Safety Evaluation Report

Related to the License Renewal of 

Palo Verde Nuclear Generating 

Station, Units 1, 2, and 3

Docket Numbers 50-528, 50-529, and 50-530

Arizona Public Service Company 

Office of Nuclear Reactor Regulation 

NUREG-1961
Safety Evaluation Report

Related to the License Renewal of 

Palo Verde Nuclear Generating

Station, Units 1, 2, and 3

Docket Numbers 50-528, 50-529, and 50-530

Arizona Public Service Company

Manuscript Completed: March 2011

Date Published: April 2011 

Office of Nuclear Reactor Regulation 

NUREG-1961
 

 
 

 iii 

ABSTRACT 

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

Generating Station, Units 1, 2, and 3 (PVNGS), license renewal application (LRA) by the 

U.S. Nuclear Regulatory Commission (NRC) staff (the staff). By letter dated 

December 11, 2008, and supplemented by letter dated April 14, 2009, Arizona Public Service 

Company (APS) (the applicant) submitted the LRA in accordance with Title 10 of the Code of 

Federal Regulations, Part 54 “Requirements for Renewal of Operating Licenses for Nuclear 

Power Plants.” APS requests renewal of the PVNGS operating licenses (facility operating 

license numbers NPF-41, NPF-51, and NPF-74) for a period of 20 years beyond the current 

expiration dates of midnight on June 1, 2025, for Unit 1; April 24, 2026, for Unit 2; and 

November 25, 2027, for Unit 3. 

PVNGS is a three-unit, nuclear-powered, steam electric generating facility located in Maricopa 

County, AZ, approximately 26 miles west of the Phoenix metropolitan area boundary. The NRC 

issued the construction permits on May 25, 1976, for all three units, and it issued the operating 

licenses on June 1, 1985, for Unit 1; April 24, 1986, for Unit 2; and November 25, 1987, for 

Unit 3. PVNGS employs a pressurized water reactor (PWR) design with a dry ambient 

containment. Each of the units uses a System 80 PWR nuclear steam supply system provided 

by Combustion Engineering, Incorporated. Bechtel Power Corporation is responsible for the 

engineering and construction of the station and designed the balance of the plant. The licensed 

power output is 3,990 megawatts-thermal per unit with a net electrical output of approximately 

1,346 megawatts-electric per unit. 

On August 6, 2010, the staff issued an SER with Open Item Related to the License Renewal of 

Palo Verde Nuclear Generating Station, Units 1, 2, and 3, in which the staff identified one open 

item and five confirmatory items necessitating further review. This SER presents the status of 

the staff’s review of information submitted through March 17, 2011, the cutoff date for 

consideration in the SER. The open and confirmatory items identified in the SER with Open 

Item were resolved before the staff made a final determination. SER Sections 1.5 and 1.6 

summarize these open and confirmatory items. SER Section 6.0 provides the staff’s final 

conclusion of the LRA review. 
 
 

 v 

TABLE OF CONTENTS 

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

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

List of Tables ............................................................................................................................... xii

Abbreviations ............................................................................................................................. xiii

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

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

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

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

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

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

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

1.5 Summary of Open Items .................................................................................... 1-6 

1.6 Summary of Confirmatory Items ....................................................................... 1-10 

1.7 Summary of Additional Items............................................................................ 1-12 

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

2.0 Scoping and Screening Methodology .................................................................................. 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 

2.1.3 Scoping and Screening Program Review ............................................ 2-2 

2.1.3.1 Implementation Procedures and Documentation Sources 

for Scoping and Screening .................................................. 2-3 

2.1.3.2 Quality Controls Applied to License Review Application 

Development ....................................................................... 2-6 

2.1.3.3 Training ............................................................................... 2-7 

2.1.3.4 Conclusion of Scoping and Screening Program Review ..... 2-8 

2.1.4 Plant Systems, Structures, and Components Scoping Methodology .. 2-8 

2.1.4.1 Application of the Scoping Criteria in 10 CFR 54.4(a)(1) .... 2-8 

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

2.1.4.3 Application of the Scoping Criteria in 10 CFR 54.4(a)(3) .. 2-18 

2.1.4.4 Plant-Level Scoping of Systems and Structures ............... 2-22 

2.1.4.5 Mechanical Scoping .......................................................... 2-23 

2.1.4.6 Structural Scoping ............................................................. 2-25 

2.1.4.7 Electrical Component Scoping .......................................... 2-26 

2.1.4.8 Scoping Methodology Conclusion ..................................... 2-27 

2.1.5 Screening Methodology ..................................................................... 2-27 

2.1.5.1 General Screening Methodology ....................................... 2-27 

2.1.5.2 Mechanical Component Screening ................................... 2-29 

2.1.5.3 Structural Component Screening ...................................... 2-30 

2.1.5.4 Electrical Component Screening ....................................... 2-31 

2.1.5.5 Screening Methodology Conclusion .................................. 2-33 

2.1.6 Summary of Evaluation Findings ....................................................... 2-33 

2.2 Plant-Level Scoping Results ............................................................................ 2-33 

2.2.1 Introduction ........................................................................................ 2-33 

2.2.2 Summary of Technical Information in the Application........................ 2-33 
Table of Contents 

 vi 

2.2.3 Staff Evaluation ................................................................................. 2-33 

2.2.4 Conclusion ......................................................................................... 2-35 

2.3 Scoping and Screening Results: Mechanical Systems ................................... 2-35 

2.3.1 Reactor Vessel, Internals, and Reactor Coolant System................... 2-35 

2.3.1.1 Reactor Vessel and Internals ............................................ 2-36 

2.3.1.2 Reactor Coolant System ................................................... 2-37 

2.3.1.3 Pressurizer ........................................................................ 2-38 

2.3.1.4 Steam Generators ............................................................. 2-39 

2.3.1.5 Reactor Core ..................................................................... 2-40 

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

2.3.2.1 Containment Leak Test System ........................................ 2-41 

2.3.2.2 Containment Purge System .............................................. 2-41 

2.3.2.3 Containment Hydrogen Control System ............................ 2-42 

2.3.2.4 Safety Injection and Shutdown Cooling System ................ 2-42 

2.3.3 Auxiliary Systems .............................................................................. 2-43 

2.3.3.1 Fuel Handling and Storage System ................................... 2-45 

2.3.3.2 Spent Fuel Pool Cooling and Cleanup System ................. 2-45 

2.3.3.3 Essential Cooling Water System ....................................... 2-47 

2.3.3.4 Essential Chilled Water System ........................................ 2-48 

2.3.3.5 Normal Chilled Water System ........................................... 2-49 

2.3.3.6 Nuclear Cooling Water System ......................................... 2-50 

2.3.3.7 Essential Spray Pond System ........................................... 2-52 

2.3.3.8 Nuclear Sampling System ................................................. 2-53 

2.3.3.9 Compressed Air System .................................................... 2-54 

2.3.3.10 Chemical Volume and Control System .............................. 2-55 

2.3.3.11 Control Building Heating, Ventilation, and Air 

Conditioning System ......................................................... 2-57 

2.3.3.12 Auxiliary Building Heating, Ventilation, and Air 

Conditioning System ......................................................... 2-58 

2.3.3.13 Fuel Building Heating, Ventilation, and Air Conditioning 

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

2.3.3.14 Containment Building Heating, Ventilation, and Air 

Conditioning System ......................................................... 2-59 

2.3.3.15 Diesel Generator Building Heating, Ventilation, and Air 

Conditioning System ......................................................... 2-60 

2.3.3.16 Radwaste Building Heating, Ventilation, and Air 

Conditioning System ......................................................... 2-61 

2.3.3.17 Turbine Building Heating, Ventilation, and Air 

Conditioning System ......................................................... 2-61 

2.3.3.18 Miscellaneous Site Structures and Spray Pond Pump 

House Heating, Ventilation, and Air Conditioning 

System .............................................................................. 2-62 

2.3.3.19 Fire Protection System ...................................................... 2-63 

2.3.3.20 Diesel Generator Fuel Oil Storage and Transfer 

System .............................................................................. 2-70 

2.3.3.21 Diesel Generator ............................................................... 2-70 

2.3.3.22 Domestic Water System .................................................... 2-72 

2.3.3.23 Demineralized Water System ............................................ 2-73 

2.3.3.24 Water Reclamation Facility Fuel System ........................... 2-74 

2.3.3.25 Service Gases (Nitrogen and Hydrogen) System ............. 2-75 

2.3.3.26 Gaseous Radwaste System .............................................. 2-76 

2.3.3.27 Radioactive Waste Drains System .................................... 2-76 
Table of Contents 

 vii 

2.3.3.28 Station Blackout Generator System .................................. 2-78 

2.3.3.29 Cranes, Hoists, and Elevators ........................................... 2-78 

2.3.3.30 Miscellaneous Auxiliary Systems In-Scope ONLY for 

Criterion 10 CFR 54.4(a)(2) ............................................... 2-79 

2.3.4 Steam and Power Conversion Systems ............................................ 2-81 

2.3.4.1 Main Steam System .......................................................... 2-81 

2.3.4.2 Condensate Storage and Transfer System ....................... 2-83 

2.3.4.3 Auxiliary Feedwater System .............................................. 2-84 

2.3.4.4 Condensate System .......................................................... 2-85 

2.3.4.5 Feedwater System ............................................................ 2-85 

2.3.4.6 Main Turbine System ........................................................ 2-86 

2.3.4.7 Steam Generator Feedwater Pump Turbine System ........ 2-86 

2.3.4.8 Feedwater Heater Extraction, Drains, and Vents 

System .............................................................................. 2-87 

2.4 Scoping and Screening Results: Structures .................................................... 2-87 

2.4.1 Containment Building ........................................................................ 2-88 

2.4.1.1 Summary of Technical Information in the Application ....... 2-88 

2.4.1.2 Staff Evaluation ................................................................. 2-89 

2.4.1.3 Conclusion ......................................................................... 2-89 

2.4.2 Control Building ................................................................................. 2-90 

2.4.2.1 Summary of Technical Information in the Application ....... 2-90 

2.4.2.2 Staff Evaluation and Conclusion ....................................... 2-90 

2.4.3 Diesel Generator Building .................................................................. 2-90 

2.4.3.1 Summary of Technical Information in the Application ....... 2-90 

2.4.3.2 Staff Evaluation and Conclusion ....................................... 2-90 

2.4.4 Turbine Building ................................................................................. 2-91 

2.4.4.1 Summary of Technical Information in the Application ....... 2-91 

2.4.4.2 Staff Evaluation ................................................................. 2-91 

2.4.4.3 Conclusion ......................................................................... 2-91 

2.4.5 Auxiliary Building ............................................................................... 2-92 

2.4.5.1 Summary of Technical Information in the Application ....... 2-92 

2.4.5.2 Staff Evaluation ................................................................. 2-92 

2.4.5.3 Conclusion ......................................................................... 2-92 

2.4.6 Radwaste Building ............................................................................. 2-92 

2.4.6.1 Summary of Technical Information in the Application ....... 2-92 

2.4.6.2 Staff Evaluation and Conclusion ....................................... 2-93 

2.4.7 Main Steam Support Structure .......................................................... 2-93 

2.4.7.1 Summary of Technical Information in the Application ....... 2-93 

2.4.7.2 Staff Evaluation and Conclusion ....................................... 2-93 

2.4.8 Station Blackout Generator Structures .............................................. 2-94 

2.4.8.1 Summary of Technical Information in the Application ....... 2-94 

2.4.8.2 Staff Evaluation and Conclusion ....................................... 2-94 

2.4.9 Fuel Building ...................................................................................... 2-94 

2.4.9.1 Summary of Technical Information in the Application ....... 2-94 

2.4.9.2 Staff Evaluation ................................................................. 2-95 

2.4.9.3 Conclusion ......................................................................... 2-95 

2.4.10 Spray Pond and Associated Water Control Structures ...................... 2-95 

2.4.10.1 Summary of Technical Information in the Application ....... 2-95 

2.4.10.2 Staff Evaluation and Conclusion ....................................... 2-96 

2.4.11 Tank Foundations and Shells ............................................................ 2-96 

2.4.11.1 Summary of Technical Information in the Application ....... 2-96 

2.4.11.2 Staff Evaluation and Conclusion ....................................... 2-96 
Table of Contents 

 viii 

2.4.12 Transformer Foundations and Electrical Structures .......................... 2-96 

2.4.12.1 Summary of Technical Information in the Application ....... 2-96 

2.4.12.2 Staff Evaluation ................................................................. 2-97 

2.4.12.3 Conclusion ......................................................................... 2-97 

2.4.13 Yard Structures (In-Scope) ................................................................ 2-97 

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

2.4.13.2 Staff Evaluation ................................................................. 2-98 

2.4.13.3 Conclusion ......................................................................... 2-98 

2.4.14 Supports ............................................................................................ 2-99 

2.4.14.1 Summary of Technical Information in the Application ....... 2-99 

2.4.14.2 Staff Evaluation and Conclusion ....................................... 2-99 

2.4.15 Fire Barriers ....................................................................................... 2-99 

2.4.15.1 Summary of Technical Information in the Application ....... 2-99 

2.4.15.2 Staff Evaluation ............................................................... 2-100 

2.4.15.3 Conclusion ....................................................................... 2-101 

2.5 Scoping and Screening Results: Electrical and Instrumentation and 

Control Systems ............................................................................................. 2-101 

2.5.1 Electrical and Instrumentation and Control Systems Component 

Groups ............................................................................................. 2-102 

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

2.5.1.2 Staff Evaluation ............................................................... 2-103 

2.5.1.3 Conclusion ....................................................................... 2-104 

2.6 Conclusion for Scoping and Screening .......................................................... 2-104 

3.0 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 1s ........................................................... 3-2 

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

3.0.2 Staff’s Review Process ........................................................................ 3-3 

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

3.0.2.2 Review of Aging Management Review Results ................... 3-5 

3.0.2.3 Updated Final Safety Analysis Report Supplement ............ 3-6 

3.0.2.4 Documents Reviewed ......................................................... 3-6 

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

3.0.3.1 Aging Management Programs Consistent with the 

Generic Aging Lessons Learned Report ............................. 3-9 

3.0.3.2 Aging Management Programs Consistent with the 

Generic Aging Lessons Learned Report, with 

Exceptions or Enhancements ............................................ 3-44 

3.0.3.3 Aging Management Programs Not Consistent with or 

Not Addressed in the Generic Aging Lessons 

Learned Report ............................................................... 3-128 

3.0.4 Quality Assurance Program Attributes Integral to Aging 

Management Programs ................................................................... 3-134 

3.0.4.1 Summary of Technical Information in the Application ..... 3-134 

3.0.4.2 Staff Evaluation ............................................................... 3-134 

3.0.4.3 Conclusion ....................................................................... 3-135 

3.1 Aging Management of Reactor Vessel, Internals and Reactor Coolant 

System ........................................................................................................... 3-136 

3.1.1 Summary of Technical Information in the Application...................... 3-136 

3.1.2 Staff Evaluation ............................................................................... 3-136 
Table of Contents 

 ix 

3.1.2.1 Aging Management Review Results Consistent with 

the Generic Aging Lessons Learned Report ................... 3-151 

3.1.2.2 Aging Management Review Results Consistent with 

the Generic Aging Lessons Learned Report for Which 

Further Evaluation Is Recommended .............................. 3-158 

3.1.2.3 Aging Management Review Results Not Consistent 

with or Not Addressed in the Generic Aging Lessons 

Learned Report ............................................................... 3-179 

3.1.3 Conclusion ....................................................................................... 3-181 

3.2 Aging Management of Engineered Safety Features Systems ........................ 3-181 

3.2.1 Summary of Technical Information in the Application...................... 3-181 

3.2.2 Staff Evaluation ............................................................................... 3-181 

3.2.2.1 Aging Management Review Results Consistent with 

the Generic Aging Lessons Learned Report ................... 3-189 

3.2.2.2 Aging Management Review Results Consistent with 

the Generic Aging Lessons Learned Report for Which 

Further Evaluation Is Recommended .............................. 3-196 

3.2.2.3 Aging Management Review Results Not Consistent 

with or Not Addressed in the Generic Aging Lessons 

Learned Report ............................................................... 3-203 

3.2.3 Conclusion ....................................................................................... 3-206 

3.3 Aging Management of Auxiliary Systems ....................................................... 3-206 

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

3.3.2 Staff Evaluation ............................................................................... 3-207 

3.3.2.1 Aging Management Review Results Consistent with 

the Generic Aging Lessons Learned Report ................... 3-221 

3.3.2.2 Aging Management Review Results Consistent with 

the Generic Aging Lessons Learned Report for Which 

Further Evaluation Is Recommended .............................. 3-230 

3.3.2.3 Aging Management Review Results Not Consistent 

with or Not Addressed in the Generic Aging Lessons 

Learned Report ............................................................... 3-250 

3.3.3 Conclusion ....................................................................................... 3-269 

3.4 Aging Management of Steam and Power Conversion Systems ..................... 3-269 

3.4.1 Summary of Technical Information in the Application...................... 3-269 

3.4.2 Staff Evaluation ............................................................................... 3-270 

3.4.2.1 Aging Management Review Results Consistent with 

the Generic Aging Lessons Learned Report ................... 3-275 

3.4.2.2 Aging Management Review Results Consistent with 

the Generic Aging Lessons Learned Report for Which 

Further Evaluation Is Recommended .............................. 3-279 

3.4.2.3 Aging Management Review Results Not Consistent 

with or Not Addressed in the Generic Aging Lessons 

Learned Report ............................................................... 3-288 

3.4.3 Conclusion ....................................................................................... 3-291 

3.5 Aging Management of Structures and Component Supports ......................... 3-291 

3.5.1 Summary of Technical Information in the Application...................... 3-291 

3.5.2 Staff Evaluation ............................................................................... 3-292 

3.5.2.1 Aging Management Review Results Consistent with 

the Generic Aging Lessons Learned Report ................... 3-303 
Table of Contents 

 x 

3.5.2.2 Aging Management Review Results Consistent with 

the Generic Aging Lessons Learned Report for Which 

Further Evaluation Is Recommended .............................. 3-306 

3.5.2.3 Aging Management Review Results Not Consistent 

with or Not Addressed in the Generic Aging Lessons 

Learned Report ............................................................... 3-321 

3.5.3 Conclusion ....................................................................................... 3-327 

3.6 Aging Management of Electrical and Instrumentation and Controls ............... 3-328 

3.6.1 Summary of Technical Information in the Application...................... 3-328 

3.6.2 Staff Evaluation ............................................................................... 3-328 

3.6.2.1 Aging Management Review Results Consistent with 

the Generic Aging Lessons Learned Report ................... 3-331 

3.6.2.2 Aging Management Review Results Consistent with 

the Generic Aging Lessons Learned Report for Which 

Further Evaluation Is Recommended .............................. 3-332 

3.6.2.3 Aging Management Review Results Not Consistent 

with or Not Addressed in the Generic Aging Lessons 

Learned Report ............................................................... 3-338 

3.6.3 Conclusion ....................................................................................... 3-338 

3.7 Conclusion for Aging Management Review Results ....................................... 3-338 

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

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

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

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

4.1.3 Staff Evaluation ................................................................................... 4-1 

4.1.4 Conclusion ......................................................................................... 4-12 

4.2 Reactor Vessel Neutron Embrittlement ............................................................ 4-12 

4.2.1 Neutron Fluence, Upper Shelf Energy and Adjusted Reference 

Temperature ...................................................................................... 4-13 

