerations. Through an informal request on January 31, 2005, the staff requested the

applicant to provide the following information as a follow-up to RAI 4.7.8: (a) Based on the

design function of the EECW system, discuss when and at what frequency would the system be

shut down; (b) Based on the design function and the total past history, discuss whether the

number of cycles in the fatigue evaluation bound the number of cycles projected for the period

of extended operation; (c) Describe events, and the frequency that they have occurred, that
4-60

resulted in system operational interruptions; and (d) Should the EECW system experience more

cycles than is bounded by the applicant’s analysis, discuss any plant procedures in place to

identify this condition.

The applicant responded by letter on March 2, 2005, and provided the following as a follow up

to RAI 4.7.8:

The EECW system is intended to be in a continuous standby condition (i.e. under

pressure-minimum flow) in both shutdown and operating plant modes. As currently

designed, sections of this system may be isolated and depressurized for routine

maintenance or repair. Based on operating history and future (anticipated operations) a

total of 125 full pressure cycles (0 psig to design operating pressure) was selected as a

conservative measure to ensure the number of fatigue cycles would not be exceeded.

The preventative maintenance work orders scheduled on this system are of a periodicity

of no less than 96 weeks (almost 2 years) and unless unexpected repairs are required,

the system would not need to be depressurized. Using a conservatism of a little over 2

times in a year makes sense for it would be very unlikely for the same Section of the

EECW system to be shutdown [sic] > 2 times in a year. Please review preventative

maintenance scheduled items on [the] following page [Not included in this evaluation.

See March 2, 2005 letter]. An administrative tracking system will be developed and used

to ensure that the 125 fatigue cycles will not be exceeded.

Based on operating history and anticipated future operations coupled with the applicant’s

commitment to develop an administrative tracking system to ensure that the EECW system

does not exceed the applicant’s 125 full pressure cycles, the staff concluded that the EECW

weld flaw evaluation is valid for the period of extended operation in accordance with

10 CFR 54.21(c)(1)(i) and is, therefore, acceptable.

4.7.8.3 UFSAR Supplement

As required by 10 CFR 54.21(d), applicants for license renewal must include a UFSAR

supplement summary description of the "programs and activities for managing the effects of

aging and the evaluation of TLAA for the period of extended operation." The applicant provided

a UFSAR supplement summary description of EECW weld flaw evaluation in LRA

Section A.3.5.7. On the basis of its review, and the responses to the staff’s RAIs, the staff

concluded that the UFSAR supplement summary adequately describes the TLAA on EECW

weld flaw evaluation and is, therefore, acceptable.

4.7.8.4 Conclusion

The staff reviewed the applicant's TLAA on EECW weld flaw evaluation, as summarized in LRA

Section 4.7.8, including information submitted in response to the staff’s RAIs, and determined

that the effects of EECW weld flaw evaluation will be adequately managed. Therefore, the staff

concluded that the applicant has demonstrated that the effects of EECW weld flaw evaluation

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(c)(1)(iii). 
4-61

4.8 Conclusion for Time-Limited Aging Analyses

The staff reviewed the information in LRA Section 4, “Time-Limited Aging Analyses.” On the

basis of its review, the staff concluded that the applicant has provided an adequate list of

TLAAs, as defined in 10 CFR 54.3. Further, the staff concluded that 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) that the aging effects will be adequately

managed for the period of extended operation, as required by 10 CFR 54.21(c)(1)(iii). The staff

also reviewed the UFSAR supplement for the TLAAs and found that the UFSAR supplement

contains descriptions of the TLAAs sufficient to satisfy the requirements of 10 CFR 54.21(d). In

addition, the staff concluded that no plant-specific exemptions are in effect that are based on

TLAAs, pursuant to 10 CFR 54.21(c)(2).

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, in order to comply with 10 CFR 54.29(a), are

in accordance with the Atomic Energy Act of 1954, as amended, and the NRC’s regulations.
THIS PAGE IS INTENTIONALLY LEFT BLANK.
1

 This section is revised. See BFN LRA SER Supplement 1.

5-1

SECTION 5

REVIEW BY THE ADVISORY COMMITTEE ON REACTOR

SAFEGUARDS1

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

Advisory Committee on Reactor Safeguards (ACRS) will review the license renewal application

(LRA) for the Browns Ferry Nuclear (BFN) Units 1, 2, and 3. The ACRS Subcommittee on Plant

License Renewal will continue its detailed review of the LRA after this safety evaluation report

(SER) is issued. The applicant and staff from the U.S. Nuclear Regulatory Commission (the

staff) will meet with the subcommittee and the full committee to discuss issues associated with

the review of the LRAs.

After the ACRS completes its review of the LRAs and the SER, the full committee will issue a

report discussing the results of its review. An update to this SER will include the ACRS report.

This update will also include the staff’s response to any issues and concerns identified in the

ACRS report.
THIS PAGE IS INTENTIONALLY LEFT BLANK.
1

 This section is revised. See BFN LRA SER Supplement 1.

6-1

SECTION 6

CONCLUSIONS1

The staff of the U.S. Nuclear Regulatory Commission (NRC or the Commission) reviewed the

license renewal applications for the Browns Ferry Nuclear, Units 1, 2, and 3, in accordance with

Commission regulations and NUREG-1800, “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 applications, 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 Subpart A of 10 CFR Part 51 are documented in

Supplement 21 to NUREG-1437, “Generic Environmental Impact Statement for License

Renewal of Nuclear Plants: Regarding Browns Ferry Nuclear, Units 1, 2, and 3, Final Report,”

dated June 23, 2005.
THIS PAGE INTENTIONALLY LEFT BLANK
1

 This commitment table is revised. See BFN LRA SER Supplement 1

A-1

APPENDIX A

COMMITMENTS FOR LICENSE RENEWALS

OF BFN UNITS 1, 2, AND 31

During the review of the Browns Ferry Nuclear Plant (BFN) license renewal application (LRA) by

the U.S. Nuclear Regulatory Commission (NRC) staff, the applicant made commitments related

to aging management programs (AMPs) to manage aging effects of structures and components

(SCs) before the period of extended operation. The following tables list these commitments,

along with the implementation schedules and the sources of the commitments.

 • Table 1 lists those commitments that are not for a specific unit.

 • Table 2 lists commitments that are specific to Unit 1.

Note that these tables also contain non-AMP commitments.
A-2

THIS PAGE IS INTENTIONALLY LEFT BLANK
TABLE 1: BFN COMMITMENT LIST ASSOCIATED WITH LRA APPENDIX A AGING MANAGEMENT PROGRAMS AND TLAAs

(NON-UNIT SPECIFIC)

A-3

Item Number/Title Commitment LRA

Appendix A

(UFSAR)

Implementation

Schedule

Source

1. Accessible NonEnvironmental

Qualification Cables

and Connections

Inspection Program

Develop and implement new program. A.1.1 Prior to the period of

extended operation

 • LRA Section B.2.1.1

2. Electrical Cables Not

Subject to 

10 CFR 50.49

Environmental

Qualification

Requirements Used

in Instrumentation

Circuits Program

Revise implementing documents for

LPRM cable system aging to reference

existing Technical Specification

requirements and license renewal

reference(s).

A.1.2 Prior to the period of

extended operation

 • LRA Section B.2.1.2

 • Response to followup to RAI 2.5-2 dated

March 2, 2005

Develop and implement new program to

manage IRM cable system aging.

Prior to the period of

extended operation

 • LRA Section B.2.1.2

 • Response to followup to RAI 2.5-2 dated

March 2, 2005

3. Inaccessible Medium

Voltage Cables Not

Subject to 10 CFR

50.49 Environmental

Qualification

Requirements

Program

Develop and implement new program to

manage the medium-voltage cables to the

Residual Heat Removal Service Water

pumps.

A.1.3 Prior to the period of

extended operation

 • LRA Section B.2.1.3

 • Response to RAI 3.6-

3(a) dated December

9, 2004

 • Response to followup RAI 3.6-3 dated

January 18, 2005

4. ASME Section XI

Inservice Inspection

Subsections IWB,

IWC, and IWD

Program

Revise implementing documents to

include license renewal reference(s).

A.1.4 Prior to the period of

extended operation

 • LRA Section B.2.1.4
TABLE 1: BFN COMMITMENT LIST ASSOCIATED WITH LRA APPENDIX A AGING MANAGEMENT PROGRAMS AND TLAAs

(NON-UNIT SPECIFIC)

Item Number/Title Commitment LRA

Appendix A

(UFSAR)

Implementation

Schedule

Source

A-4

5. Chemistry Control

Program

Revise implementing documents to

include license renewal reference(s).

A.1.5 Prior to the period of

extended operation

 • LRA Section B.2.1.5

6. Reactor Head

Closure Studs

Program

Revise implementing documents to

include license renewal reference(s).

A.1.6 Prior to the period of

extended operation

 • LRA Section B.2.1.6

7. Boiling Water

Reactor Vessel

Inside Diameter

Attachment Welds

Program

Revise implementing documents to

include license renewal reference(s).

A.1.7 Prior to the period of

extended operation

 • LRA Section B.2.1.7

8. Boiling Water

Reactor Feedwater

Nozzle Program

Revise implementing documents to

include license renewal reference(s).

A.1.8 Prior to the period of

extended operation

 • LRA Section B.2.1.8

9. Boiling Water

Reactor Control Rod

Drive Return Line

Nozzle Program

Revise implementing documents to

include license renewal reference(s).

A.1.9 Prior to the period of

extended operation

 • LRA Section B.2.1.9

10 Boiling Water

Reactor Stress

Corrosion Cracking

Program

Revise implementing documents to

include license renewal reference(s).

A.1.10 Prior to the period of

extended operation

 • LRA Section B.2.1.10

11. Boiling Water

Reactor Penetrations

Program

Revise implementing documents to

include license renewal reference(s).

A.1.11 Prior to the period of

extended operation

 • LRA Section B.2.1.11

 • Enclosure 1 of TVA

letter dated

September 14, 2005
TABLE 1: BFN COMMITMENT LIST ASSOCIATED WITH LRA APPENDIX A AGING MANAGEMENT PROGRAMS AND TLAAs

(NON-UNIT SPECIFIC)

Item Number/Title Commitment LRA

Appendix A

(UFSAR)

Implementation

Schedule

Source

A-5

12. Boiling Water

Reactor Vessel

Internals Program

Revise implementing documents to

include license renewal reference(s).

A.1.12 Prior to the period of

extended operation

 • LRA Section B.2.1.12

Inspect the top guide beams Prior to the period of

extended operation

 • Response to NRC

Question (3) dated

May 25, 2005

Establish an aging management program

for the steam dryers.

Two years before the

first BFN unit enters the

period of extended

operation

 • Response to

RAI 3.1-1 dated

January 31, 2005

Enhance the Reactor Pressure Vessel

Internals Inspection (RPVII) Units 1, 2,

and 3 procedure to require visual

inspection of the Access Hole Covers

(AHCs) and inspection of the AHC welds.

Two years before the

first BFN unit enters the

period of extended

operation

 • Response to RAI

B.2.1.12-1(C) dated

January 31, 2005

 • Response to NRC

Question (7) dated

May 25, 2005

Implement the inspection of weld TS-2

(BWRVIP-41).

When inspection

technique for weld TS-2

being developed by the

BWRVIP Inspection

Committee is available.

 • Response to

Question (12) dated

May 25, 2005

13. Flow-Accelerated

Corrosion Program

Revise implementing documents to

include license renewal reference(s).

A.1.14 Prior to the period of

extended operation

 • LRA Section B.2.1.15

14. Bolting Integrity

Program

Revise implementing documents to

include license renewal reference(s).

A.1.15 Prior to the period of

extended operation

 • LRA Section B.2.1.16
TABLE 1: BFN COMMITMENT LIST ASSOCIATED WITH LRA APPENDIX A AGING MANAGEMENT PROGRAMS AND TLAAs

(NON-UNIT SPECIFIC)

Item Number/Title Commitment LRA

Appendix A

(UFSAR)

Implementation

Schedule

Source

A-6

15. Open-Cycle Cooling

Water System

Program

Revise implementing documents to

include license renewal reference(s).

A.1.16 Prior to the period of

extended operation

 • LRA Section B.2.1.17

16. Closed-Cycle

Cooling Water

System Program

Revise implementing documents to

include license renewal reference(s).

A.1.17 Prior to the period of

extended operation

 • LRA Section B.2.1.18

17. Inspection of

Overhead Heavy

Load and Light Load

Handling Systems

Program

Revise implementing documents to

include license renewal reference(s).

A.1.18 Prior to the period of

extended operation

 • LRA Section B.2.1.20

18. Compressed Air

Monitoring Program

Revise implementing documents to:

 • Include license renewal reference(s).

 • Incorporate guidelines in ASME OMS/G-2000, Part 17; ANSI/ISAS7.0.01-1996; and EPRI TR 108147

A.1.19 Prior to the period of

extended operation

 • LRA Section B.2.1.21

19. BWR Reactor Water

Cleanup System

Program

Revise implementing documents to

include license renewal reference(s).

A.1.20 Prior to the period of

extended operation

 • LRA Section B.2.1.22

20. Fire Protection

Program

Revise implementing documents to

include license renewal reference(s).

A.1.21 Prior to the period of

extended operation

 • LRA Section B.2.1.23
TABLE 1: BFN COMMITMENT LIST ASSOCIATED WITH LRA APPENDIX A AGING MANAGEMENT PROGRAMS AND TLAAs

(NON-UNIT SPECIFIC)

Item Number/Title Commitment LRA

Appendix A

(UFSAR)

Implementation

Schedule

Source

A-7

21. Fire Water System

Program

Revise implementing documents to:

 • Include license renewal reference(s).

 • Perform flow tests or non-intrusive

examinations to identify evidence of

loss of material due to corrosion.

A.1.22 Prior to the period of

extended operation

 • LRA Section B.2.1.24

Perform sprinkler head inspections to

ensure signs of degradation, such as

corrosion, are detected in a timely

manner.

Prior to exceeding the

50-year service life for

any sprinkler

 • LRA Section B.2.1.24

22. Aboveground Carbon

Steel Tanks Program

Revise implementing documents to

include license renewal reference(s).

A.1.23 Prior to the period of

extended operation

 • LRA Section B.2.1.26

23. Fuel Oil Chemistry

Program

Revise implementing documents to

include license renewal reference(s).

A.1.24 Prior to the period of

extended operation

 • LRA Section B.2.1.27

 • Enclosure 1 of TVA

letter dated

September 14, 2005
TABLE 1: BFN COMMITMENT LIST ASSOCIATED WITH LRA APPENDIX A AGING MANAGEMENT PROGRAMS AND TLAAs

(NON-UNIT SPECIFIC)

Item Number/Title Commitment LRA

Appendix A

(UFSAR)

Implementation

Schedule

Source

A-8

24. Reactor Vessel

Surveillance

Program

Revise implementing documents to

include license renewal reference(s).

A.1.25 Prior to the period of

extended operation

 • LRA Section B.2.1.28

Enhance the Integrated Surveillance

Program (ISP) per proposed BWRVIP116.

Prior to the period of

extended operation

 • LRA Section B.2.1.28

If the ISP is not approved two years prior

to the commencement of the license

renewal period, a plant-specific

surveillance program for each BFN unit

will be submitted to the NRC.

Two years prior to the

commencement of the

license renewal period

 • Response to RAI

B.2.1.28-1(A) dated

January 31, 2005

 • Response to

Question (9) dated

May 25, 2005

Maintain Unit 1 and Unit 3 surveillance

capsules (standby capsules) available to

the ISP.

Unit 3 is ongoing

Unit 1 will commence at

restart

 • Response to

Question (10) dated

May 25, 2005
TABLE 1: BFN COMMITMENT LIST ASSOCIATED WITH LRA APPENDIX A AGING MANAGEMENT PROGRAMS AND TLAAs

(NON-UNIT SPECIFIC)

Item Number/Title Commitment LRA

Appendix A

(UFSAR)

Implementation

Schedule

Source

A-9

25. One-Time Inspection

Program

Develop and implement new program. A.1.26 Prior to the period of

extended operation

 • LRA Section B.2.1.29

Develop and submit procedure for NRC

review.

At least two years prior

to the expiration of the

current operating license

 • Response to

Proposed Unresolved

Item 3.0-4 LP dated

May 27, 2005

Perform a one-time inspection of the

ASME equivalent Class MC supports in a

submerged environment of the Units 2

and 3 Torus.

Prior to the period of

extended operation

 • Response to RAI

B.2.1.33-2 dated

January 18, 2005

Perform a one-time inspection of the inscope submerged concrete in one

individual CCW pump bay of the Intake

Pumping Station.

Prior to the period of

extended operation

 • Response to

Question 359 dated

October 8, 2004

 • Response to RAI 

3.5-16 dated April 5,

2005

Perform ultrasonic thickness

measurements of tank bottoms for those

tanks specified in the Fuel Oil Chemistry

Program (B.2.1.27) and the Aboveground

Carbon Steel Tanks Program (B.2.1.26).

Prior to the period of

extended operation

 • Response to RAI

7.1.19-1 dated May

25, 2005
TABLE 1: BFN COMMITMENT LIST ASSOCIATED WITH LRA APPENDIX A AGING MANAGEMENT PROGRAMS AND TLAAs

(NON-UNIT SPECIFIC)

Item Number/Title Commitment LRA

Appendix A

(UFSAR)

Implementation

Schedule

Source

A-10

26. Selective Leaching of

Materials Program

Develop and implement program. A.1.27 Prior to the period of

extended operation

 • LRA Section B.2.1.30

27. Buried Piping and

Tanks Inspection

Program

Revise implementing documents to

include license renewal reference(s).

A.1.28 Prior to the period of

extended operation

 • LRA Section B.2.1.31

Add a trigger to the excavation permit

document to require notification of

engineering to perform a piping inspection

when piping is excavated.

Complete • NRC Inspection

Report dated January

27, 2005

Determine (via engineering evaluation) if

sufficient inspections have been

performed to draw conclusion regarding

ability of underground coating to protect

piping.

If required, conduct a focused inspection

to draw conclusion concerning the

coating.

Within ten years after

entering the period of

extended operation

 • Response to RAI

7.1.22-1 dated May

25, 2005

Revise implementing documents to

inspect buried piping when it is excavated.

Complete • Response to RAI

7.1.22-1 dated May

25, 2005

28. ASME Section XI

Subsection IWE

Program

Revise implementing documents to

include license renewal reference(s).

A.1.29 Prior to the period of

extended operation

 • LRA Section B.2.1.32
TABLE 1: BFN COMMITMENT LIST ASSOCIATED WITH LRA APPENDIX A AGING MANAGEMENT PROGRAMS AND TLAAs

(NON-UNIT SPECIFIC)

Item Number/Title Commitment LRA

Appendix A

(UFSAR)

Implementation

Schedule

Source

A-11

29. ASME Section XI

Subsection IWF

Program

Revise implementing documents to

include license renewal reference(s).

A.1.30 Prior to the period of

extended operation

 • LRA Section B.2.1.33

Enhance program to manage the aging

effects of ASME equivalent Class MC

supports.