4.2.2 Pressurized Thermal Shock .............................................................. 4-16 

4.2.3 Pressure Temperature Limits ............................................................ 4-17

4.2.4 Low Temperature Overpressure Protection....................................... 4-19 

4.3 Metal Fatigue Analysis ..................................................................................... 4-19

4.3.1 Enhanced Fatigue Aging Management Program .............................. 4-21 

4.3.2 American Society of Mechanical Engineers III Fatigue Analysis of 

Class 1 Vessels, Piping, and Components ........................................ 4-42 

4.3.3 Fatigue and Cycle Based Time Limited Aging Analyses of American 

Society of Mechanical Engineers III, Subsection NG, Reactor Pressure 

Vessel Internals ................................................................................. 4-75 

4.3.4 Effects of the Reactor Coolant System Environment on Fatigue Life of 

Piping and Components (Generic Safety Issue 190)......................... 4-76 

4.3.5 Assumed Thermal Cycle Count for Allowable Secondary Stress Range 

Reduction Factor in American National Standards Institute B31.1 and 

American Society of Mechanical Engineers III Class 2 and 3 Piping 4-82 

4.4 Environmental Qualification of Electrical Equipment ........................................ 4-85 

4.4.1 Summary of Technical Information in the Application........................ 4-85 

4.4.2 Staff Evaluation ................................................................................. 4-86 

4.4.3 Updated Final Safety Analysis Report Supplement ........................... 4-86 

4.4.4 Conclusion ......................................................................................... 4-87 

4.5 Concrete Containment Tendon Prestress Analyses ......................................... 4-87 

4.5.1 Summary of Technical Information in the Application........................ 4-87 
Table of Contents 

 xi 

4.5.2 Staff Evaluation ................................................................................. 4-88 

4.5.3 Updated Final Safety Analysis Report Supplement ........................... 4-89 

4.5.4 Conclusion ......................................................................................... 4-89 

4.6 Containment Liner Plate, Equipment Hatch and Personnel Air Locks, 

Penetrations, and Polar Crane Brackets .......................................................... 4-90 

4.6.1 Absence of a Time Limited Aging Analysis for Containment Liner Plate, 

Polar Crane Brackets, Equipment Hatch and Personnel Air Locks, and 

Containment Penetrations (Except Main Steam, Main Feedwater, and 

Recirculation Sump Suction Penetrations) ........................................ 4-90 

4.6.2 Design Cycles for the Main Steam and Main Feedwater 

Penetrations ...................................................................................... 4-92 

4.6.3 Design Cycles for the Recirculation Sump Suction Line 

Penetrations ...................................................................................... 4-93 

4.7 Other Plant Specific Time Limited Aging Analyses .......................................... 4-94 

4.7.1 Load Cycle Limits of Cranes, Lifts, and Fuel Handling Equipment 

Designed to Crane Manufacturers Association of America 

Standard 70 ....................................................................................... 4-94 

4.7.2 Absence of Time Limited Aging Analyses for Metal Corrosion 

Allowances and Corrosion Effects ..................................................... 4-97 

4.7.3 Inservice Flaw Growth Analyses that Demonstrate Structural Stability 

for 40 Years ....................................................................................... 4-97 

4.7.4 Fatigue Crack Growth and Fracture Mechanics Stability Analyses of 

Half Nozzle Repairs to Alloy 600 Material in Reactor Coolant Hot Legs 

and Supporting Corrosion Analyses .................................................. 4-98 

4.7.5 Corrosion Analyses of Pressurizer Ferritic Materials Exposed to Reactor 

Coolant by Half Nozzle Repairs of Pressurizer Heater Sleeve Alloy 600 

Nozzles ............................................................................................ 4-103 

4.7.6 Absence of a Time Limited Aging Analysis for Reactor Vessel 

Underclad Cracking Analyses ......................................................... 4-104 

4.7.7 Absence of a Time Limited Aging Analysis for a Reactor Coolant 

Pump Flywheel Fatigue Crack Growth Analysis .............................. 4-104 

4.7.8 Building Absolute or Differential Heave or Settlement, Including 

Possible Effects of Changes in Perched Groundwater Lens ........... 4-104 

4.8 Absence of Time Limited Aging Analyses Supporting Title 10, Part 50.12, 

Exemptions, of the Code of Federal Regulations ........................................... 4-108 

4.9 Conclusion for Time Limited Aging Analyses ................................................. 4-108 

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

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

Appendix A: Palo Verde Nuclear Generating Station Units 1, 2, and 3 License Renewal 

Commitments ................................................................................................................ A-1 

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

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

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

 xii 

LIST OF TABLES 

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

Table 2.2-1 Missing Systems or Structures in Table 2.2 1 of the LRA .......................... 2-34 

Table 3.0-1 Aging Management Programs ...................................................................... 3-6 

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

 Reactor Coolant System Components in the GALL Report ..................... 3-137 

Table 3.2-1 Staff Evaluation for Engineered Safety Features Systems 

 Components in the GALL Report ............................................................. 3-182

Table 3.3-1 Staff Evaluation for Auxiliary System Components in the GALL 

Report ....................................................................................................... 3-208

Table 3.4-1 Staff Evaluation for Steam and Power Conversion Systems 

Components in the GALL Report ............................................................. 3-270

Table 3.5-1 Staff Evaluation for Structures and Component Supports 

Components in the GALL Report ............................................................. 3-293

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

the GALL Report ....................................................................................... 3-329

Table 4.1-1 Alloy 82/182 Dissimilar Metal Welds Mitigation ............................................ 4-9 

Table 4.3-1 Alloy 600 Small-Bore Hot Leg Nozzle Repairs ........................................... 4-62 

Table A-1 Palo Verde Nuclear Generating Station License Renewal Commitments ... A-1 
 
 

 xiii

ABBREVIATIONS 

ACI American Concrete Institute 

ACRS Advisory Committee on Reactor Safeguards 

ACSR aluminum conductor steel reinforced 

ACU air conditioning unit 

ADAMS Agencywide Document Access and Management System 

AERM aging effect requiring management 

AFW auxiliary feedwater 

AHU air handling unit 

AMP aging management program 

AMR aging management review 

ANSI American National Standards Institute 

APS Arizona Public Service Company 

ART adjusted reference temperature 

ASM American Society for Metals 

ASME American Society of Mechanical Engineers 

ASTM American Society for Testing and Materials 

ATWS anticipated transient without scram 

 

BTP branch technical position 

BWR boiling water reactor 

 

CASS cast austenitic stainless steel 

CBF cycle-based fatigue 

CC cycle counting 

CE Combustion Engineering, Incorporated 

CEA control element assembly 

CEDM control element drive mechanism 

CEOG Combustion Engineering Owners Group 

CFR Code of Federal Regulations 

CLB current licensing basis 

CMMA Crane Manufacturer's Association of America 

CSS core support structure 

CST condensate storage tank 

CTL Construction Technology Laboratories 

CUF cumulative usage factor 

CVCS chemical and volume control system 

 

DBA design basis accident 

DBE design basis event 

DG diesel generator 
Abbreviations 

 xiv 

 

ECCS emergency core cooling system 

EDG emergency diesel generator 

EFPY effective full-power year 

EOL end of life 

EPRI Electric Power Research Institute 

EQ environmental qualification 

ESF engineered safety feature 

ESP essential spray pond 

ETL electro-thermal link 

 

FAC flow-accelerated corrosion 

FR Federal Register 

FSAR final safety analysis report 

 

GALL Generic Aging Lessons Learned 

GEIS Generic Environmental Impact Statement 

GL generic letter 

GSI generic safety issue 

 

HELB high-energy line break 

HPSI high-pressure safety injection 

HVAC heating, ventilation, and air conditioning 

 

I&C instrumentation and controls 

IASCC irradiation assisted stress corrosion cracking 

IE Office of Inspection and Enforcement 

IGSCC intergranular stress corrosion cracking 

IN information notice 

IPA integrated plant assessment 

ISG interim staff guidance 

ISI inservice inspection 

ISO International Standardization Organization 

 

LBB leak-before-break 

LOCA loss of coolant accident 

LR license renewal 

LRA license renewal application 

LRDMT license renewal data management tool 

LTOP low temperature over pressure protection 

 

MEB metal enclosed bus 
 Abbreviations 

 xv 

MIC microbiologically-induced corrosion 

MNSA mechanical nozzle seal assembly 

MRV minimum required value 

MSSS main steam support structure 

 

NAS National Academy of Sciences 

NATM Nuclear Administrative Technical Manual 

NDE nondestructive examination 

NEI Nuclear Energy Institute 

NESC National Electrical Safety Code 

NFPA National Fire Protection Association 

NPF Nuclear Power Facility 

NRC U.S. Nuclear Regulatory Commission 

NSAC Nuclear Safety Analysis Center 

NSSS nuclear steam supply system 

NUREG NRC Technical Report Designation 

 

OBE operating-basis earthquake 

 

P&ID piping and instrumentation drawing 

PDT pressure differential transmitter 

PEC pulsed-eddy current 

PLL predicted lower limit 

P-T pressure-temperature 

PTS pressurized thermal shock 

PVC polyvinyl chloride 

PVNGS Palo Verde Nuclear Generating Station 

PWR pressurized water reactor 

PWSCC primary water stress corrosion cracking 

 

QA quality assurance 

 

RAI request for additional information 

RCP reactor coolant pump 

RCPB reactor coolant pressure boundary 

RCS reactor coolant system 

 

RFO refuel outage 

RG regulatory guide 

RIS regulatory information summary 

RMWT reactor makeup water tank 

RPV reactor pressure vessel 
Abbreviations 

 xvi 

RR relief request 

RTD resistance temperature detector 

RTNDT resistance temperature nil ductility transition 

RV reactor vessel 

RVID reactor vessel integrity database 

RWT refueling water tank 

 

SBF stress-based fatigue 

SBO station blackout 

SBOG station blackout generator 

SC structure and component 

SCC stress-corrosion cracking 

SE safety evaluation 

SER safety evaluation report 

SG steam generator 

SRP-LR Standard Review Plan-License Renewal 

SSC system, structure, and component 

SSE safe-shutdown earthquake 

SWMS site work management system 

 

TLAA time-limited aging analysis 

TR topical report 

TS technical specifications 

TSR Technical Requirements Manual Surveillance Requirement 

 

UFSAR Updated Final Safety Analysis Report 

UGS upper guide structure 

USE upper-shelf energy 

UT ultrasonic testing 

 

WCAP Westinghouse Commercial Atomic Power Report 

WRF water reclamation facility 
 

 1-1 

1.0 INTRODUCTION AND GENERAL DISCUSSION 

1.1 Introduction

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

Palo Verde Nuclear Generating Station, Units 1, 2, and 3 (PVNGS), as filed by Arizona Public 

Service Company (APS) (the applicant). By letter dated December 11, 2008, as supplemented 

by letter dated April 14, 2009, APS submitted its application to the U.S. Nuclear Regulatory 

Commission (NRC) for renewal of the PVNGS operating license for an additional 20 years. 

The NRC staff (the staff) prepared this report to summarize the results of its safety review of the 

LRA for compliance with Title 10, Part 54, “Requirements for Renewal of Operating Licenses for 

Nuclear Power Plants,” of the Code of Federal Regulations (10 CFR Part 54). The NRC project 

manager for the license renewal review is Ms. Lisa Regner. Ms. Regner may be contacted by 

telephone at 301-415-1906, or by electronic mail at Lisa.Regner@NRC.gov. Alternatively, 

written correspondence may be sent to the following address: 

Division of License Renewal 

U.S. Nuclear Regulatory Commission 

Washington, D.C., 20555-0001 

Attention: Lisa Regner, Mail Stop O11-F1 

In its December 11, 2008, submission letter, the applicant requested renewal of the operating 

licenses issued under Section 103 (Operating License Nos. NPF-41, NPF-51, and NPF-74) of 

the Atomic Energy Act of 1954, as amended, for PVNGS for a period of 20 years beyond the 

current expiration at midnight on June 1, 2025 (Unit 1), April 24, 2026 (Unit 2), and 

November 25, 2027 (Unit 3). 

PVNGS is located approximately 26 miles west of Phoenix, AZ. The NRC issued the 

construction permits on May 25, 1976, for all three units, and issued the operating licenses on 

June 1, 1985, for Unit 1; April 24, 1986, for Unit 2; and November 25, 1987, for Unit 3. PVNGS 

uses a pressurized water reactor (PWR) design with a dry ambient containment. Each of the 

PVNGS units uses a System 80 PWR nuclear steam supply system provided by Combustion 

Engineering, Incorporated (CE). Bechtel Power Corporation was responsible for the 

engineering and construction of the station and designed the balance of the plant. The licensed 

power output is 3,990 megawatts-thermal per unit with a net electrical output of approximately 

1,346 megawatts-electric per unit. The updated final safety analysis report (UFSAR) contains 

details of the plant and the site. 

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

issues and an environmental review. The NRC regulations in 10 CFR Part 54, “Requirements 

for Renewal of Operating Licenses for Nuclear Power Plants” and 10 CFR Part 51, 

“Environmental Protection Regulations for Domestic Licensing and Related Regulatory 

Functions,” respectively, set forth requirements for these reviews. The safety review for the 

PVNGS license renewal is based on the applicant’s LRA and on its responses to the staff’s 

requests for additional information (RAIs). The applicant supplemented the LRA and provided 

clarifications through its responses to the staff’s RAIs in audits, meetings, and docketed 

correspondence. On August 8, 2010, the staff issued an SER with Open Items related to the 

License Renewal of Palo Verde Nuclear Generating Station, Units 1, 2, and 3, in which the staff 

identified one open item for further review. Subsequently, the applicant amended the LRA and 

provided responses to the staff’s RAIs and docketed correspondence. Unless otherwise noted, 

the staff reviewed and considered information submitted through March 17, 2011. The staff 

reviewed information received after that date depending on the stage of the safety review and 

the volume and complexity of the information. 
Introduction and General Discussion 

 1-2 

The public may view the LRA and all pertinent information and materials at the NRC Public 

Document Room, located on the first floor of One White Flint North, 11555 Rockville Pike, 

Rockville, MD 20852-2738 (301-415-4737 or 800-397-4209), the Litchfield Park Branch Library, 

West Wigwam Boulevard, Litchfield Park, AZ 85340, and the Sam Garcia Western Avenue 

Library, 495 East Western Avenue, Avondale, AZ 85323. In addition, the public may find the 

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

http://www.nrc.gov/reactors/operating/licensing/renewal.html. 

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

technical details considered in evaluating the safety aspects of the unit’s 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 in NUREG-1800, Revision 1, 

“Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants” 

(SRP-LR), dated September 2005. 

SER Sections 2-4 address the staff’s evaluation of license renewal issues considered during the 

review of the application. SER Section 5 is reserved for the report of the Advisory Committee 

on Reactor Safeguards (ACRS). The conclusions of this SER are in Section 6. 

SER Appendix A is a table showing the applicant’s regulatory commitments for renewal of the 

operating licenses. SER Appendix B is a chronology of the principal correspondence between 

the staff and the applicant regarding the LRA review. SER Appendix C is a list of principal 

contributors to the SER, and Appendix D is a bibliography of the references in support of the 

staff’s review. 

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

NUREG-1437, “Generic Environmental Impact Statement for License Renewal of Nuclear 

Plants (GEIS).” This supplement discusses the environmental considerations for license 

renewal for PVNGS. The staff issued the draft, plant-specific GEIS, NUREG-1437, 

Supplement 44, “Generic Environmental Impact Statement for License Renewal of Nuclear 

Plants Regarding the Palo Verde Nuclear Generating Station, Units 1, 2, and 3 – Draft Report” 

in August of 2010. The final, plant-specific GEIS Supplement is scheduled to be issued in 

January 2011. 

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 and can be renewed for up to 

20 additional years. The original 40-year license term was selected based on economic and 

antitrust considerations rather than on technical limitations; however, some individual plant and 

equipment designs may have been engineered for 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. From the results of that research, a technical review group concluded that 

many aging phenomena are readily manageable and pose no technical issues precluding 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 10 CFR Part 54, the License Renewal Rule (Volume 56, 

page 64943, of the Federal Register (56 FR 64943), dated December 13, 1991). The staff 

participated in an industry-sponsored demonstration program to apply 10 CFR Part 54 to a pilot 

plant and to gain the experience necessary to develop implementation guidance. To establish a 

scope of review for license renewal, 10 CFR Part 54 defined age-related degradation unique to 
 Introduction and General Discussion 

 1-3 

license renewal. During the demonstration program, the staff found that adverse aging effects 

on plant systems and components are managed during the period of initial license and that the 

scope of the review did not allow sufficient credit for management programs. This was 

particularly true for the implementation of 10 CFR 50.65, “Requirements for Monitoring the 

Effectiveness of Maintenance at Nuclear Power Plants,” which regulates management of 

plant-aging phenomena. As a result of this finding, the staff amended 10 CFR Part 54 in 1995. 

As published in May 8, 1995 (60 FR 22461), the amended 10 CFR Part 54 establishes a 

regulatory process that is simpler, more stable, and more predictable than the previous 

10 CFR Part 54. In particular, as amended, 10 CFR Part 54 focuses on the management of 

adverse aging effects rather than on the identification of age-related degradation unique to 

license renewal. The staff made 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 amended 10 CFR Part 54 clarifies and simplifies 

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

long-lived structures and components (SCs). 

Concurrent with these initiatives, the staff pursued a separate rulemaking effort (61 FR 28467, 

June 5, 1996) and amended 10 CFR Part 51 to focus the scope of the review of environmental 

impacts of license renewal in order to fulfill NRC responsibilities under the National 

Environmental Policy Act of 1969. 

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 maintain an acceptable level of safety with the possible exceptions of 

the detrimental aging effects on the functions of certain SSCs, as well as a few other 

safety-related issues, during the period of extended operation. 

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

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

In implementing these two principles, 10 CFR 54.4, “Scope,” defines the scope of license 

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

safety-related functions, or (3) that are relied on to demonstrate compliance with the NRC’s 

regulations for fire protection, environmental qualification (EQ), pressurized thermal shock 

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

Pursuant to 10 CFR 54.21(a), a license renewal applicant must review all SSCs within the 

scope of 10 CFR Part 54 to identify SCs subject to an aging management review (AMR). Those 

SCs subject to an AMR perform an intended function without moving parts or without change in 

configuration or properties and are not subject to replacement based on a qualified life or 

specified time period. Pursuant to 10 CFR 54.21(a), a license renewal applicant must 

demonstrate that the aging effects will be managed such that the intended function(s) 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, detrimental aging effects that may affect 

active equipment can be readily identified and corrected through routine surveillance, 

performance monitoring, and maintenance. Surveillance and maintenance programs for active 

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

required throughout the period of extended operation. 
Introduction and General Discussion 

 1-4 

Pursuant to 10 CFR 54.21(d), the LRA is required to include an UFSAR supplement with a 

summary description of the applicant’s programs and activities for managing aging effects and 

an evaluation of time-limited aging analyses (TLAAs) for the period of extended operation. 