Prior to the period of

extended operation

 • Response to Followup RAI B.2.1.33-1

dated May 31, 2005

30. 10 CFR 50 Appendix

J Program

Revise implementing documents to

include license renewal reference(s).

A.1.31 Prior to the period of

extended operation

 • LRA Section B.2.1.34

31. Masonry Wall

Program

Revise implementing documents to

include license renewal reference(s).

A.1.32 Prior to the period of

extended operation

 • LRA Section B.2.1.35

Revise implementing procedures to clearly

identify structures with masonry walls

within scope and to clarify qualification

requirements for personnel who perform

masonry wall walkdowns.

Prior to the period of

extended operation

 • LRA Section B.2.1.35
TABLE 1: BFN COMMITMENT LIST ASSOCIATED WITH LRA APPENDIX A AGING MANAGEMENT PROGRAMS AND TLAAs

(NON-UNIT SPECIFIC)

Item Number/Title Commitment LRA

Appendix A

(UFSAR)

Implementation

Schedule

Source

A-12

32. Structures Monitoring

Program

Revise implementing documents to

include license renewal reference(s).

A.1.33 Prior to the period of

extended operation

 • LRA Section B.2.1.36

Enhance procedures implementing the10

CFR 50.65 Maintenance Rule Program to

identify all structures and structural

components within scope.

Prior to the period of

extended operation

 • LRA Section B.2.1.36

 • Response to GALL

audit Question 173

dated October 8,

2004

 • Response to GALL

audit Question 357

dated October 8,

2004

Enhance procedures implementing the 10

CFR 50.65 Maintenance Rule program

sampling approach to include

examinations of below-grade concrete

when excavated.

Prior to the period of

extended operation

 • LRA Section B.2.1.36

 • Response to GALL

audit Question 285

dated October 8,

2004

Enhance procedures implementing the 10

CFR 50.65 Maintenance Rule program to

include the guidance provided in ACI

349.3R-96 Chapter 7.

Prior to the period of

extended operation

 • LRA Section B.2.1.36

Enhance LCEI-CI-C9, Attachment 1,

“Buried Piping Inspection Checklist,” to

include “Mechanical Penetration” as an

inspection attribute.

Prior to entering the

period of extended

operation

 • Response to GALL

audit Question 285

dated October 8,

2004
TABLE 1: BFN COMMITMENT LIST ASSOCIATED WITH LRA APPENDIX A AGING MANAGEMENT PROGRAMS AND TLAAs

(NON-UNIT SPECIFIC)

Item Number/Title Commitment LRA

Appendix A

(UFSAR)

Implementation

Schedule

Source

A-13

33. Inspection of WaterControl Structures

Program

Revise implementing documents to

include license renewal reference(s).

A.1.34 Prior to the period of

extended operation

 • LRA Section B.2.1.37

Revise implementing documents to

identify required structures and structural

components within the scope of license

renewal.

Prior to the period of

extended operation

 • LRA Section B.2.1.37

Revise implementing documents to

include special inspections following the

occurrence of large floods, earthquakes,

tornadoes, and intense rainfall.

Prior to the period of

extended operation

 • LRA Section B.2.1.37

Implement periodic monitoring of the raw

service water in close proximity to the

Intake Pumping Station for the

requirements of an aggressive

environment.

Prior to the period of

extended operation

 • Response to RAI 3.5-

16 dated April 5,

2005

34. Environmental

Qualification

Program

Revise implementing documents to

include license renewal reference(s).

A.1.35 Prior to the period of

extended operation

 • LRA Section B.3.1

35. Fatigue Monitoring

Program

Implement enhanced Fatigue Monitoring

Program using the EPRI-licensed

FatiguePro® cycle counting and fatigue

usage tracking computer program.

A.1.36 Prior to the period of

extended operation

 • LRA Section B.3.2

36. Systems Monitoring

Program

Revise implementing documents to

include license renewal reference(s).

A.2.1 Prior to the period of

extended operation

 • LRA Section B.2.1.39

 • Enclosure 1 of TVA

letter dated

September 14, 2005
TABLE 1: BFN COMMITMENT LIST ASSOCIATED WITH LRA APPENDIX A AGING MANAGEMENT PROGRAMS AND TLAAs

(NON-UNIT SPECIFIC)

Item Number/Title Commitment LRA

Appendix A

(UFSAR)

Implementation

Schedule

Source

A-14

37. Bus Inspection

Program

Develop and implement new program. A.2.2 Prior to the period of

extended operation

 • LRA Section B.2.1.40

 • Response to RAI 3.6-

4 dated December 9,

2004

38. Diesel Starting Air

Program

Revise implementing documents to

include license renewal reference(s).

A.2.3 Prior to the period of

extended operation

 • LRA Section B.2.1.41

39. Time-Limited Aging

Analysis:

Reactor Vessel

Thermal Limit

Analyses: Operating

PressureTemperature Limits

(P-T)

Develop and submit revised P-T limits to

the NRC for approval.

A.3.1.5 Prior to the period of

extended operation

 • LRA Section A.3.1.5

 • LRA Section 4.2.5

40. Time-Limited Aging

Analysis:

Environmental

Qualification of

Electrical Equipment

Revise existing EQ program to cover the

extended period of operation.

A.3.3 Prior to the period of

extended operation

 • LRA Section A.3.3

 • LRA Section 4.4

41. Time-Limited Aging

Analysis:

Other Plant Specific

Time-Limited Aging

Analysis:

Emergency

Equipment Cooling

Water Weld Flaw

Evaluation

Implement an administrative tracking

system to ensure limiting number of

fatigue cycles will not be exceeded at the

select EECW locations.

A.3.5.7 Prior to the period of

extended operation

 • LRA Section A.3.5.7

 • Response to RAI

4.7.8 dated March 2,

2005
TABLE 1: BFN COMMITMENT LIST ASSOCIATED WITH LRA APPENDIX A AGING MANAGEMENT PROGRAMS AND TLAAs

(NON-UNIT SPECIFIC)

Item Number/Title Commitment LRA

Appendix A

(UFSAR)

Implementation

Schedule

Source

A-15

42. RAI 2.1-2,A-3 Identify additional piping segments and

supports/equivalent anchors to be placed

in scope.

N/A Complete • Response to RAI 2.1-

2,A-3 dated

September 3, 2004

 • TVA response dated

February 28, 2005

43. RAI 2.1-2,B Implement Unit 1, 2, and 3 DCNs to

qualify twelve temperature switches in the

Turbine Building.

N/A Prior to the period of

extended operation

 • Response to RAI 2.1-

2,B dated

September 3, 2004

44. RAI 2.1-2,C RHRSW

tunnel

Include 24-inch Raw Cooling Water

discharge piping located in the RHRSW

tunnel in scope of license renewal.

N/A Complete • Response to RAI 2.1-

2,C RHRSW Tunnel

dated September 3,

2004

 • TVA response dated

January 31, 2005

45. RAI 2.1-2,C Intake

Pumping Station

Revise 10 CFR 54.4(a)(2) Scoping

Methodology document to address

components located in the lower

compartments of the Intake Pumping

Station.

N/A Prior to next annual

update

 • Response to RAI 2.1-

2,C Intake Pumping

Station dated

September 3, 2004

46. Open Item OI 2.4-3 Perform one time confirmatory ultrasonic

thickness (UT) measurements on a

portion of the cylindrical section of the

drywell on Units 2 and 3.

N/A Prior to the period of

extended operation

 • Enclosures 1 and 9 of

TVA letter dated

November 16, 2005
TABLE 1: BFN COMMITMENT LIST ASSOCIATED WITH LRA APPENDIX A AGING MANAGEMENT PROGRAMS AND TLAAs

(NON-UNIT SPECIFIC)

Item Number/Title Commitment LRA

Appendix A

(UFSAR)

Implementation

Schedule

Source

A-16

47. Open Item OI 4.7.7 Perform a BFN plant-specific analysis

consistent with BWRVIP-25 to

demonstrate that the core plate hold-down

bolts can withstand required loads,

considering the effects of stress relaxation

until the end of the period of extended

operation. Take appropriate corrective

action if the analysis does not satisfy the

specified criteria.

Submit the analysis or the corrective

action taken to resolve the core plate holddown bolt issue to the NRC for review.

N/A Two years prior to the

period of extended

operation

 • Enclosures 3 and 9 of

TVA letter dated

November 16, 2005

48. Open Item from AMP

Inspection on

Inspection of

RHRSW Piping

Perform a confirmatory inspection of the

RHRSW pump pit supply piping.

Include instructions in the CCW pump pit

Preventive Maintenance Program to

periodically inspect the sluice gate valves.

Perform a confirmatory inspection of the

seismic restraints in the RHRSW pump

pit.

N/A Prior to the period of

extended operation

 • Enclosures 4 and 9 of

TVA letter dated

November 16, 2005

 
TABLE 2: BFN COMMITMENT LIST ASSOCIATED WITH LRA APPENDIX A AGING MANAGEMENT PROGRAMS AND TLAAs

(UNIT 1 SPECIFIC)

A-17

 NOTE: This Table does not contain all of the same Item Numbers as contained in Table 1. While there is a one-to-one correlation

 of items with the same number, the same Item Numbers are not in both tables as explained below:

 • For Item Numbers 1. through 49., only those Item Numbers that have a Unit 1 specific commitment are included in this table.

 • Item Number 63. applies only to Unit 1.

Item Number/Title Commitment LRA

Appendix A

(UFSAR)

Implementation

Schedule

Source

2. Electrical Cables Not

Subject to 10 CFR

50.49 Environmental

Qualification

Requirements Used

in Instrumentation

Circuits Program

Include Unit 1 High-Range Radiation

Monitoring cables in the Environmental

Qualification (EQ) Program.

A.1.2 Prior to Unit 1 restart • Response to GALL

audit Question 169

dated October 8,

2004

5. Chemistry Control

Program

Include Unit 1 in the program. A.1.5 Prior to Unit 1 restart • LRA Section B.2.1.5

7. Boiling Water

Reactor Vessel

Inside Diameter

Attachment Welds

Program

Include Unit 1 in the program. A.1.7 Prior to Unit 1 restart • LRA Section B.2.1.7

8. Boiling Water

Reactor Feedwater

Nozzle Program

Upgrade Unit 1 operating procedures to

decrease the magnitude and frequency of

feedwater temperature fluctuations.

A.1.8 Prior to Unit 1 restart • LRA Section B.2.1.8

10. Boiling Water

Reactor Stress

Corrosion Cracking

Program

Include Unit 1 in the program. A.1.10 Prior to Unit 1 restart • LRA Section B.2.1.10

 • Response to GALL

audit Question 181

dated October 8,

2004
TABLE 2: BFN COMMITMENT LIST ASSOCIATED WITH LRA APPENDIX A AGING MANAGEMENT PROGRAMS AND TLAAs

(UNIT 1 SPECIFIC)

Item Number/Title Commitment LRA

Appendix A

(UFSAR)

Implementation

Schedule

Source

A-18

11. Boiling Water

Reactor Penetrations

Program

Include Unit 1 in the program. A.1.11 Prior to Unit 1 restart • LRA Section B.2.1.11

 • Response to GALL

audit Question 194

dated October 8,

2004

12. Boiling Water

Reactor Vessel

Internals Program

Include Unit 1 in the program. A.1.12 Prior to Unit 1 restart • LRA Section B.2.1.12

 • Response to

Question (4b) dated

May 25, 2005

13. Flow-Accelerated

Corrosion Program

Include Unit 1 in the program. A.1.14 Prior to Unit 1 restart • LRA Section B.2.1.15

 • Response to GALL

audit Question 144

dated October 8,

2004

15. Open-Cycle Cooling

Water System

Program

Include Unit 1 in the program. A.1.16 Prior to Unit 1 restart • LRA Section B.2.1.17

 • Response to GALL

audit Question 144

dated October 8,

2004

16. Closed-Cycle

Cooling Water

System Program

Include Unit 1 in the program. A.1.17 Prior to Unit 1 restart • LRA Section B.2.1.18

 • Response to GALL

audit Question 144

dated October 8,

2004

18. Compressed Air

Monitoring Program

Include Unit 1 in the program. A.1.19 Prior to Unit 1 restart • LRA Section B.2.1.21
TABLE 2: BFN COMMITMENT LIST ASSOCIATED WITH LRA APPENDIX A AGING MANAGEMENT PROGRAMS AND TLAAs

(UNIT 1 SPECIFIC)

Item Number/Title Commitment LRA

Appendix A

(UFSAR)

Implementation

Schedule

Source

A-19

19. BWR Reactor Water

Cleanup System

Program

Include Unit 1 in the program. A.1.20 Prior to Unit 1 restart • LRA Section B.2.1.22

 • LRA Section F.13

20. Fire Protection

Program

Update the Fire Protection Report and to

incorporate Unit 1 as an operating unit. 

Fully implement the program on Unit 1.

A.1.21 Prior to Unit 1 restart • LRA Section B.2.1.23

21. Fire Water System

Program

Update the Fire Protection Report and

procedures to incorporate Unit 1 as an

operating unit. Fully implement the

program on Unit 1.

A.1.22 Prior to Unit 1 restart • LRA Section B.2.1.24

24. Reactor Vessel

Surveillance

Program

Either include Unit 1 within the BWRVIP

ISP, or submit for NRC approval a plant

specific surveillance program that meets

the requirements of 10 CFR 50 Appendix

H for the period of extended operation.

A.1.25 Prior to the period of

extended operation

 • LRA Section B.2.1.28

Ensure BWRVIP-86-A and BWRVIP-116

are revised to incorporate Unit 1, and

submit to the NRC a license amendment

request to implement the ISP for sitespecific use for

Unit 1.

Prior to the period of

extended operation

 • Response to RAI

B.2.1.28-1 dated

January 31, 2005

25. One-Time Inspection

Program

Perform a one-time inspection of the

ASME equivalent Class MC supports in a

submerged environment of the Unit 1

Torus.

A.1.26 Prior to Unit 1 restart • Response to RAI

B.2.1.33-2(b) dated

January 18, 2005

34. Environmental

Qualification

Program

Include Unit 1 in the program. A.1.35 Prior to Unit 1 restart • LRA Section B.3.1
TABLE 2: BFN COMMITMENT LIST ASSOCIATED WITH LRA APPENDIX A AGING MANAGEMENT PROGRAMS AND TLAAs

(UNIT 1 SPECIFIC)

Item Number/Title Commitment LRA

Appendix A

(UFSAR)

Implementation

Schedule

Source

A-20

47. Open Item OI 2.4-3 Perform one time confirmatory UT

measurements on the drywell vertical

cylindrical area immediately below the

drywell flange

N/A Prior to Unit 1 restart • Enclosures 1 and 9 or

TVA letter dated

November 16, 2005

49. Unit 1 Periodic

Inspection Program

Develop and implement new program. A.2.4 Prior to the period of

extended operation

 • Response to

Proposed Unresolved

Items 3.0-2 LP (1 &

2) and 3.0-3 LP dated

May 27, 2005

 • Enclosure 1 of TVA

letter dated

September 14, 2005

Develop and submit implementing

procedure(s) for NRC review.

At least two years prior

to the period of extended

operation

 • Response to

Proposed Unresolved

Items 3.0-4 LP dated

May 27, 2005

63. Response to NRC

Questions

Concerning RPV

Internals

Replace all BFN Unit 1 dry tubes. N/A Prior to Unit 1 restart • Response to

Question (8) dated

May 25, 2005

Perform MSIP for Unit 1 Control Rod Drive

Return Line Cap.

Prior to Unit 1 restart • Response to

Question (6) dated

May 25, 2005

Change the Unit 1 AHCs to bolted design. Prior to Unit 1 restart • Response to NRC

Question (7) dated

May 25, 2005
TABLE 3: UNIT 1 RESTART COMMITMENTS THAT ARE DISCUSSED IN LRA APPENDIX F

A-21

 NOTE: See Note at the beginning of Table 2

Item Number/Title Commitment LRA

Appendix A

(UFSAR)

Implementation

Schedule

Source

50. Appendix F.1 Evaluate and modify, as required, main

steam leakage path piping to ensure

structural integrity.

N/A Prior to Unit 1 restart • LRA Appendix F

 • TVA response dated

January 31, 2005

51. Appendix F.2 Implement Containment Atmosphere

Dilution System modification.

N/A Prior to Unit 1 restart • LRA Appendix F

 • TVA response dated

January 31, 2005

52. Appendix F.3 Revise Fire Protection Program to ensure

compliance with 10 CFR 50 Appendix R.

Revise Fire Protection Report per Unit 1

License Condition 2.C.13.

N/A Prior to Unit 1 restart • LRA Appendix F

 • TVA response dated

January 31, 2005

53. Appendix F.4 Implement Environmental Qualification

Program.

N/A Prior to Unit 1 restart • LRA Appendix F

 • TVA response dated

January 31, 2005

54. Appendix F.5 Address GL 88-01, and make necessary

plant modifications.

N/A Prior to Unit 1 restart • LRA Appendix F

 • TVA response dated

January 31, 2005

55. Appendix F.6 BWRVIP Programs used for Units 2 and 3

will be used for Unit 1.

N/A Prior to Unit 1 restart • LRA Appendix F

 • TVA response dated

January 31, 2005

56. Appendix F.7 Install ATWS features. N/A Prior to Unit 1 restart • LRA Appendix F

 • TVA response dated

January 31, 2005
TABLE 3: UNIT 1 RESTART COMMITMENTS THAT ARE DISCUSSED IN LRA APPENDIX F

Item Number/Title Commitment LRA

Appendix A

(UFSAR)

Implementation

Schedule

Source

A-22

57. Appendix F.8 Remove Reactor Vessel Head Spray

piping in drywell, and seal the primary

containment penetrations

N/A Prior to Unit 1 restart • LRA Appendix F

 • TVA response dated

January 31, 2005

58. Appendix F.9 Implement the Hardened Wetwell Vent

modification.

N/A Prior to Unit 1 restart • LRA Appendix F

 • TVA response dated

January 31, 2005

59. Appendix F.10 Cap Service Air and Demineralized Water

Primary Containment Penetrations.

N/A Prior to Unit 1 restart • LRA Appendix F

 • TVA response dated

January 31, 2005

60. Appendix F.11 Modify Auxiliary Decay Heat Removal

System to serve Unit 1.

N/A Prior to Unit 1 restart • LRA Appendix F

 • TVA response dated

January 31, 2005

61. Appendix F.12 Fully implement the Maintenance Rule

Unit 1’s temporary exemption ceases to

be effective.

N/A Prior to Unit 1 restart • LRA Appendix F

 • TVA response dated

January 31, 2005

62. Appendix F.13 Replace RWCU piping outside of primary

containment with IGSCC resistant piping.

Implement actions requested in GL 89-10

for RWCU

N/A Prior to Unit 1 restart • LRA Appendix F

 • TVA response dated

January 31, 2005
B-1

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 Tennessee Valley Authority

(TVA), and other correspondence regarding the NRC staff’s reviews of the Browns Ferry

Nuclear (BFN), Units 1, 2 and 3 (under Docket Numbers 50-259, 50-260 and 50-296) license

renewal application (LRA).