License renewal also requires TLAA identification and updating. During the plant design phase, 

certain assumptions about the length of time the plant can operate are incorporated into design 

calculations for several plant 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 aging 

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

In 2005, the NRC revised 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, Revision 6, “Industry Guideline for Implementing the Requirements 

of 10 CFR Part 54 - The License Renewal Rule,” issued in June 2005. NEI 95-10 details an 

acceptable method of implementing 10 CFR Part 54. The staff also used the SRP-LR to review 

the LRA. 

In the LRA, the applicant fully utilized the process defined in NUREG-1801, Revision 1, 

“Generic Aging Lessons Learned (GALL) Report,” dated September 2005. The GALL Report 

summarizes staff-approved aging management programs (AMPs) for many SCs subject to an 

AMR. If an applicant commits to implementing these staff-approved AMPs, they can greatly 

reduce the time, effort, and resources for LRA review, thus 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 is also a quick reference for both applicants and 

staff reviewers to AMPs and activities that can manage aging adequately during the period of 

extended operation. 

1.2.2 Environmental Review 

Part 51 of 10 CFR contains regulations on environmental protection regulations. In December 

1996, the staff revised the environmental protection regulations to facilitate the environmental 

review for license renewal. The staff prepared the GEIS to document its evaluation of possible 

environmental impacts associated with nuclear power plant license renewals. For certain types 

of environmental impacts, the GEIS contains generic findings that apply to all nuclear power 

plants and are codified in Appendix B, “Environmental Effect of Renewing the Operating License 

of a Nuclear Power Plant,” to Subpart A, “National Environmental Policy Act - Regulations 

Implementing Section 102(2),” of 10 CFR Part 51. Pursuant to 10 CFR 51.53(c)(3)(i), a license 

renewal applicant may incorporate these generic findings in its environmental report. In 

accordance with 10 CFR 51.53(c)(3)(ii), an environmental report also must include analyses of 

environmental impacts that must be evaluated on a plant-specific basis (i.e., Category 2 issues). 

In accordance with the National Environmental Policy Act of 1969 and 10 CFR Part 51, the staff 

reviewed the plant-specific environmental impacts of license renewal, including whether there 

was new and significant information not considered in the GEIS. As part of its scoping process, 

the staff held public meetings on June 25, 2009. One meeting was in the afternoon at Tonopah 

Valley High School, in Tonopah, AZ. The other was in the evening at Estrella Mountain 

Community College in Avondale, AZ. The purpose of these meetings was to seek comments 

from local stakeholders on plant-specific environmental issues. The draft, plant-specific GEIS, 

Supplement 44, documents the results of the environmental review and makes a preliminary 

recommendation as to the license renewal action. The staff held public meetings similar to the 

scoping meetings discussed above on September 15, 2010, in Tonopah and Avondale, AZ, to 

discuss the draft, plant-specific GEIS, Supplement 44. After considering all comments on the 
 Introduction and General Discussion 

 1-5 

draft GEIS received from stakeholders, the staff will publish the final, plant-specific GEIS 

currently scheduled for January 2011. 

1.3 Principal Review Matters

Part 54 of 10 CFR describes the requirements for the renewal of operating licenses for nuclear 

power plants. The staff’s technical review of the LRA was in accordance with NRC guidance 

and 10 CFR Part 54 requirements. Section 54.29, “Standards for Issuance of a Renewed 

License,” of 10 CFR sets forth the license renewal standards. This SER describes the results of 

the staff’s safety review. 

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

information, which the applicant provided in LRA Section 1. The staff reviewed LRA Section 1 

and finds that the applicant has submitted the required information. 

Pursuant to 10 CFR 54.19(b), the NRC requires that the 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.” On this issue, the applicant stated in the LRA: 

The current indemnity agreement for Palo Verde states in Article VII that the 

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

Item 3 of the Attachment to the agreement”. Item 3 of the Attachment to the 

indemnity agreement, as amended, lists license numbers NPF-41, NPF-51, 

and NPF-74. 

APS requests that conforming changes be made to the indemnity agreement, 

and/or the Attachment to the agreement, as required, to ensure that the 

indemnity agreement continues to apply during both the terms of the current 

licenses and the terms of the renewed licenses. APS understands that no 

changes may be necessary for this purpose if the current license numbers 

are retained. 

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

licenses, if approved. Therefore, no conforming changes need to be made to the indemnity 

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

Pursuant to 10 CFR 54.21, “Contents of Application - Technical Information,” the NRC requires 

that the LRA contain, (a) an integrated plant assessment, (b) a description of any CLB changes 

during the staff’s review of the LRA, (c) an evaluation of TLAAs, and (d) a final safety analysis 

report supplement. LRA Sections 3 and 4 and Appendix B address the license renewal 

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

requirements of 10 CFR 54.21(d). 

Pursuant to 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 

submit an LRA amendment identifying any CLB changes to the facility that affect the contents of 

the LRA, including the UFSAR supplement. By letter dated December 7, 2009, the applicant 

submitted an LRA update that summarizes the CLB changes that have occurred during the 

staff’s review of the LRA. The LRA was accepted for review on May 15, 2009 (74 FR 22978). 

This submission satisfies 10 CFR 54.21(b) requirements for the SER with Open Items. 

Pursuant to 10 CFR 54.22, “Contents of Application - Technical Specifications,” the NRC 

requires that the LRA include changes or additions to the technical specifications (TS) that are 

necessary to manage aging effects during the period of extended operation. In LRA 

Appendix D, the applicant stated that no changes to the TS are required to support the LRA. 

This statement adequately addresses the 10 CFR 54.22 requirement. 
Introduction and General Discussion 

 1-6 

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

accordance with NRC regulations and SRP-LR guidance. SER Sections 2, 3, and 4 document 

the staff’s evaluation of the LRA technical information. 

As required by 10 CFR 54.25, “Report of the Advisory Committee on Reactor Safeguards,” the 

ACRS will issue a report documenting its evaluation of the staff’s LRA review and SER. SER 

Section 5 is reserved for the ACRS report, when it is issued. SER Section 6 documents the 

findings required by 10 CFR 54.29. 

1.4 Interim Staff Guidance

License renewal is a living program. The 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 

incorporated into such license renewal guidance documents as the SRP-LR and GALL Report. 

Table 1.4-1 shows the current set of ISGs, as well as the SER sections in which the staff 

addresses them. 

Table 1.4-1. Current Interim Staff Guidance 

ISG Issue (Approved ISG Number) Purpose SER Section 

Nickel-alloy Components in the 

Reactor Coolant Pressure Boundary 

(LR-ISG-19B) 

To address the cracking of nickel-alloy components in the 

reactor pressure boundary 

(ISG is under development. NEI and the Electric Power 

Research Institute-modification/rework package will develop 

an augmented inspection program for GALL AMP XI.M11-B. 

This AMP will not be completed until the NRC approves an 

augmented inspection program for nickel-alloy base metal 

components and welds as proposed by Electric Power 

Research Institute-modification/rework package). 

3.0.3.3.1

Corrosion of Drywell Shell in Mark I 

Containments 

(LR-ISG-2006-01) 

To address concerns related to corrosion of drywell shell in 

Mark I containments 

Not applicable

Changes to GALL AMP XI.E6, 

“Electrical Cable Connections Not 

Subject to 10 CFR 50.49 

Environmental Qualification 

Requirements” 

(LR-ISG-2007-02) 

To address the frequency of inspection of electrical cable 

connections not subject to 10 CFR 50.49 before the period 

of extended operation. 

The staff has addressed industry comments and a notice of 

availability of the Final LR-ISG-2007-02 was published in 

the Federal Register. See 74 FR 68287, dated 

December 23, 2009. 

3.0.3.1.8

Aging Management of Spent Fuel 

Pool Neutron-Absorbing Materials 

Other than Boraflex 

(LR-ISG-2009-01) 

To provide guidance as to one acceptable approach for 

managing the effects of aging during the period of extended 

operation for certain neutron-absorbing spent fuel pool 

components within the scope of the License Renewal Rule 

(10 CFR Part 54, “Requirements for Renewal of Operating 

Licenses for Nuclear Power Plants”) 

Not applicable

1.5 Summary of Open Items

As a result of its review of the LRA, the staff identified the following open item. An item is 

considered open if, based on the applicant’s submittals, it does not meet all applicable 
 Introduction and General Discussion 

 1-7 

regulatory requirements at the time of the issuance of this SER. The staff has assigned a 

unique identifying number to this open item. 

Open Item 4.3-1

The staff’s review of LRA Section 4.3 “Metal Fatigue,” is inconclusive regarding the applicant’s 

compliance with regulatory requirements. The staff requires further information to reach a 

conclusion on the proposed metal fatigue analysis as discussed in detail in SER Section 4.3. 

The following presents a brief description of the RAIs that the staff has issued to the applicant: 

 Clarify which transients required a 25-percent occurrences assumption and justify why 

this assumption yields a conservative 60-year cycle basis (RAI 4.3-1). 

 Response: In a June 29, 2010, letter the applicant provided information including the 

transients for which it applied a 25-percent occurrences assumption. The applicant also 

provided justification that this assumption yields a conservative basis because the 

applicant performed a detailed review of plant documentation for occurrences of these 

transients. The staff’s detailed review is found in SER Section 4.3.1.4.2. 

 Explain why the cumulative usage factors (CUFs) for the instrument nozzles at Unit 1 

are 5 times greater than at Units 2 and 3 (RAI 4.3-2). 

 Response: In letters dated June 29, and October 13, 2010, the applicant provided 

information concerning dissimilarities in the CUFs for the instrument nozzles in Unit 1 

versus Units 2 and 3. The applicant stated the differences were due to variations in 

modeling and analysis methods and assumptions. The staff’s detailed review is found in 

SER Section 4.3.1.4.2. 

 Provide the allowable stress limits and stress ranges from the revised design analyses 

for the reactor coolant hot leg sample line piping and the steam generator (SG) 

downcomer and feedwater recirculation line piping (RAI 4.3-3). 

 Response: In a June 29, 2010, response, the applicant provided the requested 

information related to the reactor coolant hot leg sample line piping and the SG 

downcomer and feedwater recirculation line piping and the ASME Code allowable stress 

limits and stress range reduction factors. The staff’s detailed review is found in SER 

Section 4.3.5.2. 

 Demonstrate that the environmental factors used in analyzing the reactor pressure 

vessel components are the maximums for a given material and provide a basis and 

justification for any assumptions (RAI 4.3-4). 

 Response: In a June 29, 2010, response, the applicant stated that the “maximum 

applicable” Fen factors for the low alloy steel RPV shell and lower head, RPV inlet and 

outlet nozzles, and safety injection nozzle (forging knuckle) were all computed using the 

guidance in NUREG/CR-6583, “Effects of LWR Coolant Environments on Fatigue 

Design Curves of Carbon and Low-Alloy Steels.” The applicant also provided the basis 

and justification for assumptions used in the analysis. The staff’s detailed review is 

found in SER Section 4.3.4.2. 

 Describe the methodology used for the environmental factor calculation of the charging 

system nozzle and the safety injection nozzle and justify assumptions (RAI 4.3-5). 

 Response: In a June 29, 2010, response, the applicant provided the details of the 

methodology used to calculate a more accurate Fen value for the charging nozzle and 

safety injection nozzle. The staff’s detailed review is found in SER Section 4.3.4.2. 
Introduction and General Discussion 

 1-8 

 Justify using an environmental factor value of 1.49 for the nickel alloy pressurizer heater 

penetrations and describe plans to update the CUF calculation methodology consistent 

with NUREG/CR-6909 (RAI 4.3-6). 

 Response: In a June 29, 2010, response, the applicant committed to confirm the 

conservatism of its use of an Fen value of 1.49 or perform a reanalysis of the pressurizer 

heater penetrations using an Fen value calculated using the methodology in 

NUREG/CR-6909. The staff’s detailed review is found in SER Section 4.3.4.2. 

 Provide the monitoring basis for the pressurizer spray nozzles (RAI 4.3-7). 

 Response: In an August 12, 2010, response, the applicant clarified that the higher Fen

value for the surge line elbow will result in a higher environmentally-assisted fatigue 

usage factor compared to the pressurizer spray nozzle. Further, since the stratification 

effects on the surge line are only associated with the surge line elbow, this results in the 

surge line elbow as the bounding component compared to the pressurizer spray nozzle. 

The staff’s detailed review is found in SER Section 4.3.1.2.2. 

 Clarify whether Transient 17 (LRA Table 4.3-3) refers to initiation of the pressurizer 

spray system or containment spray system and provide the basis for correlating the 

tracking of this transient to Transient 12 (RAI 4.3-8). 

 Response: In an August 12, 2010, response, the applicant clarified that Transient 17 

refers to the initiation of auxiliary pressurizer spray and provided the relationship 

between Transient 17 and 12. The applicant explained the sequence of events to initiate 

auxiliary spray during cooldown which provided the basis for the correlation between the 

two transients. The staff’s detailed review is found in SER Section 4.3.1.4.2. 

 Clarify if the transient cycle counting procedure has been updated to include 

Transient 25 (LRA Table 4.3-3); if not, specify when it will be updated (RAI 4.3-9). 

 Response: In an August 12, 2010, response, the applicant stated that the 

cycle-counting surveillance procedure was updated to include Transient 25 (in 

Amendment 14 dated April 28, 2010) and the applicant’s enhanced Metal Fatigue 

Program will monitor this transient during the period of extended operation to ensure that 

it does not exceed the design limit. The staff’s detailed review is found in 

SER Section 4.3.1.4.2. 

 Clarify whether Transient 79 (LRA Table 4.3-3) is the American Society of Mechanical 

Engineers (ASME) Code Section XI required system leak test; if so, justify the number of 

occurrences stated in the LRA (RAI 4.3-10). 

 Response: In an August 12, 2010, letter, the applicant clarified that its operating 

practice is to perform the ASME Code Section XI leak test concurrently with a plant 

heatup without a separate thermal transient and, therefore, the fatigue effects are 

appropriately accounted for as a plant heatup transient and not as a separate leak test 

transient. Further, the applicant clarified that the ASME Code fatigue analyses account 

for the fatigue effects of plant heatup, cooldown, and ASME Code Section XI leak test as 

separate transients. The staff’s detailed review is found in SER Section 4.3.1.4.2. 

 Clarify the meaning of “significant contributors to usage factor” and how this is 

associated with the corrective action limits in the metal fatigue AMP (RAI 4.3-11). 

 Response: In an August 12, 2010, response, the applicant clarified that the “significant 

contributors” to fatigue include all transients listed in the UFSAR tables. The applicant 

also stated that the cycle counting corrective action limits associated with all transients 

listed in LRA Table 4.3-2 will be tracked by the enhanced Metal Fatigue Program. This 
 Introduction and General Discussion 

 1-9 

will ensure that the assumptions made in the analyses of record and design limits are 

not exceeded. The staff’s detailed review is found in SER Section 4.3.1.5.2. 

 Clarify whether the scope of corrective actions for CUF monitoring includes both ASME 

Code Class 1 components and ASME Code Class 2 components analyzed to Class 1 

requirements; if not, provide justification (RAI 4.3-12). 

 Response: In letters dated July 21 and August 12, 2010, the applicant clarified that the 

scope of the enhanced Metal Fatigue Program includes all components, including 

Class 2 and 3 components, with a CUF analysis. Further, the applicant’s program will 

ensure that the design limit of 1.0 is not exceeded or corrective actions will be taken to 

reanalyze, repair, or replace the component before the design limit is exceeded. 

The staff’s detailed review is found in SER Section 4.3.1.4.2. 

 Justify why the SG tubes CUF calculation is not a TLAA and provide the basis for the 

CUF value of zero; justify omitting AMR items for pressurizer components cumulative 

fatigue damage; justify omitting AMR items for ASME Code Class 2 and 3 or American 

National Standards Institute (ANSI) B31.1 components cumulative fatigue damage 

(RAI 4.3-13). 

 Response: In an August 12, 2010, response, the applicant stated that the SG tube CUF 

value was taken from the applicable design report for each unit. The applicant further 

clarified that the zero value for the SG tube CUF is based on the cyclic stress range 

being below the endurance limit. Also, the applicant amended LRA Table 3.1.2-4 to 

include the ANSI B31.1 component AMR items. The staff’s detailed review is found in 

SER Sections 3.1.2.2.1, 3.2.2.2.1, 3.3.2.2.1, and 3.4.2.2.1. 

 Clarify whether cycle-based monitoring will be performed on reactor pressure vessel 

studs only (not lugs); if so, provide the transients contributing to fatigue usage and 

quantify the contribution for both studs and lugs (RAI 4.3-14). 

 Response: In an August 12, 2010, response, the applicant stated that both RPV studs 

and RPV external bottom head shear lugs will be monitored individually by cycle 

counting, and action limits for the enhanced Metal Fatigue Program will be established to 

allow for corrective actions before the design basis number of events is exceeded. 

The staff’s detailed review is found in SER Section 4.3.2.1.2. 

 Identify the type of low cycle fatigue analysis referred to in LRA Sections 4.3.2.7 

and 4.3.2.8 and justify why the low-cycle fatigue analysis is not a TLAA (RAI 4.3-15). 

 Response: In an August 12, 2010, response, the applicant stated that the low cycle 

fatigue analysis referred to in LRA Sections 4.3.2.7 and 4.3.2.8 is not a TLAA and does 

not contain an implicit fatigue analysis, cycle-based fatigue flaw growth, or cycle-based 

fracture mechanics analysis. The staff’s detailed review is found in SER 

Section 4.1.3.1.5. 

 Clarify the current design basis CUF values and limits for the transients evaluated for the 

regenerative and letdown heat exchangers (RAI 4.3-16). 

 Response: In an August 12, 2010, response, the applicant provided the design basis 

CUFs for the components. In the response, the applicant also explained the design 

basis transients analyzed and associated limits for the transients. During the review of 

the analyses of record for the heat exchangers, the applicant noted that the analysis 

assumed a higher number of cycles for significant design transients and a lower number 

of cycles for less significant transients than those stated in the UFSAR for several 

transients. The applicant stated that none of the transient limits have been challenged 

by current operating history. The applicant also stated that the inconsistency between 
Introduction and General Discussion 

 1-10 

the transient assumptions in the UFSAR and those in the analyses are in the applicant's 

corrective action process for evaluation. The staff’s detailed review is found in SER 

Section 4.3.2.10.2. 

 Identify which reactor vessel internal components are designed to ASME Section III NG 

requirements and which require a CUF design calculation; for those required, provide 

the design basis CUF values and limits for the transients evaluated; justify the use of 

cycle-based monitoring for those with high CUF values (RAI 4.3-17). 

 Response: In an August 12, 2010, response, the applicant identified the ASME Code 

Section III, Subsection NG reactor vessel internal components and clarified the design 

basis CUFs and transients for those components. Further, the applicant stated it will use 

cycle counting in its enhanced Metal Fatigue Program to track these transients to ensure 

that when action limits are reached that corrective actions are taken to maintain fatigue 

usage below the design limit of 1.0. The staff’s detailed review is found in SER 

Section 4.3.3.2. 

 Identify the source documents for the equation references in LRA Section 4.3.5 and 

identify the analysis of record for the recirculating SG downcomer and feedwater 

recirculation lines (RAI 4.3-18). 