July 12, 1984 TVA letter to NRC, in regards to NUREG 0737, Item II.K.3.28,

“Qualification of ADS Accumulators”

July 24, 1985 NRC letter to TVA, “NUREG 0737, Item II.K.3.28, Qualification of ADS

Accumulators”

March 1, 1988 TVA letter, R. Gridley to NRC, “Browns Ferry Nuclear Plant (BFN) -

Anticipated Transients Without Scram (ATWS) Rule (10 CFR 50.62) -

Plant Specific Design”

August 1, 1988 TVA letter to NRC, “Browns Ferry Nuclear Plant (BFN) - Response to

Bulletin (sic) 88-01, NRC Position on IGSCC in BWR Austenitic Stainless

Steel Piping, dated January 25, 1988”

October 24, 1988 TVA letter, S. A. White to NRC, “Browns Ferry Nuclear Plan (BFN)

Nuclear Performance Plan, Revision 2"

December 8, 1988 NRC letter to TVA, “Browns Ferry Nuclear Plant, Units 1, 2 and 3 -

Appendix R Safe Shutdown System Analysis”

January 22, 1989 NRC letter to TVA, “Compliance with Rule 10 CFR 50.62 Relating to

Alternate Rod Injection and Reactor Pump Trip Systems”

January 26, 1989 NRC letter to TVA, “Technical Specifications on Anticipated Transients

Without Scram (ATWS) - Recirculation Pump Trip (RPT), Browns Ferry

Nuclear Plants, Units 1, 2, and 3” (Accession No. ML020020476)

October 30, 1989 NRC letter to All Operating Licensees with Mark I Containments,

“Installation of a Hardened Wetwell Vent (Generic Letter 89-16),” dated

September 1, 1989. 2. TVA letter, M. J. Ray to NRC, “Response to

Generic Letter 89-16, Installation of Hardened Wetwell Vent”

November 2, 1989 NRC letter to TVA, “Supplemental Safety Evaluation on Post-Fire Safe

Shutdown Systems and Final Review of the National Fire Protection

Association Code Deviations - Browns Ferry Nuclear Plant, Unit 2" 
B-2

November 29, 1990 TVA letter, E. G. Wallace to NRC, “Browns Ferry Nuclear Plant (BFN) -

Anticipated Transient Without Scram (ATWS) Response to NRC

Followup Items Received During ATWS Inspection

January 23, 1991 NRC letter to TVA, “NUREG 1232, Volume 3, Supplement 2 Browns

Ferry, Unit 2"

March 6, 1991 NRC letter to TVA, “Issuance of Amendment” (Accession No.

ML020090226) 

May 5, 1992 NRC letter to TVA, “Request for Additional Information to Review

Compliance with NUREG 0737, Item II.E.4.2 and 10 CFR 50, Appendix J

December 28, 1992 TVA letter to NRC, “Browns Ferry Nuclear Plant – Unit 3 - Supplemental

Response to Generic Letter (GL) 88-01, NRC Position on Intergranular

Stress Corrosion Cracking (IGSCC) in BWR Austenitic Stainless Steel

Piping”

March 31, 1993 NRC letter to TVA, “Fire Protection Program - Browns Ferry Nuclear

Plant Units 1, 2 and 3"

December 3, 1993 NRC letter to TVA, “Browns Ferry Nuclear Plant Unit 3 - Safety

Evaluation of Supplemental Response to Generic Letter 88-01"

January 2, 1995 NRC letter to TVA, “Browns Ferry Nuclear Plant Units 1 and 3,

NUREG-0737, Item II.E.4.2, Containment Isolation Dependability”

November 2, 1995 NRC letter to TVA, “Safety Evaluation of Post-Fire Safe Shutdown

Capability and Issuance of Technical Specification Amendments for the

Browns Ferry Nuclear Plant Units 1, 2, and 3" (Accession No.

ML020040025) 

April 25, 1997 BWRVIP letter, C. Terry to B. Sheron (NRC), “BWR Utility Commitments

to the BWRVIP”

August 9, 1999 NRC letter to TVA, ”Issuance of Temporary Partial Exemption from

10 CFR 50.65, Browns Ferry Nuclear Plant, Unit 1” (Accession No.

ML020040329) 

November 25, 2002 NRC Meeting Summary, S.T. Hoffman, “Summary Of Meeting to Discuss

Planned License Renewal Application” (Accession No. ML023300013)

June 2, 2003 NRC Meeting Summary, S.T. Hoffman, Summary Of Meeting To Discuss

Planned License Renewal Application (Accession No. ML031540295)

October 30, 2003 NRC Meeting Summary, S.T. Hoffman, “Summary Of Meeting to Discuss

Browns Ferry Units 1, 2, and 3 Planned License Renewal Application”

(Accession No. ML033080369)
B-3

December 3, 2003 NRC letter to TVA, “Browns Ferry Nuclear Plant Unit 3 - Safety

Evaluation of Supplemental Response to Generic Letter 88-01"

December 31, 2003 Letter from Mr. Mark. J. Burzynski, Tennessee Valley Authority (TVA) to

the NRC, submitting the application for the renewal of the operating

Licenses for Browns Ferry Nuclear Units 1,2, and 3 (Accession No.

ML040060361) 

January 7, 2004 Letter from P.T.Kuo, NRC, to J.A.Scalice,TVA forwarding the Notice of

Receipt and Availability of the application for the renewal of the operating

license for the BFN Units 1,2 and 3 (Accession No. ML040090370)

February 19, 2004 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the

NRC- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 - January 28,

2004 Meeting Follow-Up - Additional Information - Supplemental

Information - Unit 1 Wet Lay-Up (Accession No. ML040510241)

March 4, 2004 Letter from P.T.Kuo, NRC to J. A. Scalice, TVA indicating acceptability

and sufficiency for docketing and opportunity for a hearing regarding the

application from Tennessee Valley Authority for renewal of the operating

licenses for the BFN, units 1, 2, and 3 (Accession No. ML040650206)

March 25, 2004 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

stating use of the BFN license renewal boundary drawings to obtain

scoping results (Accession No. ML040860596)

March 31, 2004 Letter from P.T.Kuo, NRC, to J.A.Scalice,TVA forwarding the review

schedule for application for renewal of the operating licenses for the BFN

Units 1,2 and 3 (Accession No. ML040910016)

May 4, 2004 In a memorandum (signed by Jimi Yerokum), NRC summarized the

April 7, 2004 teleconference between the NRC staff and Tennessee

Valley Authority (TVA) regarding draft Request for Additional Information

(D-RAI) concerning the staff’s review of the LRA. (Accession No.

ML041310015)

May 6, 2004 In a memorandum (signed by Jimi Yerokum), NRC summarized the

March 24, 2004 and March 30, 2004 teleconferences between the NRC

staff and Tennessee Valley Authority (TVA) regarding draft Request for

Additional Information (D-RAI) concerning the staff’s review of the LRA.

(Accession No. ML041310029)

May 10, 2004 In a memorandum (signed by Jimi Yerokum), NRC summarized the

April 14, 2004 teleconference between the NRC staff and Tennessee

Valley Authority (TVA) regarding draft Request for Additional Information

(D-RAI) concerning the staff’s review of the LRA. (Accession No.

ML041310206)
B-4

May 27, 2004 Browns Ferry Nuclear Plant (BFN) Units 1, 2, and 3 - March 30-31, 2004

meeting follow-up-additional information for License Renewal

Environmental Review

May 28, 2004 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

updating the LRA application sections 4.2 and 4.3 to reflect extended

power uprate conditions (Accession No. ML041550393)

June 15, 2004 In a memorandum (signed by Yoira Diaz-Sanabria), NRC summarized

the May 19, 2004 teleconference between the NRC staff and Tennessee

Valley Authority (TVA) regarding draft Request for Additional Information

(D-RAI) concerning the staff’s review of the LRA. (Accession No.

ML041700550)

June 16, 2004 In a memorandum (signed by Yoira Diaz-Sanabria), NRC summarized

the April 21, 2004 teleconference between the NRC staff and Tennessee

Valley Authority (TVA) regarding draft Request for Additional Information

(D-RAI) concerning the staff’s review of the LRA. (Accession No.

ML041700505)

June 16, 2004 In a memorandum (signed by Yoira Diaz-Sanabria), NRC summarized

the May 27, 2004 teleconference between the NRC staff and Tennessee

Valley Authority (TVA) concerning activities on BFN units 1, 2 and 3 LRA.

(Accession No. ML041700523)

June 18, 2004 In a memorandum (signed by Yoira Diaz-Sanabria), NRC summarized

the May 5, 2004 teleconference between the NRC staff and Tennessee

Valley Authority (TVA) regarding draft Request for Additional Information

(D-RAI) concerning the staff’s review of the LRA. (Accession No.

ML041700572)

June 23, 2004 Letter from Yoira Diaz-Sanabria, NRC, to K. W. Singer, Tennessee

Valley Authority (TVA) forwarding request for additional information for

the review of the BFN units 1, 2 and 3 license renewal application on

section 3.5 of the LRA. (Accession No. ML041760076)

June 28, 2004 In a memorandum (signed by Yoira Diaz-Sanabria), NRC summarized

the May 27, 2004 teleconference between the NRC staff and Tennessee

Valley Authority (TVA) regarding draft Request for Additional Information

(D-RAI) concerning the staff’s review of the LRA. (Accession No.

ML041810168)

July 7, 2005 Response to Request for Additional Information (RAI) regarding severe

accident mitigation alternatives for Browns Ferry Nuclear Plant, Units 1,

2, and 3
B-5

July 9, 2004 TVA letter to NRC, “Browns Ferry Nuclear Plant (BFN) Unit 1 - Technical

Specification (TS) 436 - Increased Main Steam Isolation Valve (MSIV)

Leakage Rate Limits and Exemption from 10 CFR 50, Appendix J” 

(Accession No. ML041980222)

July 10, 2004 In a memorandum (signed by Yoira Diaz-Sanabria), NRC summarized

the June 16, 2004 teleconference between the NRC staff and 

Tennessee Valley Authority (TVA) regarding draft Request for Additional

Information (D-RAI) concerning the staff’s review of the LRA. (Accession

No. ML041950508)

July 19, 2004 In a memorandum (signed by Yoira Diaz-Sanabria), NRC summarized

the April 28, 2004 teleconference between the NRC staff and Tennessee

Valley Authority (TVA) regarding draft Request for Additional Information

(D-RAI) concerning the staff’s review of the LRA. (Accession No.

ML042010388)

July 19, 2004 Letter from Mr. M.J.Burzynski, Tennessee Valley Authority (TVA) to the

NRC regarding lay-up effects of Unit 1 Structures and Component

Supports (Accession No. ML042040231)

July 21, 2004 TVA letter, T. E. Abney to NRC, “Browns Ferry Nuclear Plant (BFN)

Unit 1 – Supplemental Response to Generic Letter 88-01, NRC Position

on Intergranular Stress Corrosion Cracking in BWR Austenitic Stainless

Steel Piping” (Accession No. ML042040274)

July 28, 2004 In a memorandum (signed by Yoira Diaz-Sanabria), NRC summarized

the July 1, 2004 teleconference between the NRC staff and Tennessee

Valley Authority (TVA) regarding draft Request for Additional Information

(D-RAI) concerning the staff’s review of the LRA. (Accession No.

ML042110485)

July 30, 2004 Letter from Yoira Diaz-Sanabria, NRC, to K. W. Singer, Tennessee

Valley Authority (TVA) forwarding request for additional information for

the review of the BFN units 1, 2 and 3 license renewal application on

section 2.1 of the LRA. (Accession No. ML042120186)

August 3, 2004 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

detailed explanation of how the LRA application Bounds the BFN

extended power uprate (EPU) submittals (Accession No. ML042180449)

August 5, 2004 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

update of application sections 4.2 and 4.3 to reflect extended power

uprate conditions –supplemental information (Accession No.

ML042220285)
B-6

August 23, 2004 Letter from Yoira Diaz-Sanabria, NRC, to K. W. Singer, Tennessee

Valley Authority (TVA) forwarding request for additional information for

the review of the BFN units 1, 2 and 3 license renewal application on

sections 3.1, 3.2, 3.3, and 3.4 of the LRA. (Accession NO.

ML042360590)

August 23, 2004 Letter from Yoira Diaz-Sanabria, NRC, to K. W. Singer, Tennessee

Valley Authority (TVA) forwarding request for additional information for

the review of the BFN units 1, 2 and 3 license renewal application on

sections 2.3, 3.3, 4.4, B.2.0 of the LRA (Accession NO. ML042360762)

August 23, 2004 In a memorandum (signed by Yoira Diaz-Sanabria), NRC summarized

the July 28, 2004 teleconference between the NRC staff and Tennessee

Valley Authority (TVA) regarding draft Request for Additional Information

(D-RAI) concerning the staff’s review of the LRA. (Accession No.

ML042390497)

August 26, 2004 In a memorandum (signed by Yoira Diaz-Sanabria), NRC summarized

the July 24, 2004 teleconference between the NRC staff and Tennessee

Valley Authority (TVA) regarding draft Request for Additional Information

(D-RAI) concerning the staff’s review of the LRA. (Accession No.

ML042400550)

August 31, 2004 In a memorandum (signed by Yoira Diaz-Sanabria), NRC summarized

the July 12, 2004 teleconference between the NRC staff and Tennessee

Valley Authority (TVA) regarding draft Request for Additional Information

(D-RAI) concerning the staff’s review of the LRA. (Accession No.

ML042450211)

August 31, 2004 Letter from Yoira Diaz-Sanabria, NRC, to K. W. Singer, Tennessee

Valley Authority (TVA) forwarding request for additional information for

the review of the BFN units 1, 2 and 3 license renewal application on

sections 2.1, 2.2, and 2.3 of the LRA. (Accession No. ML042450260)

September 3, 2004 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

NRC scoping and screening audit – request for additional information

(RAI) (Accession No. ML042520374)

September 16, 2004 In a memorandum (signed by Yoira Diaz-Sanabria), NRC summarized

the August 19, 2004 teleconference between the NRC staff and 

Tennessee Valley Authority (TVA) regarding draft Request for Additional

Information (D-RAI) concerning the staff’s review of the LRA. (Accession

No. ML042600522)

September 27, 2004 NRC letter to TVA, “Browns Ferry Nuclear Plant, Units 1, 2, and 3 —

Issuance of Amendments Regarding Full- Scope Implementation of

Alternative Source Term” (Accession No. ML042730028)
B-7

September 30, 2004 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC 

NRC scoping and screening audit –request for additional information

(Accession No. ML042750259)

October 6, 2004 Letter from Yoira Diaz-Sanabria, NRC, to K. W. Singer, Tennessee

Valley Authority (TVA) forwarding request for additional information for

the review of the BFN units 1, 2 and 3 license renewal application on

2.3.1, 2.3.2, and 2.3.3 of the LRA. (Accession No. ML042860015)

October 8, 2004 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC 

NRC scoping and screening audit –request for additional information

(Accession No. ML042870422)

October 8, 2004 Letter from Yoira Diaz-Sanabria, NRC, to K. W. Singer, Tennessee

Valley Authority (TVA) forwarding request for additional information for

the review of the BFN units 1, 2 and 3 license renewal application on

section 2.3 of the LRA. (Accession No. ML042860051)

October 8, 2004 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC 

NRC scoping and screening staff audit at BFN – request for additional

information (Accession No. ML042870428)

October 8, 2004 Letter from Yoira Diaz-Sanabria, NRC, to K. W. Singer, Tennessee

Valley Authority (TVA) forwarding request for additional information for

the review of the BFN units 1, 2 and 3 license renewal application on

sections 2.3.2 and 2.3.3 of the LRA (Accessiion No. ML042860066)

October 12, 2004 Letter from Yoira Diaz-Sanabria, NRC, to K. W. Singer, Tennessee

Valley Authority (TVA) forwarding request for additional information for

the review of the BFN units 1, 2 and 3 license renewal application on

section 3.3 of the LRA (Accession No. ML042860133)

October 15, 2004 In a memorandum (signed by Yoira Diaz-Sanabria), NRC summarized

the September 15, 2004 teleconference between the NRC staff and 

Tennessee Valley Authority (TVA) regarding draft Request for Additional

Information (D-RAI) concerning the staff’s review of the LRA. (Accession

No. ML042920201)

October 18, 2004 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC 

NRC scoping and screening audit – request for additional information

(Accession No. ML042930471)

October 19, 2004 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC 

– request for additional information - Sections 2.1, 2.2, and 2.3, related

to the Scoping and Screening: Mechanical Systems (Accession No.

ML042930931)
B-8

October 21, 2004 In a memorandum (signed by Yoira Diaz-Sanabria), NRC summarized

the September 22, 2004 teleconference between the NRC staff and 

Tennessee Valley Authority (TVA) regarding draft Request for Additional

Information (D-RAI) concerning the staff’s review of the LRA. (Accession

No. ML042990519)

October 22, 2004 In a memorandum (signed by Yoira Diaz-Sanabria), NRC summarized

the August 18, 2004 teleconference between the NRC staff and 

Tennessee Valley Authority (TVA) regarding draft Request for Additional

Information (D-RAI) concerning the staff’s review of the LRA. (Accession

No. ML043000040)

October 25, 2004 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC 

 - request for additional information on Appendix F (Accession No.

ML043000149)

October 28, 2004 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC 

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application – Fire Protection Section Verbal Request on October 20,

2004 - Response to NRC Request for Additional Information (Accession

No. ML043030434)

November 1, 2004 Letter from Yoira Diaz-Sanabria, NRC, to K. W. Singer, Tennessee

Valley Authority (TVA) forwarding request for additional information for

the review of the BFN units 1, 2 and 3 license renewal application on

section 2.5 of the LRA (Accession No. ML043060492)

November 3, 2004 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

Browns Ferry Nuclear Plant (BFN) – Units 1, 2, and 3 License Renewal

Application – Heating, Ventilation, and Cooling (HVAC) Systems

Sections 2.3.2 and 2.3.3 – Request for Additional Information (RAI) -

(Accession No. ML043090545)

November 3, 2004 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

Browns Ferry Nuclear Plant (BFN) – Units 1, 2, and 3 License Renewal

Application – Reactor Systems Section 2.3.1, 2.3.2, and 2.3.3 – Request

for Additional Information (Accession No. ML043100588)

November 3, 2004 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application – Auxiliary Systems Section 3.3 - Response to NRC Request

for Additional Information (Accession No. ML043090343)

November 4, 2004 Letter from Yoira Diaz-Sanabria, NRC, to K. W. Singer, Tennessee

Valley Authority (TVA) forwarding request for additional information for

the review of the BFN units 1, 2 and 3 license renewal application on

sections 3.1.2.4, B.2.1.13, and 4.7.8 of the LRA (Accession No.