 Response: In a August 12, 2010, response, the applicant clarified that the 7000-thermal 

cycles fatigue analysis is the analysis of record for the recirculating SG downcomer and 

feedwater recirculation lines and has been identified as a TLAA consistent with 

10 CFR 54.21(c)(1). The staff’s detailed review is found in SER Section 4.3.5.2. 

1.6 Summary of Confirmatory Items 

Based on its review of the LRA, including additional information submitted through July 9, 2010, 

the staff identified the following confirmatory items. An item is considered confirmatory if the 

staff and the applicant have reached a satisfactory resolution, but the applicant has not yet 

formally submitted the resolution. The staff has assigned a unique identifying number to each 

confirmatory item. 

Confirmatory Item 2.1.4.2-1

SER Section 2.1.4.2 Application of the Scoping Criteria in 10 CFR 54.4(a)(2) 

During the scoping and screening methodology audit, performed on-site October 19-22, 2009, 

the staff determined that the nonsafety-related, abandoned containment spray chemical addition 

tanks in Units 1 and 3 had not been included in the scope of license renewal. The associated 

piping was cut and capped for these tanks, but they had not been verified to be drained. 

The tanks were found to contain liquid and, thus, are in the scope of license renewal under 

10 CFR 54.4(a)(2). The applicant responded to the RAI by providing a commitment to drain the 

tanks by August 30, 2010. 

By letter dated November 10, 2010, the applicant stated that the containment spray chemical 

addition tanks and associated piping components have been drained. The staff’s detailed 

review is found in SER Section 2.1.4.2. 

Confirmatory Item 3.0.3.2.2-1

SER Section 3.0.3.2.2 Flow-Accelerated Corrosion Program 

PVNGS experienced a through-wall leak in stainless steel high pressure safety injection (HPSI) 

system piping which was determined by the applicant to be caused by erosion from cavitation. 

The applicant resolved this issue by periodic replacement of the affected sections of the HPSI 

system for all three units at approximately 7.5-year intervals. In its review of the apparent cause 

evaluation, the staff noted that the extent of condition analysis identified components in other 
 Introduction and General Discussion 

 1-11 

safety-related systems that were potentially susceptible to the same aging effect. The staff was 

unclear whether the applicant evaluated all identified in-scope line items susceptible to this 

aging effect. The applicant agreed to submit information regarding the resolution of the extent 

of condition for the HPSI cavitation erosion issue. 

The applicant responded by letters dated July 30, and September 3, 2010, stating that the 

extent of condition evaluation was completed. The applicant also provided a commitment 

(Commitment No. 59) stating that it would complete inspections of other potentially susceptible 

piping locations by June 30, 2012, and would incorporate any remaining components found to 

exhibit flow-related degradation into a comparable periodic replacement plan. The staff’s 

detailed review is found in SER Section 3.0.3.2.2. 

Confirmatory Item 3.0.3.2.13-1

SER Section 3.0.3.2.13 One-Time Inspection of ASME Code Class 1 Small-Bore Piping 

The applicant has experienced two failures of ASME Code Class 1 small-bore piping socket 

welds that the applicant attributed to a design defect. The applicant stated that the design issue 

has been resolved, but the staff considers this an aging-related failure requiring management. 

The staff needs assurance that a sufficient number of samples, as recommend by the GALL 

Report, will be selected to assure identification of small-bore piping socket weld inside-diameter 

cracking. The applicant stated that it would modify the One-Time Inspection Program 

(discussed in SER Section 3.0.3.1.6) to volumetrically inspect 10 percent of the socket weld 

population for each unit. 

In its response to Confirmatory Item 3.0.3.2.13-1, dated July 30, 2010, and supplemented by 

letter dated December 3, 2010, the applicant revised its AMP to volumetrically inspect at least 

10 percent of Class 1 socket welds per unit with a maximum of 25 welds and that weld selection 

will be based on risk insight and the potential for aging degradation. The staff’s detailed review 

is found in SER Section 3.0.3.2.13. 

Confirmatory Item 3.1.2.2.14-1

SER Section 3.1.2.2.14 Wall Thinning Due to Flow-Accelerated Corrosion 

The GALL Report identifies that wall thinning due to flow-accelerated corrosion (FAC) can occur 

in steel SG feedrings and supports. The applicant stated that feedring wall thinning, as 

addressed in Information Notice (IN) 91-19, is not applicable to PVNGS due to the model of 

SGs in use, and that no action is required. However, the staff does not consider IN 91-19 to be 

limited to CE SGs. During a conference call on July 9, 2010, the applicant clarified that the 

material of the SG feedring is FAC resistant. The applicant also explained that the scope of the 

SG degradation assessment done before every outage includes secondary side SG internals. 

The applicant clarified that the material of the SG feedring is fabricated from P11 steel and, 

therefore, is FAC resistant. The applicant also explained that the Steam Generator Tube 

Integrity Program considers wall thinning of the SG feedring and applicable operating 

experience as part of the secondary side SG Degradation Assessment, performed before every 

outage. The staff’s detailed review is found in SER Section 3.1.2.2.14. 

Confirmatory Item 3.3.2.1.1-1

SER Section 3.3.2.1 AMR Results Consistent with the GALL Report 

The staff needs further information on how the applicant manages elastomer components 

exposed to raw water in auxiliary systems for aging during the period of extended operation. 

The applicant stated it would provide information demonstrating that the polyvinyl chloride and 

polyethylene components are not susceptible to loss of material due to erosion and that the 

AMPs proposed to manage aging of the elastomer-lined carbon steel piping are appropriate. 
Introduction and General Discussion 

 1-12 

The applicant provided information demonstrating that the polyvinyl chloride components are 

not susceptible to loss of material due to erosion since they are used in low-velocity systems 

and because the material has good resistance to abrasion and erosion. The submittal also 

contained information describing why the AMPs proposed to manage aging of elastomer-lined 

carbon steel piping are appropriate. The staff’s detailed review is found in SER 

Section 3.3.2.1.1. 

1.7 Summary of Additional Items

Since issuance of the SER with Open Items on August 6, 2010, the staff identified and resolved 

the following additional items prior to issuance of this SER. The items are summarized below 

and the appropriate sections are identified which provide details of the staff’s review. 

Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Program (Section 3.0.3.1.9) 

The staff determined that the applicant’s Inaccessible Medium Voltage Cables AMP did not 

consider the most recent industry operating experience and the staff’s position on the scope of 

the program and inspection frequency. The applicant responded by letter dated 

October 13, 2010, providing additional information and a revised commitment to expand the 

scope of the program to include inaccessible low-voltage cables (480 volts to 2 kilo-volts) and to 

increase the manhole inspection and cable test frequencies. The staff’s detailed review is found 

in SER Section 3.0.3.1.9. 

Buried Piping and Tanks Inspection Program (Section 3.0.3.2.12) 

The staff determined that the applicant’s Buried Piping and Tanks AMP did not consider the 

most recent industry operating experience and the staff’s position on the scope and inspection 

frequency. In its response dated October 13, 2010, as supplemented by letter dated 

November 10, 2010, the applicant provided additional information and a revised commitment to 

describe its inspections of buried piping and tanks. See SER Section 3.0.3.2.12 for additional 

details. 

NUREG/CR-6260 Limiting Locations (Section 4.3.4.2) 

The staff requested the applicant to confirm and justify that the plant-specific components or 

locations listed in LRA Table 4.3-11 (except the pressurizer surge line pressurizer elbow) are 

bounding for the generic NUREG/CR-6260 locations and the additional location (pressurizer 

heater penetrations). The staff also requested the applicant to confirm and justify that the LRA 

Table 4.3-11 locations selected for environmentally-assisted fatigue analyses consists of the 

most limiting locations for the plant. If these locations are not bounding, the applicant was 

requested to clarify the locations that require an environmentally-assisted fatigue analysis and 

the actions that will be taken for these additional locations. 

By letter dated December 3, 2010, the applicant provided additional information to address the 

staff’s concern. The applicant committed to confirm and justify that the LRA locations were 

limiting. The staff’s detailed review is found in SER Section 4.3.4.2. 

Selective Leaching AMP (Section 3.0.3.2.11) 

The staff determined that the applicant’s inspection methodology was not defined in accordance 

with the staff’s position on sample size. The applicant responded by letter dated 

December 3, 2010, providing additional information and a revised commitment to further 

describe its inspection parameters. The staff’s detailed review is found in SER 

Section 3.0.3.2.11. 
 Introduction and General Discussion 

 1-13 

Steam Generator Tube Denting and Welds Susceptible to Primary Water Stress 

Corrosion Cracking (Sections 3.1.2.1.1, item 3.1.1-79, and Section 3.1.2.1.2, item 3.1.1-81) 

The staff determined that the applicant did not consider the most recent operating experience 

and the staff’s position on primary water stress corrosion cracking of SG tube-to-tubesheets 

welds and divider plate bar welds. In addition the staff noted a discrepancy in the LRA 

associated with the SG tube denting aging mechanism. The applicant amended the LRA to 

correct the aging effect for SG tubes to be consistent with the GALL Report. In addition, the 

applicant addressed the staff’s concerns about tube-to-tubesheet and divider plate bar welds by 

committing to address the aging management of these welds. The staff’s detailed review is 

found in SER Sections 3.1.2.1.1 and 3.1.2.1.2. 

1.8 Summary of Proposed License Conditions

Following the staff’s review of the LRA, including subsequent information and clarifications from 

the applicant, the staff identified three proposed license conditions. 

The first license condition requires the applicant to include the UFSAR supplement required by 

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

of the renewed licenses. The applicant may make changes to the programs and activities 

described in the UFSAR supplement provided changes are evaluated in accordance with the 

criteria set forth in 10 CFR 50.59. 

The second license condition requires the applicant to complete future activities described in the 

UFSAR supplement before the period of extended operation. 

The third license condition requires that all capsules in the reactor vessel that are removed and 

tested meet the requirements of American Society for Testing and Materials E 185-82 to the 

extent practicable for the configuration of the specimens in the capsule. The staff must approve 

any changes to the capsule withdrawal schedule before implementation, including spare 

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

approve any changes to storage requirements. 
Introduction and General Discussion 

 1-14 
 2-1 

2.0 Scoping and Screening Methodology 

2.1 Scoping and Screening Methodology

2.1.1 Introduction 

Title 10 of the Code of Federal Regulations (CFR), Section 54.21, “Contents of Application - 

Technical Information,” (10 CFR 54.21) requires an integrated plant assessment (IPA) for each 

license renewal application (LRA). The IPA must list and identify all of the systems, structures 

and components (SSCs) within the scope of license renewal in accordance with 10 CFR 54.4(a) 

and all structures and components (SCs) subject to an aging management review (AMR) in 

accordance with 10 CFR 54.21(a). 

LRA Section 2.1, “Scoping and Screening Methodology,” describes the scoping and screening 

methodology used to identify the SSCs at the Palo Verde Nuclear Generating Station (PVNGS) 

within the scope of license renewal and the SCs subject to an AMR. The U.S. Nuclear 

Regulatory Commission (NRC) staff (the staff) reviewed the scoping and screening 

methodology of the Arizona Public Service Company (APS) (the applicant) to determine if it 

meets the scoping requirements of 10 CFR 54.4(a) and the screening requirements of 

10 CFR 54.21. 

In developing the scoping and screening methodology for the LRA, the applicant stated that it 

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

Licenses for Nuclear Power Plants,” (the Rule) as well as statements of consideration related for 

the Rule and the guidance of Nuclear Energy Institute (NEI) 95-10, Revision 6, “Industry 

Guideline for Implementing the Requirements of 10 CFR Part 54 - The License Renewal Rule,” 

dated June 2005 (NEI 95-10). Additionally, in developing this methodology, the applicant stated 

that it considered the correspondence between the NRC, other applicants, and the NEI. 

2.1.2 Summary of Technical Information in the Application 

In LRA Sections 2 and 3, the applicant provides the technical information required by 

10 CFR 54.4, “Scope,” and 10 CFR 54.21(a). This safety evaluation report (SER) contains 

sections entitled “Summary of Technical Information in the Application,” which provide 

information taken directly from the LRA. 

In LRA Section 2.1, the applicant describes the process used to identify the SSCs that meet the 

license renewal scoping criteria under 10 CFR 54.4(a) and the process used to identify the SCs 

that are subject to an AMR, as required by 10 CFR 54.21(a)(1). The applicant provided the 

results of the process used for identifying the SCs subject to an AMR in the following LRA 

sections: 

 Section 2.2, “Plant Level Scoping Results” 

 Section 2.3, “Scoping and Screening Results: Mechanical Systems” 

 Section 2.4, “Scoping and Screening Results: Structures” 

 Section 2.5, “Scoping and Screening Results: Electrical and Instrumentation and 

Control Systems” 

In LRA Section 3.0, “Aging Management Review Results,” the applicant describes its aging 

management results as follows: 

 Section 3.1, “Aging Management of Reactor Vessel, Internals, and Reactor Coolant 

System” 
Scoping and Screening Methodology 

 2-2 

 Section 3.2, “Aging Management of Engineered Safety Features” 

 Section 3.3, “Aging Management of Auxiliary Systems” 

 Section 3.4, “Aging Management of Steam and Power Conversion Systems” 

 Section 3.5, “Aging Management of Containments, Structures, and Component 

Supports” 

 Section 3.6, “Aging Management of Electrical and Instrumentation and Controls” 

LRA Section 4, “Time-Limited Aging Analyses,” states the applicant’s evaluation of time-limited 

aging analyses (TLAAs). 

2.1.3 Scoping and Screening Program Review 

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

guidance contained in NUREG-1800, Revision 1, “Standard Review Plan for Review of License 

Renewal Applications for Nuclear Power Plants,” (SRP-LR), Section 2.1, “Scoping and 

Screening Methodology.” The following regulations form the basis for the acceptance criteria for 

the scoping and screening methodology review: 

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

Rule 

 10 CFR 54.4(b), as it relates to the identification of the intended functions of SSCs 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 SCs 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, to ensure that the applicant described a process for identifying SSCs that 

are within the scope of license renewal in accordance with the requirements of 

10 CFR 54.4(a) 

 Section 2.2, to ensure that the applicant described a process for determining the SCs 

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 PVNGS, located 

26 miles west of the Phoenix, AZ metropolitan area, during the week of October 19-22, 2009. 

The audit focused on ensuring that the applicant had developed and implemented adequate 

guidance to conduct the scoping and screening of SSCs in accordance with the methodologies 

described in the LRA and the requirements of the Rule. The staff reviewed implementation of 

the project-level guidelines and topical reports describing the applicant’s scoping and screening 

methodology. The staff conducted detailed discussions with the applicant on the 

implementation and control of the license renewal program and reviewed the administrative 

control documentation used by the applicant during the scoping and screening process, the 

quality practices used by the applicant to develop the LRA, and the training and qualification of 

the LRA development team. 

The staff evaluated the quality attributes of the applicant’s aging management program activities 

described in Appendix A, “Updated Final Safety Analysis Report Supplement,” and Appendix B, 

“Aging Management Programs” of the LRA. On a sampling basis, the staff performed a system 

review of the safety injection and shutdown cooling, diesel generator fuel oil storage and 
 Scoping and Screening Methodology 

 2-3 

transfer, auxiliary feedwater, and turbine building. This assessment included a review of the 

scoping and screening results reports and supporting design documentation used to develop 

the reports. The purpose of the staff’s review was to ensure that the applicant had appropriately 

implemented the methodology outlined in the administrative controls and to verify that the 

results are consistent with the current licensing basis (CLB) documentation. 

2.1.3.1 Implementation Procedures and Documentation Sources for Scoping and 

Screening 

The staff reviewed the applicant’s scoping and screening implementing procedures as 

documented in the Scoping and Screening Methodology Audit Trip Report, dated April 7, 2010, 

to verify that the process used to identify SCs subject to an AMR was consistent with the 

SRP-LR. Additionally, the staff reviewed the scope of CLB documentation sources and the 

process used by the applicant to ensure that applicant’s commitments, as documented in the 

CLB and relative to the requirements of 10 CFR 54.4 and 10 CFR 54.21, were appropriately 

considered and that the applicant adequately implemented its procedural guidance during the 

scoping and screening process. 

2.1.3.1.1 Summary of Technical Information in the Application 

In LRA Section 2.1, “Scoping and Screening Methodology,” the applicant addressed the 

following information sources for the license renewal scoping and screening process: 

 Updated Final Safety Analysis Report (UFSAR) 

 Safety Evaluation Reports 

 Technical Specifications 

 Licensing correspondence 

 Engineering drawings 

 License renewal position papers 

 Plant equipment database 

The applicant stated that it used a variety of documents, including those listed above, to apply 

scoping criteria in determining and confirming SSC functions. 

2.1.3.1.2 Staff Evaluation 

Scoping and Screening Implementing Procedures. The staff reviewed the applicant’s scoping 

and screening methodology implementing procedures, including license renewal guidelines, 

documents, and reports, as documented in the audit report, to ensure the guidance is consistent 

with the requirements of the Rule, the SRP-LR, and NEI 95-10. The staff finds that the overall 

process used to meet the 10 CFR Part 54 requirements and described in the implementing 

procedures and AMRs is consistent with the Rule, the SRP-LR, and industry guidance. 

The applicant’s implementing procedures contain guidance for determining plant SSCs within 

the scope of the Rule and for determining which SCs, within the scope of license renewal, are 

subject to an AMR. During the review of the implementing procedures, the staff focused on the 

consistency of the detailed procedural guidance with information in the LRA. This information 

included the implementation of NRC staff positions documented in the SRP-LR and the 

information in the applicant’s responses, dated February 5, April 1, and April 2, 2010, to the 

staff’s requests for additional information (RAIs) dated December 23, 2009. 

After reviewing the LRA and supporting documentation, the staff determined that the scoping 

and screening methodology instructions are consistent with the methodology description 

provided in LRA Section 2.1. The applicant’s methodology is sufficiently detailed to provide 

concise guidance on the scoping and screening implementation process to be followed during 

the LRA activities. 
Scoping and Screening Methodology 

 2-4 

Sources of Current Licensing Basis Information. The staff reviewed the scope and depth of the 

applicant’s CLB review to verify that the methodology is sufficiently comprehensive to identify 

SSCs within the scope of license renewal as well as SCs requiring an AMR. Under 

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. The CLB also includes the plant-specific design bases that are docketed 

and in effect and applicable NRC regulations, orders, license conditions, exemptions, technical 

specifications, and design-basis information (documented in the most recent UFSAR). The CLB 

also includes licensee commitments, remaining in effect, that the applicant made in docketed 

licensing correspondence such as licensee responses to NRC bulletins, generic letters and 

enforcement actions, and licensee commitments documented in NRC safety evaluations or 

licensee event reports. 

During the audit, the staff reviewed pertinent information sources used by the applicant 

including the UFSAR, design-basis information, and license renewal drawings. In addition, the 

applicant’s license renewal process identified additional sources of plant information pertinent to 

the scoping and screening process, including the plant equipment database, controlled 

drawings, technical correspondence, analyses, and reports. The staff confirmed that the 

applicant’s detailed license renewal program guidelines specified the use of the CLB source 

information in developing scoping evaluations. 

The plant equipment database, UFSAR, design basis information, and plant drawings were the 

applicant’s primary repository for system identification and component safety classification 

information. During the audit, the staff reviewed the applicant’s administrative controls for the 

plant equipment database, design-basis information, and other information sources used to 

verify system information. Plant administrative procedures describe these controls and govern 

their implementation. Based on a review of the administrative controls and a sample of the 

system classification information contained in the applicable documentation, the staff concludes 

that the applicant has established adequate measures to control the integrity and reliability of 

system identification and safety classification data. Therefore, the staff concludes that the 

information sources used by the applicant during the scoping and screening process provide a 

sufficiently controlled source of system and component data to support scoping and screening 

evaluations. 

During the staff’s review of the applicant’s CLB evaluation process, the applicant explained the 

incorporation of updates to the CLB and the process used to ensure that it adequately 

incorporates those updates into the license renewal process. The staff determined that LRA 

Section 2.1 provided 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. 

In addition, the staff reviewed the implementing procedures and results reports used to support 

the identification of SSCs that the applicant relied on to demonstrate compliance with the 

safety-related criteria, nonsafety-related criteria, and the regulated events criteria detailed in 

10 CFR 54.4(a). The applicant’s license renewal program guidelines provided a listing of 

documents used to support scoping and screening evaluations. The staff finds 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. 

The staff determined that additional information would be required to complete the review of the 

applicant’s scoping methodology. RAI 2.1-1, dated December 23, 2009, states that during 

review of the LRA and the performance of the scoping and screening methodology audit 

performed onsite October 19-22, 2009, the staff determined that although differences exist 

between the three units, the applicant had provided a single set of license renewal drawings to 

assist the staff in its review. In addition, the staff’s review of license renewal drawing 

LR-PVNGS-CT-01-M-CTP-001 identified a vent and drain valve, which is present only in 
 Scoping and Screening Methodology 

 2-5 

PVNGS Unit 2, but is not identified or described in the LRA. As a result, the staff asked that the 

applicant provide the following information: 

 A description of the process used to identify and document the 

differences in system, structure, or component configurations and the 

material and environments between similar structures or components 

between the three PVNGS units 

 A list of any differences of systems, structures, or components included 

within the scope of license renewal and any structures or component 

subject to AMR between the three PVNGS units 

The applicant responded to RAI 2.1-1 by letter dated February 5, 2010, which stated the 

following: 

PVNGS Piping and Instrumentation Drawings (P&ID) were used with the LRDMT 

[license renewal data management tool - containing information derived from the 

plant equipment database] for scoping and screening of mechanical components. 

For each mechanical system, P&IDs for units 1, 2, and 3 were reviewed for 

obvious differences. The most representative P&ID was selected for 

development of the license renewal boundary drawing and was used as the 

working drawing for scoping and screening of components. After in-scope 

license renewal boundaries were established on a plant system P&ID, each 

in-scope component on the P&ID was checked off, and scoping and screening 

information was entered into the LRDMT (component by component). After all 

in-scope components were checked off on the working P&ID, any unevaluated 

components in the LRDMT were reconciled. Some of these components were 

shown on other interfacing drawings and had to be evaluated accordingly for 

being in-scope of license renewal. Components that were clearly out of scope 

based on the P&ID in-scope boundaries and [plant equipment database] 

research were not included in-scope in the LRDMT. Any remaining LRDMT 

system components were evaluated and determined whether or not to be within 

the scope of license renewal based on [plant equipment database] and current 

licensing basis (CLB) research. Some of these components were minor unit 

differences. Each of these unit difference components were then evaluated for 

intended function, material type, and internal and external environments and 

documented in the LRDMT on a component by component basis. Thus, all 

mechanical components in the LRDMT (i.e., SWMS [site equipment database]) 

were accounted for and evaluated for license renewal whether the component 

was applicable to one, two, or three units. 

In cases where a mechanical system had unit differences for in-scope 

components, system boundary drawings were sometimes modified to show the 

unit-specific components with a note explaining additional unit-specific 

components are in-scope, as was the case for the valve noted in this RAI on 

boundary drawing LR-PVNGS-CT-01-MCTP-001. Whether unit-specific 

components have been shown on the boundary drawings or not, the unit-specific 

components have been appropriately scoped and screened as described above. 

Unit differences are identified and documented as described in the general 

discussion above. The differences are contained in the LRDMT, and affected 

components scoped and screened as discussed above. There is no separate 

reporting or documenting of these minor unit differences since it is inherent in the 

scoping and screening methodology that mechanical system components are 
Scoping and Screening Methodology 

 2-6 

evaluated individually and determined to be, or not to be, within the scope of 

license renewal. 

Unit-difference components were found based on the P&ID review and [plant 

equipment database]/LRDMT reconciliation. These components were then 

evaluated on an individual component basis. Each component was researched 

through SWMS (Site Work Management System), P&IDs, component drawings, 

component specifications, etc., to determine the material type and appropriate 

environments on a one for one component basis. The results were documented 

in the LRDMT for each of these components. 

The review of the scoping and screening methodology concluded that the 

methodology did not preclude identification of SSCs which should have been 

included in the scope of license renewal. PVNGS Units 1, 2, and 3 components 

have been included in the appropriate component type/material/environment 

groups for aging evaluation management. No additional SSCs were added to the 

scope of license renewal based on this review. 

[The response included] a list of differences of systems, structures, or 

components included within the scope of license renewal and any structures or 

component subject to aging management review, between the three PVNGS 

units. 

The scoping and screening methodology was reviewed with respect to the issue 

identified. It was determined that the methodology did not preclude identification 

of SSCs which should have been included in the scope of license renewal. The 

specific valve in question, although not on the Unit 1 boundary drawing used for 

PVNGS, was noted on the boundary drawing as existing in Unit 2 only. The 

valve was included in the PVNGS LRDMT and was evaluated for aging 

management. 

The staff reviewed the applicant’s response to RAI 2.1-1 and determined that the applicant had 

provided documentation that explained and clarified how differences in SSCs between the three 

PVNGS units were identified, documented, and dispositioned and provided a list of the identified 

differences. The staff determined that the methodology as explained, provided an adequate 

method to ensure that differences between units were evaluated and identified on the single set 

of license renewal drawings. RAI 2.1-1 is resolved. 

2.1.3.1.3 Conclusion 

Based on its review of LRA Section 2.1, the detailed scoping and screening implementing 

procedures, the results from the scoping and screening audit, and the response to the RAI, the 

staff concludes that the applicant's scoping and screening methodology consider CLB 

information in a manner consistent with the Rule, the SRP-LR, and NEI 95-10 guidance and, 

therefore, is acceptable. 

2.1.3.2 Quality Controls Applied to License Review Application Development 

2.1.3.2.1 Staff Evaluation 

The staff reviewed the quality assurance controls used by the applicant to ensure that it 

adequately carried out the scoping and screening methodologies used in the LRA. The 

applicant applied the following quality assurance processes during the LRA development: 

 Written procedures and guidelines governed the scoping and screening methodology. 

 The applicant’s team reviewed the LRA in a structured self-assessment. 
 Scoping and Screening Methodology 

 2-7 

 Internal assessment teams reviewed the LRA. These teams included the license 

renewal team, system engineers, subject matter experts, quality assurance audit team, 

plant review board, and off-site review committee. Each of these teams included 

different levels of plant and organizational management. 

 External assessment teams, including industry peers, reviewed the LRA. Recent license 

renewal applicants also participated and provided additional benchmarking. 

 The applicant addressed and managed comments received through the assessment 

process using peer and management review. 

2.1.3.2.2 Conclusion 

On the basis of its review of pertinent LRA development guidance, discussion with the 

applicant’s license renewal staff, review of the applicant’s documentation of the activities 

performed to assess the quality of the LRA, and review of the information provided in response 

to RAI 2.1-1, the staff concludes that the applicant’s quality assurance activities meet current 

regulatory requirements and provide assurance that LRA development activities were performed 

in accordance with the applicant’s license renewal program requirements. 

2.1.3.3 Training 

2.1.3.3.1 Staff Evaluation 

The staff reviewed the applicant’s training process to ensure that it applied the guidelines and 

methodology for the scoping and screening activities in a consistent and appropriate manner. 

As outlined in the implementing procedures, the applicant requires training for all personnel 

participating in the development of the LRA and uses only trained and qualified personnel to 

prepare the scoping and screening implementing procedures. The training included the 

following activities: 

 Initial qualification was completed before the project started and included the review of 

the license renewal processes, license renewal project guidelines, and relevant industry 

documents such as 10 CFR Part 54 regulations, NEI 95-10, SRP-LR, and NUREG-1801, 

“Generic Aging Lessons Learned Report,” Revision 1. 

 Training was required for the license renewal project personnel, which followed 

documented and written guidance. 

 License renewal project personnel completed training in general license renewal 

requirements, license renewal project procedures, and discipline-specific areas. Project 

personnel with license renewal project experience also supplied mentoring services. 

 Plant personnel received information systems training and attended aging management 

program and TLAA workshops. 

The staff reviewed the applicant’s written procedures and, on a sampling basis, reviewed 

completed qualification and training records, and completed training checklists for some of the 

applicant’s license renewal personnel. The staff determined that the applicant had developed 

and implemented adequate procedures to control the training of personnel performing 

LRA activities. 

2.1.3.3.2 Conclusion 

On the basis of discussions with the applicant’s license renewal project personnel, responsible 

for the scoping and screening process, and its review of selected documentation in support of 

the process, the staff concludes that the applicant’s personnel are adequately trained to 

implement the scoping and screening methodology described in the applicant’s implementing 

procedures and the LRA. 
Scoping and Screening Methodology 

 2-8 

2.1.3.4 Conclusion of Scoping and Screening Program Review 

On the basis of a review of information provided in LRA Section 2.1, a review of the applicant's 

detailed scoping and screening implementing procedures, discussions with the applicant’s 

license renewal personnel, and the results from the scoping and screening methodology audit, 

the staff concludes that the applicant’s scoping and screening program is consistent with the 

SRP-LR and the requirements of 10 CFR 54 and, therefore, is acceptable. 

2.1.4 Plant Systems, Structures, and Components Scoping Methodology 

LRA Section 2.1 describes the applicant’s methodology used to scope SSCs per the 

requirements of the 10 CFR 54.4(a) criteria. The LRA states that the scoping process 

categorized the entire plant in terms of systems and structures with respect to license renewal. 

According to the LRA, systems and structures were evaluated against criteria provided in 

10 CFR 54.4 (a)(1), (2), and (3) to determine if the item should be considered within the scope 

of license renewal. The LRA states that the scoping process identified the SSCs that are 

safety-related and perform or support an intended function for responding to a design basis 

event (DBE); are nonsafety-related but their failure could prevent accomplishment of a 

safety-related function; or support a specific requirement for one of the five regulated events 

applicable to license renewal. Section 2.1.1 “Introduction,” states that the scoping methodology 

utilized is consistent with 10 CFR 54 and with the industry guidance contained in NEI 95-10. 

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

2.1.4.1.1 Summary of Technical Information in the Application 

As required by 10 CFR 54.4(a)(1), plant SSCs within the scope of license renewal must include 

safety-related SSCs, which are those SSCs that are relied upon to remain functional during and 

following DBEs (as defined in 10 CFR 50.49 (b)(1)), to ensure the following functions: 

(i) The integrity of the reactor coolant pressure boundary 

(ii) The capability to shut down the reactor and maintain it in a safe shutdown condition 

(iii) The capability to prevent or mitigate the consequences of accidents, which could result 

in potential off-site 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 

LRA Section 2.1.2.1, “Title 10 CFR 54.4(a)(1) - Safety-Related,” states the following: 

Safety-related classifications for systems and structures at PVNGS are reported 

in the UFSAR or in design basis documents such as engineering drawings, 

evaluations, or calculations. Safety-related classifications for components are 

documented on engineering drawings and in a plant equipment database. The 

safety-related classification as reported in these source documents has been 

relied upon to identify SSCs satisfying one or more of the criteria of 

10 CFR 54.4(a)(1). These SSCs have been identified as within the scope of 

license renewal. 

The LRA points to the UFSAR Appendix 17.2C “Terms and Definitions,” which defines 

“safety-related” as the equipment and SCs that are relied upon to remain functional, during and 

following design bases events, to ensure the following: 

 The integrity of the reactor coolant boundary 

 The capability to shut down the reactor and maintain it in a safe condition 

 The capability to prevent or mitigate the consequences of accident, which could result in 

potential offsite exposures comparable to the guideline exposures of 10 CFR 100 
 Scoping and Screening Methodology 

 2-9 

The UFSAR review identified the set of DBEs and confirmed that the license renewal process 

had evaluated the associated SSCs consistent with the criteria of the Rule. The exposure 

guidelines used for license renewal are the same as 10 CFR 54.4 with the exception of the 

guidelines cited for off-site exposures. In addition to the guidelines of 10 CFR 100, 

10 CFR 54.4(a)(1)(iii) references the dose guidelines of 10 CFR 50.34(a)(1) and 

10 CFR 50.67(b)(2). These different exposure guidelines appear in three different code 

sections to address similar accident analyses performed by licensees for different reasons. The 

guidelines of 10 CFR 50.34(a)(1) are applicable to facilities seeking a construction permit and 

are, therefore, not applicable to license renewal. The exposure guidelines of 

10 CFR 50.67(b)(2) address the use of alternate source terms, which are not applicable under 

the PVNGS CLB. Therefore, the applicant stated that use of the safety-related classification 

designators is consistent with 10-CFR 54.4(a)(1) scoping criteria. 

2.1.4.1.2 Staff Evaluation 

As stated above, under 10 CFR 54.4(a)(1), the applicant must consider all safety-related SSCs 

relied upon to remain functional, during and following a DBE, to ensure the integrity of the 

reactor coolant pressure boundary, the ability to shut down the reactor and maintain it in a safe 

shutdown condition, or the capability to prevent or mitigate the consequences of accidents that 

could result in potential offsite exposures. 

With regard to identification of DBEs, Section 2.1.3, “Review Procedures,” of the SRP-LR states 

the following: 

The set of DBEs as defined in the Rule is not limited to Chapter 15 (or 

equivalent) of the UFSAR. Examples of DBEs that may not be described in this 

chapter include external events, such as floods, storms, earthquakes, tornadoes, 

or hurricanes, and internal events, such as a high energy line break. Information 

regarding DBEs as defined in 10 CFR 50.49(b)(1) may be found in any chapter of 

the facility UFSAR, the Commission’s regulations, NRC orders, exemptions, or 

license conditions within the CLB. These sources should also be reviewed to 

identify SSCs relied upon to remain functional during and following DBEs (as 

defined in 10 CFR 50.49(b)(1)) to ensure the functions described in 

10 CFR 54.4(a)(1). 

During the audit, the applicant stated that it evaluated the types of events listed in NEI 95-10 

(i.e., anticipated operational occurrences, DBEs, external events, and natural phenomena) that 

were applicable to PVNGS. The staff reviewed the applicant’s basis documents, which 

described all design basis conditions in the CLB and addressed all events defined by 

10 CFR 50.49(b)(1) and 10 CFR 54.4(a)(1). The PVNGS UFSAR and basis documents 

discussed events such as internal and external flooding, tornados, and missiles. The staff 

concludes that the applicant’s evaluation of DBEs was consistent with the SRP-LR. 

The applicant scoped SSCs for the 10 CFR 54.4(a)(1) criterion in accordance with the license 

renewal implementing procedures, which provide guidance for the preparation, review, 

verification, and approval of the scoping evaluations to ensure the adequacy of the results of the 

scoping process. The staff reviewed the implementing procedures governing the applicant’s 

evaluation of safety-related SSCs and sampled the applicant’s reports of the scoping results to 

ensure that the methodology was applied in accordance with the implementing procedures. In 

addition, the staff discussed the methodology and results with applicant personnel who were 

responsible for these evaluations. 

The staff reviewed the applicant’s evaluation of the Rule and CLB definitions pertaining to 

10 CFR 54.4(a)(1) and determined that the CLB definition of “safety-related,” met the definition 

of “safety-related” specified in 10 CFR 54.4(a)(1). The staff reviewed a sample of the license 

renewal scoping results for the safety injection and shutdown cooling, diesel generator fuel oil 
Scoping and Screening Methodology 

 2-10 

storage and transfer, auxiliary feedwater, and turbine building to provide additional assurance 

that the applicant adequately implemented its scoping methodology in accordance with 

10 CFR 54.4(a)(1). The staff verified that the applicant developed the scoping results for each 

of the sampled systems consistent with the methodology, identified the SSCs credited for 

performing intended functions, and adequately described the basis for the results as well as the 

intended functions. The staff also confirmed that the applicant had identified and used pertinent 

engineering and licensing information to identify the SSCs required to be within the scope of 

license renewal in accordance with 10 CFR 54.4(a)(1) criteria. 

2.1.4.1.3 Conclusion 

On the basis of its review of systems (on a sampling basis), discussions with the applicant, and 

review of the applicant’s scoping process, the staff concludes that the applicant's methodology 

for identifying systems and structures that are within the scope of license renewal is consistent 

with the SRP-LR and the requirements of 10 CFR 54.4(a)(1), and, therefore, is acceptable. 

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

2.1.4.2.1 Summary of Technical Information in the Application 

LRA Section 2.1.2.2, “Title 10 CFR 54.4(a)(2) - Nonsafety-Related Affecting Safety-Related,” 

states the following: 

10 CFR 54.4(a)(2) requires that plant SSCs within the scope of license renewal 

include all nonsafety-related SSCs whose failure could prevent satisfactory 

accomplishment of any of the functions identified for safety-related SSCs. The 

guidance provided in NEI 95-10, Appendix F, was used to develop the 

methodology for scoping to the criterion of 10 CFR 54.4(a)(2). 

Section 2.1.2.2 of the LRA goes on to state that the methodology includes identification of 

nonsafety-related SSCs that are connected to safety-related SSCs and nonsafety-related SSCs 

that could spatially interact with safety-related SSCs. Determination and identification of any 

other SSCs satisfying criterion 10 CFR 54.4(a)(2) was completed as described below, based on 

review of applicable CLB documents, plant specific and industry operating experience, and by 

system and structure functional evaluations. 

LRA Section 2.1.2.2 states the following in relation to nonsafety-related SSCs providing 

functional support to safety-related SSCs: 

The PVNGS UFSAR and other current licensing basis documents were reviewed 

for every nonsafety-related plant system or structure, to determine whether the 

system or structure was credited with supporting satisfactory accomplishment of 

a safety-related function. Nonsafety-related systems or structures credited in 

CLB documents with supporting accomplishment of a safety-related function 

were classified as satisfying criterion 10 CFR 54.4(a)(2) and were included within 

the scope of license renewal. 

LRA Section 2.1.2.2 states the following in relation to nonsafety-related SSCs directly 

connected to safety-related SSCs: 

Nonsafety-related SSCs were included within the scope of license renewal, as 

applicable, up to the first seismic anchor past the safety/nonsafety interface for 

those nonsafety-related mechanical SSCs that are connected to a safety-related 

SSC and must provide structural integrity. In most cases, an actual seismic 

anchor exists to serve as the boundary for the nonsafety structural integrity 

feature. In cases where seismic anchors were not available to serve as the 

license renewal boundary, other methods as provided for in NEI 95-10, including 
 Scoping and Screening Methodology 

 2-11 

equivalent anchors were utilized to establish the license renewal boundary. 

Other methods included: 

 A combination of restraints or supports such that the nonsafety-related 

piping and associated structures and components attached to 

safety-related piping is included in-scope up to a boundary point that 

encompasses two (2) supports in each of three (3) orthogonal directions. 