ML043090573)
B-9

November 4, 2004 Letter from Yoira Diaz-Sanabria, NRC, to K. W. Singer, Tennessee

Valley Authority (TVA) forwarding request for additional information for

the review of the BFN units 1, 2 and 3 license renewal application on

section 3.6 of the LRA (Accession No. ML043090577)

November 18, 2004 Letter from Ram Subbaratnam, NRC, to K. W. Singer, Tennessee Valley

Authority (TVA) forwarding request for additional information for the

review of the BFN units 1, 2 and 3 license renewal application on 

Sections 3.2 and 3.4 of the LRA (Accession No. ML043270655)

December 1, 2004 Letter from Ram Subbaratnam, NRC, to K. W. Singer, Tennessee Valley

Authority (TVA) forwarding request for additional information for the

review of the BFN units 1, 2 and 3 license renewal application on 

Sections 3.1 of the LRA (Accession No. ML043360401)

December 1, 2004 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application – electrical and instrument and control systems (I&C) systems

section 2.5- Response to NRC Request for Additional Information

(Accession No. ML043370173)

December 3, 2004 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application – Heating, Ventilation, and Cooling (HVAC) Systems

Sections 2.3.2 and 2.3.3 - Response to NRC Request for Additional

Information (Accession No. ML043380353)

December 7, 2004 Letter from Yoira Diaz-Sanabria, NRC, to K. W. Singer, Tennessee

Valley Authority (TVA) forwarding request for additional information for

the review of the BFN units 1, 2 and 3 license renewal application on

Chemistry Control Program, Section B.2.1.5 of the LRA (Accession No.

ML043490336)

December 9, 2004 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application – Mechanical Systems Sections 3.1.2.4, B.2.1.13, and 4.7.8-

Response to NRC Request for Additional Information (Accession No.

ML043440080)

December 9, 2004 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Electrical and Instrument and Control Systems (I&C)

Systems Section 3.6- Response to NRC Request for Additional

Information (Accession No. ML043440226)

December 9, 2004 Letter from Ram Subbaratnam, NRC, to K. W. Singer, Tennessee Valley

Authority (TVA) forwarding status of staff review of the Browns Ferry

Nuclear Plant Units 1, 2, and 3 License Renewal Application (Accession

No. ML043490470)
B-10

December 10, 2004 Letter from Ram Subbaratnam, NRC, to K. W. Singer, Tennessee Valley

Authority (TVA) forwarding request for additional information for the

review of the BFN units 1, 2, and 3 license renewal application on

Section 3.5 and B.2.1.34 of the LRA (Accession No. ML043500140)

December 13, 2004 Letter from Ram Subbaratnam, NRC, to K. W. Singer, Tennessee Valley

Authority (TVA) forwarding request for additional information for the

review of the BFN units 1, 2 and 3 license renewal application on ASME

Section XI Subsection IWF Program, Section B.2.1.33 of the LRA

(Accession No. ML043500210)

December 14, 2004 Letter from Yoira Diaz-Sanabria, NRC, to K. W. Singer, Tennessee

Valley Authority (TVA) forwarding request for additional information for

the review of the BFN units 1, 2 and 3 license renewal application

Section 4.7.1 of the LRA (Accession No. ML043500508)

December 16, 2004 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Mechanical Systems Sections 3.2 and 3.4 - Response to

NRC Request for Additional Information (Accession No. ML043520395)

December 16, 2004 Letter from Yoira Diaz-Sanabria, NRC, to K. W. Singer, Tennessee

Valley Authority (TVA) forwarding request for additional information for

the review of the BFN units 1, 2 and 3 license renewal application

Section 3.0 of the LRA (Accession No. ML043560502)

December 20, 2004 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Sections 4.4-2 Mechanical and Environmental Qualifications

- Response to NRC Request for Additional Information (Accession No.

ML043550381)

December 20, 2004 Letter from Yoira Diaz-Sanabria, NRC, to K. W. Singer, Tennessee

Valley Authority (TVA) forwarding request for additional information for

the review of the BFN units 1, 2 and 3 license renewal application on

Section 2.4 of the LRA (Accession No. ML043560382)

January 6, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Sections B.2.1.5 Chemistry Control Program - Response to

NRC Request for Additional Information (Accession No. ML050070179)

January 7, 2005 Letter from Mr. M. D. Skaggs, Tennessee Valley Authority (TVA) to the

NRC - Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License

Renewal Application - Meeting Summary and Plant Visit (ML050100180)
B-11

January 12, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Sections 4.7.1 Reactor Building Crane Load Cycle -

Response to NRC Request for Additional Information (Accession No.

ML050130333)

January 18, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Sections B.2.1.33 ASME Section XI Subsection IWF

Program - Response to NRC Request for Additional Information

(Accession No. ML050180505)

January 18, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Sections 2.5 and 3.6 Electrical and Instrument and Control -

Response to NRC Request for Additional Information (Accession No.

ML050180537)

January 20, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Section 3.1 Aging of Mechanical Systems During the

Extended Outage - Response to NRC Request for Additional Information

(Accession No. ML050210334)

January 24, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Section 2.4 - Response to NRC Request for Additional

Information (Accession No. ML050250264)

January 25, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Section 4.4 - Response to NRC Request for Additional

Information (Accession No. ML050260327)

January 27, 2005 Letter from Harold O. Christensen, NRC, to K. W. Singer, Tennessee

Valley Authority (TVA) regarding Browns Ferry Nuclear Plant - Inspection

Report 05000259/2004012, 05000260/2004012, and 05000296/2004012

(Accession No. ML050270022)

January 31, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application – Annual Update (Accession No. ML050310428)

January 31, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application – The Integration of Unit 1 Restart and License Renewal

Activities. Response to NRC Request for Additional Information

(Accession No. ML050320137)
B-12

January 31, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Sections 3.1, 4.2, and B.2.1 Reactor Vessel and Internals

Mechanical Systems - Response to NRC Request for Additional

Information (Accession No. ML050320145)

January 31, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Sections 3.5, 4.7.4, and B.2.1.32 - Response to NRC

Request for Additional Information (Accession No. ML050320149)

January 31, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Section 3 Unit 1 layup questions - Response to NRC

Request for Additional Information (Accession No. ML050320208)

January 31, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application – Section 2.1, status of response to RAI 2.1-2, A.3 -

Response to NRC Request for Additional Information (Accession No.

ML050310442)

February 28, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Section 2.1, final status of response to RAI 2.1-2, A.3 - 

Response to NRC Request for Additional Information (Accession No.

ML050600274)

February 28, 2005 Browns Ferry Nuclear Plant - Units 1, 2, and 3 License Renewal

Application - LRA Section 3.5 - response to NRC request for follow-up

question for RAI 3.5-7

March 2, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Sections 2.5 and 4.7.8 - Response to NRC Request for

Additional Information (Accession No. ML050620258)

March 3, 2005 Letter from Ram Subbaratnam, NRC, to K.W. Singer, Tennessee Valley

Authority (TVA) forwarding request for additional information for the

review of the BFN units 1, 2 and 3 license renewal application on

Section 4.7.7 of the LRA (Accession No. ML050620592)

March 11, 2005 Letter from Yoira Diaz-Sanabria, NRC, to K.W. Singer, Tennessee

Valley Authority (TVA) forwarding request for additional information for

the review of the BFN units 1, 2 and 3 license renewal application on

Sections 3.1.2.4 and 3.5 of the LRA (Accession No. ML050700309)
B-13

March 11, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Section 3.3 - Response to NRC Request for Additional

Information (Accession No. ML050700463)

March 16, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Sections 4.6.2 T-Quenchers within Reactor Vessel Vents

and Drains System - Response to NRC Request for Additional

Information (Accession No. ML050760230)

March 16, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Sections 3.1.2.4 and 4.3 Reactor Coolant Pressure

Boundary Bolting Clarifications - Response to NRC Request for

Additional Information (Accession No. ML050770041)

March 25, 2005 Letter from Ram Subbaratnam, NRC, to K.W. Singer, Tennessee Valley

Authority (TVA) forwarding request for additional information for the

review of the BFN units 1, 2 and 3 license renewal application on

Section 2.4 and 3.5 of the LRA (Accession No. ML050840483)

April 5, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Sections 7.2.5.2 ASME Equivalent Supports and

Components - Response to NRC Request for Additional Information

(Accession No. ML050950189)

April 5, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Sections 3.1.2.4-7 and 3.5-16 AMR Small Bore Piping and

Fittings and Submerged Reinforced Concrete - Response to NRC

Request for Additional Information (Accession No. ML050950311)

April 8, 2005 Letter from Ram Subbaratnam, NRC, to K.W. Singer, Tennessee Valley

Authority (TVA) Forwarding Request for Additional Information for the

Review of the BFN Units 1, 2, and 3 License Renewal Application on

Section 2.3.3.21 (Accession No. ML050980086)

April 14, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Sections 2.4 and 3.5 Radwaste and Service Building -

Response to NRC Request for Additional Information (Accession No.

ML051040164)

April 19, 005 Letter from Ram Subbaratnam, NRC, to K.W. Singer, Tennessee Valley

Authority (TVA) - Trip Report of staff visit to Browns Ferry Nuclear

Units 1,2, and 3 on March 28, 29, 2005 (Accession No. ML051090488)
B-14

April 28, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Section 2.3.3.21 Reactor Water Cleanup System -

Response to NRC Request for Additional Information (Accession No.

ML051190272)

May 12, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Section 7.2.5.2 ASME Equivalent Supports and Components

- Response to NRC Request for Additional Information (Accession No.

ML051330038)

May 18, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Sections 2.3 and 2.4 - Response to NRC Request for

Additional Information (Accession No. ML051380504)

May 18, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Section 3.0-9 Unit 1 Layup Program - Response to NRC

Request for Additional Information (Accession No. ML051390237)

May 19, 2005 Letter from Ram Subbaratnam, NRC, to K.W. Singer, Tennessee Valley

Authority (TVA) - Summary of teleconference with Tennessee Valley

Authority (TVA) License Renewal Staff ( Accession No. ML051400190)

May 24, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Section 2.3.3.21 Reactor Water Cleanup System -

Response to NRC Request for Additional Information (Accession No.

ML051440261)

May 24, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Section 3.3 Diesel Generator - Response to NRC Request

for Additional Information (Accession No. ML051440779)

May 24, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Sections 2.4, 3.5 and 4.7.4 - Response to NRC Request for

Additional Information (Accession No. ML051450126)

May 25, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Sections 7.1.19 and 7.1.22 GALL Audit - Response to NRC

Request for Additional Information (Accession No. ML051460348)
B-15

May 25, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Sections 4.2.6, 4.2.7 and 4.7.6 Reactor Pressure Vessel

Internals - Response to NRC Request for Additional Information

(Accession No. ML051460354)

May 26, 2005 Letter from Ram Subbaratnam, NRC, to K.W. Singer, Tennessee Valley

Authority (TVA) - Summary of teleconference with Tennessee Valley

Authority (TVA) License Renewal Staff (Accession No. ML051460418)

May 27, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Section 3.0 Unit 1 Layup Program - Response to NRC

Request for Additional Information (Accession No. ML051470354)

May 31, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Section 2.1.2 and 2.3.4.4 Secondary Containment and Main

Steam System - Response to NRC Request for Additional Information

(Accession No. ML051520081)

May 31, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Section 4.7.7 TLAA Core Plate Relaxation of Bolts -

Response to NRC Request for Additional Information (Accession No.

ML051520139)

May 31, 2005 Letter from Mr. M D. Skaggs, Tennessee Valley Authority (TVA) to the

NRC - Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License

Renewal Application (LRA) - Response to NRC Request for Additional

Information (RAI) concerning follow up to RAIs 2.4-3, 3.5-1, 3.5-4,

B.2.1.33-1, and B.2.1.36 (Accession No. ML051520084)

May 31, 2005 Letter from M.L. Marshall, Jr., NRC, to K W. Singer, Tennessee Valleu

Authority (TVA) - Browns Ferry Nuclear Plant Unit 1 - Safety Evaluation

for Relief Request 1-ISI-19 Associated With Reactor Pressure Vessel

Circumferential Shell Welds (Accession No. ML051110626)

June 3, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application –Response to NRC Request for Additional Information on

Potential Open Item 3.3.2.35-1 (Accession No. ML051540336)

June 9, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application – Response to NRC Request for Additional Information (RAI)

4.7.3-1-Radiation Dose for Valve Seals (Accession No. ML051610400)
B-16

June 9, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application – Response to NRC Request for Additional Information (RAI)

Concerning follow up to RAI 2.3.3.18-1 and follow up to

RAI 2.3.3.22-1(Accession No. ML051610592)

June 15, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application – Response to NRC Request for Additional Information (RAI)

for the Time-limited Aging Analysis identified in 4.7.2 and 4.7.5 of LRA

(Accession No. ML051660547)

June 15, 2005 Letter from Mr. T.E.Abney, Tennessee Valley Authority (TVA) to the NRC

- Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application – Response to NRC Request for Additional Information (RAI)

on Clarification for Item 2 of RAI 2.3-2 and RAI 2.3-3 (Accession No.

ML051670564)

June 22, 2005 Letter from Ram Subbaratnam, NRC, to K.W. Singer, Tennessee Valley

Authority (TVA) - Request for Additional Information on Section 4.7.7

(Accession No. ML051730507)

June 29, 2005 Letter from Mr. W.D. Crouch, Tennessee Valley Authority (TVA) to the

NRC - Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License

Renewal Application – Response to NRC Request for Additional

Information (RAI) concerning Follow up to Section 4.7. 7 Time Limited

Aging Analysis RAIs (Accession No. ML0519402910)

August 2, 2005 Letter from Yoira Diaz Sanabria, NRC, to K.W. Singer, Tennessee Valley

Authority (TVA) - Summary of teleconference held on July 7, 2005, with

Tennessee Valley Authority (TVA) License Renewal Staff, Concerning

Information on Browns Ferry Nuclear Plant, Units 1, 2, and 3 License

Renewal Application (Accession No. ML052140646)

August 4, 2005 Letter from Mr. W.D. Crouch, Tennessee Valley Authority (TVA) to the

NRC - Browns Ferry Nuclear Plant - Units 1, 2, and 3 License Renewal

Application - Description of Unit 1 Periodic Inspection Program

(Accession No. ML052170406)

August 9, 2005 Letter from P.T. Kuo, NRC, to K.W. Singer, Tennessee Valley Authority

(TVA) - Safety Evaluation Report (SER) with Open Items Related to the

License Renewal of Browns Ferry Nuclear Plant, Units 1, 2, and 3

(Accession No. ML052210459)

August 9, 2005 Letter from Mr. Brian O’Grady, Browns Ferry Nuclear Plant to the NRC -

Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 - Consolidated List

of Commitments for License Renewal (Accession No. ML052220070)
B-17

September 6, 2005 Letter from Mr. Brian O’Grady, Browns Ferry Nuclear Plant to the NRC -

Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal

Application - Response to NRC Request for Additional Information

Concerning Follow-Up to RAIs 4.7.7-1 and 4.7.7-2 (Accession No.

ML052570462)

September 14, 2005 Letter from Mr. Brian O’Grady, Tennessee Valley Authority (TVA) to the

NRC - Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License

Renewal Application - Results of Review of Safety Evaluation Report

(SER) with Open Items Related to License Renewal of Browns Ferry

Nuclear Plant (Accession No. ML052630075)

October 31, 2005 Letter from Yoira Diaz Sanabria, NRC, to K.W. Singer, Tennessee Valley

Authority (TVA) - Summary of teleconference held on October 14 and 18,

2005, with Tennessee Valley Authority (TVA) License Renewal Staff,

Concerning Information on Browns Ferry Nuclear Plant, Units 1, 2, and 3

License Renewal Application (Accession No. ML053050358)

November 16, 2005 Letter from Mr. W.D. Crouch, Tennessee Valley Authority (TVA) to the

NRC - Browns Ferry Nuclear Plant - Units 1, 2, and 3 License Renewal

Application (LRA) - Supplemental Responses to NRC Requests

(Accession No. ML053320331)

November 21, 2005 Letter from Mr. W.D. Crouch, Tennessee Valley Authority (TVA) to the

NRC - Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License

Renewal Application – Response to NRC Request for Clarification for

BFN’s use of Linde 80 Weld Material on Unit 1. (Accession No.

ML053260542)

December 12, 2005 Letter from Mr. W.D. Crouch, Tennessee Valley Authority (TVA) to the

NRC - Browns Ferry Units 1, 2, and 3 License Renewal Application (LRA)

- Response to NRC Request for Clarification of Commitment Tables

Contained in the Safety Evaluation Report (Accession No. ML053460417)

December 20, 2005 Letter from Mr. W.D. Crouch, Tennessee Valley Authority (TVA) to the

NRC - Browns Ferry Units 1, 2, and 3 License Renewal Application (LRA)

- Response to NRC Request for Clarification of Commitment Tables

Contained in the Safety Evaluation Report (Accession No. 053560328)
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C-1

APPENDIX C

PRINCIPAL CONTRIBUTORS

NAME RESPONSIBILITY

R. Subbaratnam

Y. Diaz Sanabria

K. Naidu

G. Galleti

B. Rogers

S. Jones

J. Guo

F. Akstulewicz

M. Razzaque

R. Dennig

R. Goel

J. Raval

S. Weerakkody

N. Iqbal

K. Manoly

D. Jeng

H. Ashar

A. Lee

Y. Li

S. Bailey

R. McNally

M. Hartzman

R. Jenkins

A. Pal

G. Cranston

T. Chan

R. Davis

S. Coffin

M. Mitchell

B. Elliot

G. Cheruvenki

L. Lambros

L. Lund

K. Parczewski

A. Hodgdon

Project Manager

Project Manager

Quality Assurance

Quality Assurance

Quality Assurance

Management Supervision

Plant Systems

Management Supervision

Reactor Systems

Management Supervision

Plant Systems

Plant Systems

Management Supervision

Plant Systems

Management Supervision

Civil Engineering

Civil Engineering

Mechanical Engineering

Mechanical Engineering

Mechanical Engineering

Mechanical Engineering

Mechanical Engineering

Management Supervision

Electrical Engineering

Technical Support

Management Supervision

Materials Engineering

Management Supervision

Management Supervision

Materials Engineering

Materials Engineering

Materials Engineering

Management Supervision

Chemical Engineering

Office of General Council

CONTRACTORS

CONTRACTOR TECHNICAL AREA

Brookhaven National Laboratory GALL Audit 

Information Systems Laboratories Plant Systems

Legin Group, Inc. SER Support
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D-1

APPENDIX D

 REFERENCES

This appendix contains a listing of references used in the preparation of the Safety Evaluation

Report prepared during the review of the license renewal application for Browns Ferry Nuclear

Plant, Units 1, 2, and 3, Docket Numbers 50-259, 50-260, and 50-296, respectively.

 (1) NUREG-1800, “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-1801, “Generic Aging Lessons Learned Report (GALL),” April 2001

 (4) Browns Ferry Nuclear Plant, Units 1, 2, and 3, updated final safety analysis report

(UFSAR), Amendment 20.

 (5) BWR Vessel and Internals Project Report BWRVIP-25: “BWR Core Plate Inspection

and Flaw Evaluation Guidelines,” TR-107284, December 1996.

 (6) BWR Vessel and Internals Project Report BWRVIP-99: “Crack Growth Rates in

Irradiated Stainless Steels in BWR Internal Components,” TR-1003018, December

2001.