 A base-mounted component (e.g., pump, heat exchanger, tank, etc.) that 

is a rugged component and is designed not to impose loads on 

connecting piping is included in scope as it has a support function for the 

safety-related piping. 

 A flexible connection that is considered a pipe stress analysis model end 

point when the flexible connection effectively decouples the piping system 

(i.e., does not support loads or transfer loads across it to connected 

piping). 

 A free end of nonsafety-related piping, such as a drain pipe that ends at 

an open floor drain. 

 A point where buried piping exits the ground. The buried portion of the 

piping should be included in the scope of license renewal. A 

determination that the buried piping is well founded on compacted soil 

that is not susceptible to liquification must be documented. 

 Nonsafety-related piping runs that are connected at both ends to 

safety-related piping include the entire run of nonsafety-related piping. 

 LRA Section 2.1.2.2 states, in relation to nonsafety-related SSCs with the 

potential for spatial interaction with safety-related SSCs: 

Nonsafety-related SSCs which are not connected to safety-related piping and/or 

which are not required for structural integrity, but have a spatial relationship such 

that their failure could adversely impact the performance of a safety-related SSC 

intended function, were included in the scope of license renewal per NEI 95-10, 

Appendix F. PVNGS applied the preventative option for 10 CFR 54.4(a)(2) 

scoping. The preventative option as implemented at PVNGS is based on a 

“spaces” approach for scoping of nonsafety-related systems with potential spatial 

interaction with safety-related SSCs. Potential spatial interaction is assumed in 

any structure that contains active or passive safety-related SSCs. The structures 

of concern for potential spatial interaction were identified based on the review of 

the CLB to determine which structures contained safety-related SSCs. Plant 

walkdowns were performed as required to confirm that all structures containing 

safety-related SSCs had been identified. For structures that contain 

safety-related SSCs, there may be selected rooms within the structure that do 

not contain any safety-related SSCs. CLB document reviews and plant 

walkdowns were utilized as appropriate to confirm that these rooms did not 

contain safety-related SSCs, thereby eliminating spatial interactions concerns 

from these rooms. 

Nonsafety-related systems and components that contain water, oil, or steam, and 

are located inside structures that contain safety-related SSCs are included 

in-scope for potential spatial interaction under criterion 10 CFR 54.4(a)(2), unless 

located in an excluded room. All high-energy lines located inside primary 

containment are included within the scope of license renewal. High-energy lines 
Scoping and Screening Methodology 

 2-12 

located outside primary containment are included within the scope of license 

renewal if their failure could adversely impact any safety-related SSC’s. 

Safety-related high-energy lines are in-scope under 10 CFR 54.4(a)(1), and 

nonsafety-related high-energy lines are in-scope under 10 CFR 54.4(a)(2). The 

potential effects of flooding as a consequence of a pipe break or critical crack 

were analyzed on a case-by-case basis to ensure that the operability of 

safety-related equipment would not be impaired. Floor drains and curbs required 

for flood mitigation are within the scope of license renewal under 

10 CFR 54.4(a)(2). Supports for all nonsafety-related SSCs within these 

structures are included within the scope of license renewal. 

2.1.4.2.2 Staff Evaluation 

Under 10 CFR 54.4(a)(2), the applicant must consider all nonsafety-related SSCs whose failure 

could prevent the satisfactory accomplishment of functions for safety-related SSCs, relied on 

during and following a DBE, to ensure: (1) the integrity of the reactor coolant pressure 

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

or (3) the capability to prevent or mitigate the consequences of accidents 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. 

Regulatory Guide (RG) 1.188, Revision 1, endorses the use of NEI 95-10, Revision 6. 

NEI 95-10 discusses the staff’s position on 10 CFR 54.4(a)(2) scoping criteria; including 

nonsafety-related SSCs typically identified in the CLB; consideration of missiles, cranes, 

flooding, and high-energy line breaks; nonsafety-related SSCs connected to safety-related 

SSCs; nonsafety-related SSCs in proximity to safety-related SSCs; and mitigative and 

preventative options related to nonsafety-related and safety-related SSCs interactions. 

In addition, the staff’s position (as discussed in NEI 95-10, Revision 6) is that applicants should 

not consider hypothetical failures, but rather should base evaluations on the plant’s CLB, 

engineering judgment and analyses, and relevant operating experience. NEI 95-10 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 NRC 

generic communications and event reports, plant-specific condition reports, industry reports 

such as safety operational event reports, and engineering evaluations. The staff reviewed LRA 

Section 2.1.2.2, in which the applicant described the scoping methodology for nonsafety-related 

SSCs under 10 CFR 54.4(a)(2). In addition, the staff reviewed the applicant’s implementing 

document and results report, which documents the guidance and corresponding results of the 

applicant’s scoping review pursuant to 10 CFR 54.4(a)(2). The applicant stated in 

Section 2.1.2.2 that it performed the review in accordance with the guidance contained in 

NEI 95-10, Revision 6, Appendix F. 

Nonsafety-Related SSCs Required to Perform a Function that Supports a Safety-Related SSC. 

The staff determined that nonsafety-related SSCs required to remain functional to support a 

safety-related function had been reviewed by the applicant for inclusion within the scope of 

license renewal in accordance with 10 CFR 54.4(a)(2). The staff reviewed the evaluating 

criteria discussed in LRA Section 2.1.2.2 and the applicant’s 10 CFR 54.4(a)(2) implementing 

document. The staff confirmed that the applicant had reviewed the UFSAR, plant drawings, 

plant equipment database, and other CLB documents to identify the nonsafety-related systems 

and structures that function to support a safety-related system whose failure could prevent the 

performance of a safety-related intended function. The applicant also considered missiles, 

overhead handling systems, internal and external flooding, and high-energy line breaks. 

Accordingly, the staff finds that the applicant implemented an acceptable method for including 

nonsafety-related systems that perform functions that support safety-related intended functions, 

within the scope of license renewal as required by 10 CFR 54.4(a)(2). 
 Scoping and Screening Methodology 

 2-13 

Nonsafety-Related SSCs Directly Connected to Safety-Related SSCs. The staff confirmed that 

nonsafety-related SSCs, directly connected to SSCs, had been reviewed by the applicant for 

inclusion within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). The staff 

reviewed the evaluating criteria discussed in LRA Section 2.1.2.2 and the applicant’s 

10 CFR 54.4(a)(2) implementing document. The applicant had reviewed the safety-related to 

nonsafety-related interfaces for each mechanical system in order to identify the 

nonsafety-related components located between the safety to nonsafety-related interface and 

license renewal structural boundary. 

The staff determined that in order to identify the nonsafety-related SSCs connected to 

safety-related SSCs and required to be structurally sound to maintain the integrity of the 

safety-related SSCs, the applicant used a combination of the following to identify the portion of 

nonsafety-related piping systems to include within the scope of license renewal: 

 Seismic anchors 

 Equivalent anchors 

 Bounding conditions described in NEI 95-10 Revision 6, Appendix F (i.e., base-mounted 

component, flexible connection, inclusion to the free end of nonsafety-related piping, or 

inclusion of the entire piping run) 

The staff finds that the applicant implemented an acceptable method for including 

nonsafety-related SSCs directly connected to safety-related SSCs, within the scope of license 

renewal as required by 10 CFR 54.4(a)(2). 

Nonsafety-Related SSCs with the Potential for Spatial Interaction with Safety-Related SSCs. 

The staff confirmed that nonsafety-related SSCs with the potential for spatial interaction with 

safety-related SSCs had been reviewed by the applicant for inclusion within the scope of license 

renewal in accordance with 10 CFR 54.4(a)(2). The staff reviewed the evaluating criteria 

discussed in the LRA Section 2.1.2.2 and the applicant’s 10 CFR 54.4(a)(2) implementing 

procedure. The applicant considered physical impacts (i.e., pipe whip, jet impingement), harsh 

environments, flooding, spray, and leakage when evaluating the potential for spatial interactions 

between nonsafety-related systems and safety-related SSCs. The staff further confirmed that 

the applicant used a “spaces” approach to identify the portions of nonsafety-related systems 

with the potential for spatial interaction with safety-related SSCs. The “spaces” approach 

focuses on the interaction between nonsafety-related and safety-related SSCs that are located 

in the same space, which was defined for the purposes of the review as a structure containing 

active or passive safety-related SSCs. 

LRA Section 2.1.2.2 and the applicant’s implementing document state that the applicant had 

included mitigative features when considering the affect of nonsafety-related SSCs on 

safety-related SSCs for occurrences discussed in the CLB. The staff reviewed the applicant’s 

CLB information, primarily contained in the UFSAR, related to missiles, crane load drops, 

flooding, and high-energy line breaks. The staff determined that the applicant also considered 

the features designed to protect safety-related SSCs from the effects of these occurrences 

through the use of mitigating features, such as floor drains and curbs. The staff confirmed that 

the applicant had included the mitigating features within the scope of license renewal in 

accordance with 10 CFR 54.4(a)(2). 

LRA Section 2.1.2.2 and the applicant’s implementing document state that the applicant had 

used a preventive approach, which considered the affect of nonsafety-related SSCs contained 

in the same space as safety-related SSCs. The staff determined that the applicant had 

evaluated all nonsafety-related SSCs containing liquid or steam and located in spaces 

containing safety-related SSCs. The applicant used a spaces approach to identify the 

nonsafety-related SSCs that were located within the same space as safety-related SSCs. 
Scoping and Screening Methodology 

 2-14 

As described in the LRA and for the purpose of the scoping review, a space was defined as a 

structure containing active or passive safety-related SSCs. In addition, the staff determined that 

following the identification of the applicable mechanical systems, the applicant identified its 

corresponding structures for potential spatial interaction, based on a review of the CLB and 

plant walkdowns. Nonsafety-related systems and components that contain liquid or steam and 

are located inside structures that contain safety-related SSCs were included within the scope of 

license renewal, unless it was in an evaluated area and determined not to contain safety-related 

SSCs. The staff also determined that, based on plant and industry operating experience, the 

applicant excluded the nonsafety-related SSCs containing air or gas from the scope of license 

renewal, with the exception of portions that are attached to safety-related SSCs and required for 

structural support. The staff confirmed that those nonsafety-related SSCs determined to contain 

liquid or steam and located within a space containing safety-related SSCs were included within 

the scope of license renewal in accordance with 10 CFR 54.4(a)(2). 

The staff determined that additional information would be required to complete the review of the 

applicant’s scoping methodology. RAI 2.1-2, dated December 23, 2009, states that during the 

scoping and screening methodology audit, performed onsite October 19-22, 2009, the staff 

determined that the applicant had not included certain fluid-filled, nonsafety-related SSCs, 

adjacent to safety-related SSCs, within the scope of license renewal. The applicant’s basis for 

not including the nonsafety-related SSCs was information contained in the applicant’s 

“Moderate Energy Crack Evaluation” document. 

The staff asked that the applicant perform a review of the issue and provide the basis for the 

determination that the Moderate Energy Crack Evaluation is part of the CLB. The staff also 

asked for a description and analysis of the pertinent information contained in the Moderate 

Energy Crack Evaluation that gives the basis for the conclusion that failure of the 

nonsafety-related, fluid filled SSCs could not prevent the satisfactory accomplishment of 

safety-related functions for SSCs relied on to remain functional during and following a DBE. 

This issue was also reviewed during a NRC license renewal inspection, done the week of 

February 22, 2010 (Inspection Report dated April 29, 2010), and subsequently documented in 

Palo Verde Action Request 3440560. 

The applicant responded to RAI 2.1-2 and issues identified during the NRC license renewal 

inspection the week of February 22, 2010, by letter dated April 1, 2010, which states the 

following: 

PVNGS UFSAR Table 3.6-3 provides the methods of protection of safety-related 

systems from the effects of high and moderate energy line breaks. The methods 

specified in the table are layout, enclosure, and redundancy. The Moderate 

Energy Crack Evaluation was prepared to verify, in part, the protection methods 

specified in PVNGS UFSAR were met. Therefore, Moderate Energy Crack 

Evaluation, 13-MC-ZZ- 642, is part of the current licensing basis (CLB) as 

defined in 10 CFR 54.3. 

Palo Verde has revised its 10 CFR 54.4(a)(2) implementing document to delete 

the use of information contained in the Moderate Energy Crack Evaluation. The 

Moderate Energy Crack Evaluation will not be used to provide the basis for 

determination that failure of the non-safety-related fluid-filled structures, systems, 

and components (SSCs) could not prevent the satisfactory accomplishment of 

safety-related functions for SSCs relied on to remain functional during and 

following a design basis event. 

The information contained in the Moderate Energy Crack Evaluation had been 

used to evaluate spatial interaction of nonsafety-related SSCs in the Auxiliary 

Building, Control Building, Diesel Generator Building, and Fuel Building. As a 
 Scoping and Screening Methodology 

 2-15 

result of the revision to the 10 CFR 54.4(a)(2) implementing document, the 

nonsafety-related SSCs that were previously excluded from the scope of license 

renewal using information contained in the Moderate Energy Crack Evaluation 

and could interact with safety-related SSCs in the Auxiliary Building, Control 

Building, Diesel Generator Building, and Fuel Building were evaluated and 

included within the scope of license renewal in accordance with criterion 

10 CFR 54.4(a)(2). 

The staff reviewed the applicant’s response to RAI 2.1-2 and determined that the applicant had 

revised its process and evaluated nonsafety-related SSCs in the auxiliary building, control 

building, diesel generator building, fuel building, and anywhere near safety-related SSCs. This 

evaluation determined if there is a potential for spatial interaction without consideration of the 

previously cited Moderate Energy Crack Evaluation. As a result of the process revision and the 

evaluation subsequently performed, the applicant has included additional nonsafety-related 

SSCs within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). The staff 

determined that the revised process is in accordance with the requirements of 

10 CFR 54.4(a)(2) and is, therefore, acceptable. RAI 2.1-2 is closed. 

RAI 2.1-3, dated December 23, 2009, states that during the scoping and screening methodology 

audit, performed onsite October 19-22, 2009, the staff determined that the following 

nonsafety-related SSCs had not been included within the scope of license renewal. The staff 

asked that the applicant perform a review and provide the basis for not including the following 

nonsafety-related SSCs, attached or adjacent to safety-related SSCs, within the scope of 

license renewal in accordance with 10 CFR 54.4(a)(2): 

(1) Nonsafety-related pipe attached to the safety-related penetration of the condensate 

storage tank 

(2) Nonsafety-related, abandoned containment spray chemical addition tanks, located in the 

auxiliary building along with safety-related SSCs, for which the associated piping had 

been cut and capped but the tanks had not been verified to be dry (PVNGS Units 1 

and 3) 

(3) Nonsafety-related, fluid-filled SSCs located within the turbine building and adjacent to a 

penetration into the safety-related main steam support structure (MSSS) 

(4) Nonsafety-related, fluid-filled SSCs located on the auxiliary building roof and adjacent to 

opening in the safety-related MSSS 

The applicant responded to RAI 2.1-3(1) by a letter dated February 5, 2010, which states the 

following: 

The non-highlighted nonsafety-related piping attached to the condensate storage 

tank (CST) has been reviewed, and two of the six lines were added to the scope 

of license renewal based on criterion 10 CFR 54.4(a)(3). The scoping 

methodology did not preclude the identification of these two lines. These lines 

were identified as a result of correcting the tank level during the review. License 

Renewal boundary drawing PVNGS-CT-01-M-CTP-001 has been revised 

(Revision 3) to add the following LR Note 1 that provides the bases for the 

conclusion that the other four nonsafety-related piping lines attached to the CST 

are not within the scope of license renewal: 

The tank penetrations are above the minimum required tank level, 

and therefore the piping and components are not required to 

maintain the tank pressure boundary. The pipe sizes are much 

smaller than the tank, and consequently impose no structural 

impact because they do not have a structural integrity function nor 
Scoping and Screening Methodology 

 2-16 

do the lines have a spatial interaction with safety-related 

components, and are not within the scope of license renewal 

based on criterion 10 CFR 54.4(a)(2). The tank penetrations are 

not associated with venting. Consequently, the piping and 

components are not within the scope of license renewal for SBO 

based on 10 CFR 54.4(a)(3). 

The staff reviewed the applicant’s response to RAI 2.1-3(1) and determined that the applicant 

had provided documentation of an evaluation and basis for not including within the scope of 

license renewal four of the six nonsafety-related pipes attached to the CST. The staff 

determined that the applicant had provided documentation of the basis that two of the 

six nonsafety-related pipes attached to the CST had been re-evaluated and determined to have 

a 10 CFR 54.4(a)(3) intended function and appropriately included within the scope of license 

renewal. RAI 2.1-3(1) is resolved. 

The applicant responded to RAI 2.1-3(2) by letter dated April 2, 2010, which states the following: 

The containment spray chemical addition tanks were taken out of service and 

abandoned in Units 1, 2, and 3. However, a residual amount of fluid containing a 

diluted solution of the original chemical was identified to be captured in the 

Units 1 and 3 tanks, and suspected in the associated piping in all three units. 

The following commitment is being added to LRA Table A4-1, License Renewal 

Commitments. 

By August 30, 2010, APS will ensure that that the abandoned 

containment spray chemical addition tanks and associated piping 

components in PVNGS Units 1, 2, and 3 are drained to preclude 

any spatial interactions with safety-related components. 

When these actions are completed, the Units 1, 2, and 3 abandoned containment 

spray chemical addition tanks and the associated piping components will not be 

within the scope of license renewal. 

The staff determined that, in order to resolve the concern in RAI 2.1-3(2), it needs confirmation 

that the abandoned containment spray chemical addition tanks and associated piping 

components in PVNGS Units 1, 2, and 3 are drained to prevent any spatial interactions with 

safety-related components. This was identified as Confirmatory Item 2.1.4.2-1. 

By letter dated November 10, 2010, the applicant stated that the containment spray chemical 

addition tanks and associated piping components have been drained. The concern in 

RAI 2.1-3(2) is resolved and Confirmatory Item 2.1.4.2-1 is closed. 

The applicant responded to RAI 2.1-3(3) by letter dated February 5, 2010, which states the 

following: 

During a site audit conducted for initial plant licensing, the NRC staff questioned 

the ability of a fire to spread through the unprotected wall opening between 

elevation 120 feet of the main steam support structure (MSSS) and the turbine 

building. The NRC question and APS response is documented in UFSAR 

Section 9A, Question 9A.121, and the response was accepted by the NRC in 

Section 9.5.1.3 of Supplement No. 6 to the PVNGS Safety Evaluation Report 

(NUREG-0857). In the response, APS indicated that the wall openings between 

the MSSS and the turbine building are unsealed to allow cooling of the hot piping 

anchor/support attachments at the concrete structure. A compartment devoid of 

in situ combustibles is located between zones 74A and 74B (formerly zone 74) of 

the MSSS and the turbine building. Ventilation exhaust fans use this 

compartment as a supply plenum to pull cooling air flow over the pipe 
 Scoping and Screening Methodology 

 2-17 

support/anchors from the turbine building and the MSSS. The air flow is away 

from the safety-related equipment in zones 74A and 74B. 

Based on this response, a failure of nonsafety-related, fluid-filled SSCs located 

within the turbine building and adjacent to a penetration will not result in any 

spray effect to the components in main steam support structure since the 

ventilation exhaust fans will pull air away from both the main steam support 

structure and the turbine building. Also, the safety-related components inside the 

MSSS are environmentally qualified to maintain intended functions during a 

single area line break inside the MSSS (UFSAR Section 10.3). Therefore, there 

are no fluid filled SSCs located within the turbine building whose failure could 

prevent satisfactory accomplishment of safety-related functions as described in 

10 CFR 54.4(a)(1). 

The staff reviewed the applicant’s response to RAI 2.1-3(3), which provided a discussion on the 

purpose of the wall openings between the turbine building and the MSSS. The openings direct 

airflow and the environmental qualification (EQ) of safety-related SSCs located within the 

MSSS. The staff determined that the applicant had provided an evaluation and basis for not 

including nonsafety-related SSCs, located in the turbine building, within the scope of license 

renewal. The potential for spatial interaction with safety-related SSCs in the MSSS was 

prevented by building design and mitigated by EQ of safety-related SSCs located in the MSSS. 

RAI 2.1-3(3) is resolved. 

The applicant responded to RAI 2.1-3(4) by letter dated February 5, 2010, which states the 

following: 

The MSSS is a safety-related Category I structure that provides shelter, 

protection, and support for the license renewal intended functions of the 

safety-related SSCs located inside the MSSS. The roofing membrane and the 

concrete and structural steel of the external walls, including any openings in the 

walls, are within scope of license renewal with license renewal intended functions 

of shelter, protection and support. The above grade portion of the MSSS is 

designed to be open to natural circulation of outside air (UFSAR 3.11.4) including 

the adjacent auxiliary building roof. The nonsafety-related fluid-filled SSCs 

located on the auxiliary building roof adjacent to the MSSS are evaluated as not 

within scope of license renewal based on criteria of 10 CFR 54.4(a)(2) leakage 

barrier considerations. This is because the walls of the MSSS, including any 

openings in the walls, are designed to be open to natural circulation of outside air 

and are evaluated as providing shelter, protection and support to any 

safety-related components inside the MSSS from rain and water spray arising 

from the failure of nonsafety-related fluid-filled SSCs on the auxiliary 

building roof. 

The staff reviewed the applicant’s response to RAI 2.1-3(4) and determined that the applicant 

had provided a discussion and evaluation on the purpose of the building openings; they are 

designed to allow airflow, but also, to provide protection to safety-related SSCs from outside 

moisture such as rain. The staff determined that the applicant had provided an evaluation and 

basis for not including nonsafety-related SSCs, located adjacent to the MSSS, within the scope 

of license renewal in that the potential for spatial interaction with safety-related SSCs was 

prevented by building design. RAI 2.1-3(4) is resolved. 

2.1.4.2.3 Conclusion 

On the basis of its review of the applicant’s scoping process, discussions with the applicant, and 

review of the information provided in the response to RAIs 2.1-2 and 2.1-3, the staff concludes 

that the applicant’s methodology for identifying and including nonsafety-related SSCs that could 
Scoping and Screening Methodology 

 2-18 

affect the performance of safety-related SSCs within the scope of license renewal is consistent 

with the scoping criteria of 10 CFR 54.4(a)(2), and, therefore, is acceptable. 

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

2.1.4.3.1 Summary of Technical Information in the Application 

LRA Section 2.1.2.3, “Title 10 CFR 54.4(a)(3) - Regulated Events,” states the following: 

10 CFR 54.4(a)(3) requires that plant SSCs within the scope of license renewal 

include all SSCs relied on in safety analyses or plant evaluations to perform a 

function that demonstrates compliance with the regulations for fire protection 

(10 CFR 50.48), environmental qualification (10 CFR 50.49), pressurized thermal 

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

station blackout (10 CFR 50.63). Position papers were prepared to provide input 

to the SSC scoping process. The purpose of these position papers was to 

evaluate the PVNGS CLB relative to the regulated events, identify the systems 

and structures that are relied upon to demonstrate compliance with each of these 

regulations, and document the results of this review. Guidance provided by the 

position papers was used during system and structure scoping to identify system 

and structure intended functions for Criterion (a)(3), and again during component 

scoping as necessary to determine which components are credited in the 

regulated events. SSCs credited in the regulated events have been classified as 

satisfying criterion 10 CFR 54.4(a)(3) and have been identified as within the 

scope of license renewal. 

Fire Protection. LRA Section 2.1.2.3.1, “Fire Protection,” describes the scoping of systems and 

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

demonstrates compliance with the fire protection criterion. LRA Section 2.1.2.3.1 states the 

following: 

Criterion 10 CFR 54.4(a)(3) requires that plant SSCs within the scope of license 

renewal include all SSCs relied on in safety analyses or plant evaluations to 

perform a function that demonstrates compliance with the regulations for fire 

protection (10 CFR 50.48). 10 CFR 50.48 requires each operating nuclear power 

plant to have a fire protection plan that satisfies the requirement of Criterion 3 of 

10 CFR 50 Appendix A, and further requires all nuclear power plants licensed to 

operate prior to January 1, 1979, to comply with Sections III.G, III.J and III.O of 

Appendix R to 10 CFR 50. 

The PVNGS Fire Protection Program licensing basis is based on Appendix A to 

Branch Technical Position (BTP) APCSB 9.5-1, “Guidelines for Fire Protection for 

Nuclear Power Plants Docketed Prior to July 1, 1976” and 10 CFR 50, 

Appendix R, “Fire Protection Program for Nuclear Power Facilities Operating 

Prior to January 1, 1979.” The primary CLB document for PVNGS is UFSAR 

Section 9.5.1, “Fire Protection System.” Appendices 9A and 9B of the UFSAR 

provide the fire hazards analysis and other information concerning the design 

and license bases, including comparisons to Appendix A to BTP APCSB 9.5-1 

and to 10 CFR 50 Appendix R. PVNGS Fire Hazards Analysis is presented in 

UFSAR Appendix 9B.2. The Fire Hazards Analysis shows that redundant safety 

systems required to achieve and maintain hot standby and cold shutdown are 

adequately protected against fire damage. 

The applicant included CLB SSCs classified as satisfying criterion 10 CFR 54.4(a)(3) related to 

fire protection that were identified for PVNGS as within the scope of license renewal. 
 Scoping and Screening Methodology 

 2-19 

Environmental Qualification. LRA Section 2.1.2.3.2, “Environmental Qualification (EQ),” 

describes the scoping of systems and structures relied on in safety analyses or plant 

evaluations to perform a function in compliance with the EQ criterion. LRA Section 2.1.2.3.2 

states the following: 

Criterion 10 CFR 54.4(a)(3) requires that plant SSCs within the scope of license 

renewal include all SSCs relied on in safety analyses or plant evaluations to 

perform a function that demonstrates compliance with the regulations for 

environmental qualification (10 CFR 50.49). The PVNGS environmental 

qualification (EQ) program applies to electrical equipment important to safety that 

is located in a harsh environment. The UFSAR, Section 3.11, states that 

environmental design criteria for PVNGS conform to 10 CFR 50, Appendix A, 

General Design Criterion 4, “Environmental and Missile Design Bases.” The 

safety-related systems and components required to mitigate the consequences 

of a design basis accident (DBA), or to attain a safe shutdown of the reactor, are 

designed to remain functional during and after exposure to normal operation 

environmental conditions and following the specific DBA which they are intended 

to mitigate. ... All components within the scope of the PVNGS EQ program 

which demonstrate compliance with 10 CFR 50.49 and the systems containing 

those components were classified as satisfying criterion 10 CFR 54.4(a)(3) and 

were identified as within the scope of license renewal. 

Pressurized Thermal Shock. LRA Section 2.1.2.3.3, “Pressurized Thermal Shock (PTS),” states 

the following: 

Criterion 10 CFR 54.4(a)(3) requires that plant SSCs within the scope of license 

renewal include all SSCs relied on in safety analyses or plant evaluations to 

perform a function that demonstrates compliance with the regulations for 

pressurized thermal shock (10 CFR 50.61). 

The applicant determined that the only component within the scope of the license renewal rule 

for PTS is the reactor pressure vessel. The applicant stated that the calculation of nil-ductility 

transition reference temperature is a TLAA, as defined by 10 CFR 54.3(a). Chapter 4 of the 

applicant’s LRA addresses this separately. 

Anticipated Transient Without Scram. LRA Section 2.1.2.3.4, “Anticipated Transients Without 

Scram,” (ATWS) describes the scoping of systems and structures relied on in safety analyses or 

plant evaluations to perform a function in compliance with the ATWS criterion. LRA 

Section 2.1.2.3, Subsection 2.1.2.3.4, states the following: 

Criterion 10 CFR 54.4(a)(3) requires that plant SSCs within the scope of license 

renewal include all SSCs relied upon in safety analyses or plant evaluations to 

perform a function that demonstrates compliance with the regulations for 

anticipated transients without scram (10 CFR 50.62). An anticipated transient 

without scram (ATWS) is a postulated operational transient that generates an 

automatic scram signal accompanied by a failure of the reactor protection system 

to shutdown the reactor. The ATWS Rule required improvements in the design 

to reduce the probability of failure to shutdown the reactor following anticipated 

transients, and to mitigate the consequences of an ATWS event. ... The following 

equipment is required by the ATWS Rule for reduction of risk from an ATWS 

event at PVNGS: 

 Supplementary protection system which includes the diverse scram 

system 

 Diverse auxiliary feedwater actuation system 
Scoping and Screening Methodology 

 2-20 

 Diverse turbine trip circuitry 

The applicant further stated that components designed to satisfy the ATWS rule which 

demonstrate compliance with 10 CFR 50.62, were classified as satisfying criterion 

10 CFR 54.4(a)(3) and were identified as within the scope of license renewal. 

Station Blackout. LRA Section 2.1.2.3, Subsection 2.1.2.3.5, “Station Blackout,” (SBO) 

describes the scoping of systems and structures relied on in safety analyses or plant 

evaluations to perform a function in compliance with the SBO criterion. LRA Section 2.1.2.3.5, 

states the following: 

Criterion 10 CFR 54.4(a)(3) requires that plant SSCs within the scope of license 

renewal include all SSCs relied on in safety analyses or plant evaluations to 

perform a function that demonstrates compliance with the regulations for station 

blackout (10 CFR 50.63). The SBO rule (10 CFR 50.63) requires that nuclear 

power plants have the capability to withstand and recover from the loss of offsite 

and onsite AC power of a specified duration (the coping duration). Regulatory 

Guide 1.155 provides guidance on selecting the time period for which a licensee 

must cope with the SBO. PVNGS used RG 1.155 to calculate a plant-specific 

coping time period. A “sixteen hour” coping duration was determined for PVNGS 

based on expected frequency of loss of offsite power and the probable time 

needed for its restoration. Redundancy and reliability in onsite emergency AC 

power source (emergency diesel generators) was also factored in the evaluation. 

The applicant developed a position paper to summarize the results of a detailed review of the 

SBO documentation. The position paper identifies the SSCs credited with coping and 

recovering from a SBO. The SSCs identified in the SBO position paper were used in scoping 

evaluations to identify SSCs that demonstrate compliance with 10 CFR 50.63. The LRA 

included all SSCs classified as satisfying criterion 10 CFR 54.4(a)(3) related to SBO as within 

the scope of license renewal. 

2.1.4.3.2 Staff Evaluation 

The staff reviewed the applicant’s approach in identifying SSCs relied on to perform functions 

meeting the requirements of the regulations on fire protection, EQ, ATWS, PTS, and SBO. The 

staff reviewed the applicant’s methodology, boundary scoping drawings, position papers, and 

LRA to assess the scoping process for these regulated safety systems. The staff also 

evaluated, on a sampling basis, the SSCs included within the scope of license renewal under 

10 CFR 54.4(a)(3). 

The staff confirmed that the applicant’s implementing procedures, as described in LRA 

Section 2.1.1.1.3, “Technical Position Papers,” were used for identifying SSCs within the scope 

of license renewal under 10 CFR 54.4(a)(3). The applicant evaluated the PVNGS CLB to 

identify all SSCs that perform functions addressed in 10 CFR 54.4(a)(3), “Regulated Events,” 

and then included these SSCs within the scope of license renewal as documented in the 

specific regulated event(s) position papers. The staff determined that these position paper 

results reference the information sources used for determining the SSCs credited for 

compliance with the events listed in the specified regulations for the applicable license renewal 

regulated events. 

Fire Protection. The staff determined that the applicant’s fire protection scoping documents 

identified SSCs in the scope of license renewal required for fire protection. The applicant used 

documents, such as the UFSAR, fire protection design basis calculations, and the Fire 

Protection Design Basis Manual, to identify the SSCs within the scope of license renewal for fire 

protection. The staff reviewed the source documents used by the applicant to identify SSCs 
 Scoping and Screening Methodology 

 2-21 

within the scope of license renewal, primarily the UFSAR, Section 9.5.1, “Fire Protection 

Systems.” 

The staff also reviewed, on a sampling basis, the scoping results in conjunction with the LRA 

and the CLB information to validate the methodology for including SSCs within the scope of 

license renewal. The staff determined that the applicant’s scoping included SSCs that perform 

intended functions to meet the requirements of 10 CFR 50.48. Based on its review of the CLB 

documents and the sample review, the staff determined that the applicant’s scoping 

methodology is adequate for including SSCs credited in performing fire protection functions 

within the scope of license renewal. 

Environmental Qualification. The staff confirmed that the applicant’s EQ scoping document 

required the inclusion of safety-related electrical equipment, nonsafety-related electrical 

equipment whose failure under postulated environmental conditions could prevent satisfactory 

accomplishments of safety functions of the safety-related equipment, and certain post-accident 

monitoring equipment, as defined in 10 CFR 50.49(b)(1), (b)(2), and (b)(3). The staff 

determined that the applicant used the CLB, as described in the UFSAR Section 3.11 and its 

EQ program manual, to identify SSCs necessary to meet the requirements of 10 CFR 50.49. 

SWMS, the site’s equipment database, contains the EQ identifications for specific components. 

The staff reviewed the LRA, implementing procedures, scoping results reports, and master EQ 

component equipment list in the equipment database to verify that the applicant identified SSCs 

within the scope of license renewal that meet EQ requirements. Based on that review, the staff 

determined that the applicant’s scoping methodology is adequate for identifying EQ SSCs within 

the scope of license renewal. 

Pressurized Thermal Shock. The staff confirmed that the applicant’s PTS scoping document 

included the scoping methodology used to review the CLB information to identify SSCs within 

the scope of license renewal to meet 10 CFR 50.61, “Fracture Toughness Requirements for 

Protection Against Pressurized Thermal Shock Events.” The applicant’s scoping methodology 

resulted in a determination that the reactor vessel is within the scope of license renewal. The 

staff reviewed the basis document and position paper and determined that the methodology was 

appropriate for identifying SSCs with functions credited for complying with the PTS regulation. 

The staff finds that the scoping results included SSCs that perform intended functions to meet 

the requirements of 10 CFR 50.61. The staff determined that the applicant’s scoping 

methodology is adequate for including SSCs within the scope of license renewal which are 

credited in meeting PTS requirements. 

Anticipated Transient Without Scram. The staff confirmed that the applicant’s ATWS scoping 

document included the scoping methodology used to review the CLB and the site equipment 

database to identify plant SSCs within the scope of license renewal which are credited for 

ATWS mitigation. The staff reviewed these documents, and the LRA, in conjunction with the 

scoping results to validate the methodology for identifying ATWS SSCs within the scope of 

license renewal. The staff determined that the scoping results included systems and structures 

that perform intended functions to meet 10 CFR 50.62 requirements. The staff determined that 

the applicant’s scoping methodology is adequate for identifying SSCs within the scope of 

license renewal which are credited in meeting the ATWS regulation. 

Station Blackout. The staff confirmed that the applicant’s SBO scoping document included the 

scoping methodology used to review CLB documents to identify SSCs within the scope of 

license renewal which are credited for SBO mitigation. The CLB documents used by the 

applicant include the plant-specific SBO calculations, UFSAR, drawings, modifications, the site 

equipment database, and plant procedures. On a sampling basis, the staff reviewed these 

documents and the LRA, in conjunction with the scoping results, to validate the applicant’s 

methodology. The staff finds that the scoping results included SSCs that perform intended 

functions meeting 10 CFR 50.63 requirements. The staff determined that the applicant’s 
Scoping and Screening Methodology 

 2-22 

scoping methodology is adequate for identifying SSCs within the scope of license renewal which 

are credited in complying with the SBO regulation. 

2.1.4.3.3 Conclusion 

On the basis of the sample reviews, discussions with the applicant, review of the LRA, and 

review of the implementing procedures and reports, the staff concludes that the applicant’s 

methodology for identifying systems and structures meets the scoping criteria pursuant to 

10 CFR 54.4(a)(3) and, therefore, is acceptable. 

2.1.4.4 Plant-Level Scoping of Systems and Structures 

2.1.4.4.1 Summary of Technical Information in the Application 

System and Structure Level Scoping. LRA Section 2.1, “Scoping and Screening Methodology,” 

states the following: 

For systems, structures and components (SSCs) within the scope of license 

renewal, 10 CFR 54.21(a)(1) requires the license renewal applicant to identify 

and list the structures and components subject to an aging management review 

(AMR). 10 CFR 54.21(a)(2) further requires that the methods used to implement 

the requirements of 10 CFR 54.21(a)(1) be described and justified. This section 

of the application provides a description and justification of the methodology used 

to identify and list structures and components that are within the scope of license 

renewal and subject to an AMR. PVNGS Unit 1, Unit 2, and Unit 3 are 

constructed of similar materials with similar environments. Unless otherwise 

noted throughout this application, plant systems and structures discussed in this 

application apply to PVNGS Units 1, 2 and 3. 

LRA Section 2.1.1, “Introduction,” states the following: 

The first step in the integrated plant assessment (IPA) process identified the 

plant SSCs within the scope of 10 CFR 54. This step is called scoping. For 

those SSCs identified to be within the scope of the license renewal rule, the 

second step of the IPA process then identified and listed the structures and 

components that are subject to an AMR. This step of the process is called 

screening. The scoping and screening steps have been performed consistent 

with the requirements of 10 CFR 54, the Statements of Consideration supporting 

the license renewal rule, and the guidance provided in NEI 95-10, “Industry 

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

Renewal Rule.” Section 2.1.1.1 provides a discussion of the documentation used 

to perform scoping and screening. 

LRA Section 2.1.3, “Scoping Methodology,” states the following: 

Scoping of the SSCs was performed to the criteria of 10 CFR 54.4(a) to identify 

those SSCs within the scope of the license renewal rule. The scoping evaluation 

results have been retained in the license renewal database. The following 

sections describe the methodology used for scoping. Separate discussions of 

mechanical system scoping methodology, structures scoping methodology, and 

electrical and I&C system scoping methodology are provided. 

2.1.4.4.2 Staff Evaluation 

The staff reviewed the applicant’s methodology for the scoping of plant systems and 

components to ensure consistency with 10 CFR 54.4. The applicant documented the 

methodology used to determine the systems and components within the scope of license 

renewal in implementing procedures and scoping result reports for each system. The scoping 
 Scoping and Screening Methodology 

 2-23 

process defined the plant in terms of systems and structures. Specifically, the implementing 

procedures identify the systems and structures that are subject to 10 CFR 54.4 review, describe 

the processes for capturing the results of the review, and determine if the system or structure 

performs intended functions consistent with the criteria of 10 CFR 54.4(a). The applicant 

completed the scoping process for all systems and structures to ensure that it addressed the 

entire plant. 

The applicant documented the results of the plant-level scoping process in accordance with the 

implementing documents and provided the results in the systems and structures documents and 

reports. These results included information such as a description of the structure or system, a 

listing of functions performed by the system or structure, description of intended functions, 

10 CFR 54.4(a) scoping criteria met by the system or structure, references, and the basis for the 

intended function classification of the system or structure. During the audit, the staff reviewed a 

sampling of the documents and reports and concluded that the applicant’s scoping results 

contained an appropriate level of detail to document the scoping process. 

2.1.4.4.3 Conclusion 

Based on its review of the LRA, site guidance documents, and a sampling of system scoping 

results reviewed during the audit, the staff concludes that the applicant’s methodology for 

identifying SSCs, and their intended functions, within the scope of license renewal is consistent 

with the requirements of 10 CFR 54.4 and, therefore, is acceptable. 

2.1.4.5 Mechanical Scoping 

2.1.4.5.1 Summary of Technical Information in the Application 

LRA Section 2.1.3.1 states the following: 

A list of all mechanical systems was developed using the plant equipment 

database and system plant numbering procedure and is documented in the Plant 

Systems and Aging Management Programs Position Paper. These mechanical 

systems were evaluated to each of the criteria of 10 CFR 54.4(a). 

LRA Section 2.1.3.1 further states that for each system, the applicant performed the following: 

Identification of the System Purpose and Functions. A description was prepared 

for each mechanical system that included the purpose and summarized the 

functions that the system was designed to perform. This summary description 

was prepared using information obtained from the UFSAR system descriptions, 

current licensing basis documents, design basis documents (including piping and 

instrumentation drawings), and system operating descriptions. 

Determination of the System Evaluation Boundary. After the system functions 

were identified, the system evaluation boundary was determined and marked-up 

on piping and instrumentation drawings. All of the components needed for the 

system to perform its intended functions are included within the license renewal 

boundary. 

Comparison of System Functions Against 10 CFR 54.4(a)(1-3). All system 

functions were compared against the criteria of 10 CFR 54.4(a)(1), (a)(2) and 

(a)(3). The system functions were identified from the information sources 

previously described. Each of the system functions satisfying the scoping criteria 

in 10 CFR 54.4(a) was identified as a system intended function. Functions 

performed by safety-related portions of the evaluated system were identified as 

satisfying criterion (a)(1) and were classified as intended functions. Functions 

performed by nonsafety-related systems or parts of systems that are required to 

ensure success of a safety-related function were identified as satisfying criterion 
Scoping and Screening Methodology 

 2-24 

(a)(2) and classified as intended functions. Functions that were credited in one 

of the regulated events were identified as satisfying criterion (a)(3) and classified 

as intended functions. A function may have been classified as an intended 

function under more than one of the three criteria in 10 CFR 54.4. Any system 

that performed one or more intended functions (i.e., satisfying criterion (a)(1), 

(a)(2), or (a)(3)) was classified as a system within the scope of the license 

renewal rule. 

Identification of Supporting Systems. After a system was determined to be in the 

scope of the Rule for criteria (a)(1) or (a)(3), an evaluation was performed to 

identify all of its supporting systems. Each of the supporting systems was then 

reviewed to determine if its failure could prevent satisfactory accomplishment of 

any intended functions of the in-scope system. When it was determined that a 

supporting system was needed to maintain an intended function of the in-scope 

system, the supporting system was determined to be in-scope. When a 

supporting system was identified as being in-scope, the scoping evaluation for 

the supporting system was reviewed and revised as necessary. This step in the 

scoping process ensured that all supporting systems’ intended functions were 

identified. 

Component Level Scoping. A component was determined to be in-scope if it was 

determined that the component was needed to fulfill a system intended function 

meeting the safety-related criteria of 10 CFR 54.4(a)(1), the nonsafety-related 

affecting safety-related criterion of 10 CFR 54.4(a)(2), and/or if the component 

was needed to support the criteria of 10 CFR 54.4(a)(3) for regulated events. 

Components meeting one of these three criteria were identified in the license 

renewal database as within the scope of the Rule. Components not meeting one 

of these three criteria were identified in the license renewal database as out of 

scope. 

2.1.4.5.2 Staff Evaluation 

The staff evaluated LRA Section 2.1.3.1 and the guidance in the implementing procedures and 

reports to review the mechanical scoping process. The project documents and reports provided 

instructions for identifying the evaluation boundaries. The staff reviewed the implementing 

documents and the CLB documents associated with mechanical system scoping, and found that 

the guidance and CLB source information noted above are acceptable to identify mechanical 

components and support structures in mechanical systems that are within the scope of license 

renewal. The staff had detailed discussions with the applicant’s license renewal project 

personnel and reviewed documentation pertinent to the scoping process. The staff assessed if 

the applicant had appropriately applied the scoping methodology outlined in the LRA and 

implementing procedures and if the scoping results were consistent with CLB requirements. 

The staff determined that the applicant’s procedure is consistent with the description provided in 

LRA Section 2.1.3.1 and the guidance contained in the SRP-LR, Section 2.1, and that the 

applicant adequately implemented this procedure. 

On a sampling basis, the staff reviewed the applicant’s scoping reports for the safety injection 

and shutdown cooling system, diesel generator fuel oil storage and transfer system, and 

auxiliary feedwater system mechanical component types that met the scoping criteria of 

10 CFR 54.4. The staff also reviewed the implementing procedures and discussed the 

methodology and results with the applicant. The staff verified that the applicant had identified 

and used pertinent engineering and licensing information in determining the safety injection and 

shutdown cooling system, diesel generator fuel oil storage and transfer system, and auxiliary 

feedwater system mechanical component types required to be within the scope of license 

renewal. As part of the review process, the staff evaluated each system’s intended function, the 
 Scoping and Screening Methodology 

 2-25 

basis for inclusion of the intended function, and the process used to identify each 

component type. 

The staff verified that the applicant had identified and highlighted system P&IDs to develop the 

license renewal boundaries in accordance with the procedural guidance. Additionally, the staff 

determined that the applicant had independently verified the results in accordance with the 

governing procedures. The staff confirmed that knowledgeable personnel, familiar with plant 

systems and license renewal, were utilized by the applicant to perform independent reviews of 

the marked-up drawings to ensure accurate identification of system intended functions. The 

staff also confirmed that the applicant had performed additional cross-discipline verification and 

independent reviews of the resultant highlighted drawings before final approval of the 

scoping effort. 

2.1.4.5.3 Conclusion 

On the basis of its review of the LRA, scoping implementing procedures, and the sampling 

system review of mechanical scoping results, the staff concludes that the applicant’s 

methodology for identifying mechanical SSCs within the scope of license renewal is in 

accordance with the requirements of 10 CFR 54.4 and, therefore, is acceptable. 

2.1.4.6 Structural Scoping 

2.1.4.6.1 Summary of Technical Information in the Application 

LRA Section 2.1.3.2, “Structure Scoping Methodology,” states the following: 

A list of all structures was developed that included buildings, tank foundations, 

and other miscellaneous structures. The list of structures used for scoping was 

developed through review of site plot drawings in conjunction with a walkdown of 

the property. The UFSAR was relied upon to identify the safety classifications of 

structures and structural components. Category I structures and structural 

components were considered safety-related. 

Structure descriptions were prepared, including the structure purpose and all 

functions. Structure evaluation boundaries were determined, including 

examination of structure interfaces. This information was included in the license 

renewal database. All structure functions were evaluated against the criteria of 

10 CFR 54.4(a)(1), (a)(2) and (a)(3) and the results of this evaluation were 

documented in the license renewal database. In those instances where the 

structure intended functions required support from other structures or systems, 

the supporting systems or structures were identified and evaluated against the 

criteria in 10 CFR 54.4(a)(2). A list of references supporting the evaluation of 

each structure was documented in the license renewal database. 

For structures determined to be within the scope of license renewal, structural 

drawings were reviewed to identify structural elements (such as steel structures, 

foundations, floors, walls, ceilings, penetrations, stairways or curbs). For 

in-scope structures, all structural components that are required to support the 

intended functions of the structure were entered into the license renewal 

database and were identified as in-scope of license renewal. Some individual 

structural components fabricated from the same material and exposed to the 

same environment were replaced in the database with a generic component, 

such as “Structural Steel” to represent all of the carbon steel beams and columns 

in a given building. For each in-scope structure, all of the structural components 

listed in the license renewal database were evaluated and a determination was 

made as to whether the structural component was required to support the 

intended functions of the structure. Structural components that support the 
Scoping and Screening Methodology 

 2-26 

intended functions of the structure were identified in the license renewal 

database as within the scope of license renewal. 

2.1.4.6.2 Staff Evaluation 

The staff evaluated LRA Section 2.1.3.2 and the guidance in the implementing procedures and 

reports to review the structural scoping process. The project documents and reports provided 

instructions for identifying the evaluation boundaries. The staff reviewed the applicant’s 

approach for identifying structures relied upon to perform the functions described in 

10 CFR 54.4(a). As part of this review, the staff discussed the methodology with the applicant, 

reviewed the documentation developed to support the review, and evaluated the scoping results 

for a sample of structures (e.g., turbine building) that were identified within the scope of license 

renewal. The staff determined that the applicant had identified and developed a list of plant 

structures and the structures intended functions through a review of the site equipment 

database, UFSAR, drawings, system notebook, and walkdowns. Each structure the applicant 

identified was evaluated against the criteria of 10 CFR 54.4(a)(1), (a)(2), and (a)(3). 

The staff reviewed selected portions of the plant equipment database, CLB information, 

drawings, and implementing procedures to verify the adequacy of the methodology. The staff 

reviewed the applicant’s methodology for identifying structures meeting the scoping criteria as 

defined in 10 CFR 54.4(a). The staff also reviewed the scoping methodology implementing 

procedures and discussed the methodology and results with the applicant. In addition, on a 

sampling basis, the staff reviewed the applicant’s scoping reports, including information 

contained in the source documentation, for the turbine building, to verify that the application of 

the methodology would provide the results as documented in the LRA. 

The staff verified that the applicant identified and used pertinent engineering and licensing 

information in order to determine that the turbine building was required to be included in the 

scope of license renewal. As part of the review process, the staff evaluated the intended 

functions identified for the turbine building, the structural components within the building, the 

basis for inclusion of the intended function, and the process used to identify each of the 

component types. 

2.1.4.6.3 Conclusion 

On the basis of its review of information in the LRA, scoping implementation procedures, and a 

sampling review of structural scoping results for the turbine building, the staff concludes that the 

applicant’s methodology for identification of the structural SSCs within the scope of license 

renewal is in accordance with the requirements of 10 CFR 54.4 and, therefore, is acceptable. 

2.1.4.7 Electrical Component Scoping 

2.1.4.7.1 Summary of Technical Information in the Application 

LRA Section 2.1.3.3, “Electrical and I&C System Scoping Methodology” states the following: 

Scoping process for electrical and instrumentation and control (I&C) systems was 

performed by a system level scoping and then a component level scoping. 

System level scoping methodology was performed similar to the mechanical 

system-level scoping, which utilized the UFSAR descriptions, database records, 

current licensing basis documents and design basis documents that were 

applicable to the system. Furthermore, the system safety classification and all 

systems functions were determined by reviewing these documents and were 

evaluated against the criteria of 10 CFR 54.4(a)(1), (a)(2) and (a)(3). The 

component level scoping methodology included all electrical and I&C 

components that perform an intended function as described in 10 CFR 54.4 for 

systems within the scope of license renewal. Furthermore, the scoping of 
 Scoping and Screening Methodology 

 2-27 

installed electrical components were identified by reviewing plant drawings and 

databases and a list of typical electrical components provided by NEI 95-10 was 

utilized to determine which electrical component types are installed. Any 

electrical component types that are installed but were not listed in the plant 

equipment database were added into the license renewal database for evaluation 

during component screening. 

2.1.4.7.2 Staff Evaluation 

The staff evaluated LRA Section 2.1.3.3 and the guidance contained in the implementing 

procedures and reports to review the electrical scoping process. The staff reviewed the 

applicant’s approach to identifying electrical and I&C SSCs relied upon to perform the functions 

described in 10 CFR 54.4(a). The staff reviewed portions of the documentation used by the 

applicant to perform the electrical scoping process including the UFSAR, plant equipment 

database, CLB documentation, documents, procedures, drawings, specifications, codes, 

and standards. 

The staff noted that after the applicant completed the electrical and I&C component scoping, 

it categorized in-scope electrical components into component types. These component types 

include electrical and I&C components with common characteristics and functions, such as 

cable, connections, fuse holders, terminal blocks, high-voltage transmission conductor, 

connections and insulators, metal enclosed bus, switchyard bus, and connections. 

As part of this review, the staff discussed the methodology with the applicant, reviewed the 

implementing procedures developed to support the review, and evaluated a sampling of the 

scoping results of SSCs that were identified as within the scope of license renewal. The staff 

determined that the applicant had included electrical and I&C components, including electrical 

and I&C components contained in mechanical or structural systems, within the scope of license 

renewal on a commodity basis. 

2.1.4.7.3 Conclusion 

On the basis of its review of information contained in the LRA, scoping implementing 

procedures, scoping bases documents, and review of a sample of electrical scoping results, the 

staff concludes that the applicant’s methodology for the scoping of electrical components within 

the scope of license renewal is in accordance with the requirements of 10 CFR 54.4, and 

therefore, is acceptable. 

2.1.4.8 Scoping Methodology Conclusion 

On the basis of its review of the LRA, implementing procedures, and a review of a sample of 

scoping results, the staff concludes that the applicant’s scoping methodology is consistent with 

the guidance contained in the SRP-LR, and identified those SSCs, (1) that are safety-related, 

(2) whose failure could affect safety-related functions, and (3) that are necessary to 

demonstrate compliance with the NRC’s regulations for fire protection, EQ, PTS, ATWS, and 

SBO. The staff concluded that the applicant’s methodology is consistent with the requirements 

of 10 CFR 54.4(a), and, therefore, is acceptable. 

2.1.5 Screening Methodology 

2.1.5.1 General Screening Methodology 

2.1.5.1.1 Summary of Technical Information in the Application 

LRA Section 2.1.4, “Screening Methodology,” and accompanying subsections, describe the 

screening process that identifies the SCs within the scope of license renewal that are subject to 

an AMR. Section 2.1.4 states the following: 
Scoping and Screening Methodology 

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Screening is the process of identifying, and listing the structures and components 

that are subject to an aging management review. This section, and the 

accompanying subsections for mechanical systems, electrical and instrument 

and control systems, and structures, describes the process used to perform 

screening. All SSCs listed in the license renewal database were scoped to the 

criteria of 10 CFR 54.4(a). All of the structures and components categorized as 

within the scope of license renewal were screened against the criteria of 

10 CFR 54.21(a)(1)(i) and (1)(ii) to determine whether they are subject to aging 

management review. The screening methodology utilized is described in this 

section of the application. The word “passive” is used in the screening process 

for all components that perform intended functions without moving parts, or a 

change in configuration or properties. All components that are not “passive” are 

known as “active”. The word “long-lived” is used in the screening process for all 

components that are not subject to replacement based on qualified life or specific 

time period. Components that are not “long-lived” are known as “short-lived.” 

NEI 95-10, Appendix B, “Typical Structure, Component and Commodity 

Groupings and Active/Passive Determinations for the Integrated Plant 

Assessment,” provides industry guidance for screening structures and 

components. The guidance provided in NEI 95-10, Appendix B, has been 

incorporated into the license renewal screening process. Slightly differing 

screening methodologies have been applied for mechanical systems, electrical 

and instrument and control systems, and structures. 

2.1.5.1.2 Staff Evaluation 

Under 10 CFR 54.21, each LRA must contain an IPA identifying SCs within the scope of license 

renewal that are subject to an AMR. The IPA must identify components that perform an 

intended function without moving parts or a change in configuration or properties (passive), as 

well as components that are not subject to periodic replacement based on a qualified life or 

specified period (long-lived). In addition, the IPA must include a description and justification of 

the methodology used to determine the passive and long-lived SCs and a demonstration that 

the effects of aging on those SCs will be adequately managed so that the intended functions will 

be maintained under all design conditions imposed by the plant-specific CLB for the period of 

extended operation. 

The staff reviewed the methodology used by the applicant to identify the mechanical and 

structural components and electrical commodity groups within the scope of license renewal that 

should be subject to an AMR. The applicant implemented a process for determining which SCs 

are subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1). In LRA 

Section 2.1.4, the applicant discusses these screening activities as they relate to the component 

types and commodity groups within the scope of license renewal. 

The staff determined that the screening process used by the applicant evaluated the component 

types and commodity groups included within the scope of license renewal to determine which 

ones were long-lived and passive and, therefore subject to an AMR. The staff reviewed LRA 

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 Controls Systems.” These sections provide the results of the process 

used to identify component types and commodity groups subject to an AMR. The staff also 

reviewed, on a sampling basis, the screening results reports for safety injection and shutdown 

cooling, diesel generator fuel oil storage and transfer, auxiliary feedwater, and turbine building. 

The applicant provided the staff with a detailed discussion of the processes used for each 

discipline and provided administrative documentation that described the screening 
 Scoping and Screening Methodology 

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methodology. SER Section 2.1.5.2, “Mechanical Component Screening,” Section 2.1.5.3, 

“Structural Component Screening,” and Section 2.1.5.4, “Electrical Component Screening,” 

below, discuss specific methods for mechanical, electrical, and structural component screening. 

2.1.5.1.3 Conclusion 

On the basis of its review of the LRA, the implementing procedures, and a review of a sample of 

screening results, the staff concludes that the applicant’s screening methodology is consistent 

with the guidance contained in the SRP-LR and identifies passive and long-lived components in 

the scope of license renewal that are subject to an AMR. The staff concludes that the 

applicant’s process for determining which component types and commodity groups subject to an 

AMR is consistent with the requirements of 10 CFR 54.21 and, therefore, is acceptable. 

2.1.5.2 Mechanical Component Screening 

2.1.5.2.1 Summary of Technical Information in the Application 

LRA Section 2.1.4.1 states the following: 

In mechanical systems, component screening was a continuation of the 

component scoping activity. After a mechanical system component was 

categorized in the license renewal database as in scope, the classification as an 

active or passive component was determined based on evaluation of the 

component description and type. The active/passive component determinations 

documented in NEI 95-10, revision 6, Appendix B, provided guidance for this 

activity. In-scope components that were determined to be passive and long-lived 

were identified in the license renewal database as subject to aging management 

review. 

Each component that was identified as subject to an aging management review 

was evaluated to determine its component intended function(s). The component 

intended function(s) was identified based on an evaluation of the component type 

and the way(s) in which the component supports the system intended functions. 

Most in-scope passive components perform only one intended function. 

However, a few in-scope component types may perform more than one function. 

The results of the component screening were recorded in the license renewal 

database. The list of component intended functions utilized in the screening of 

mechanical system components can be found in Table 2.1-1, “Intended 

Functions Abbreviations and Definitions.” 

During the screening process, a few in-scope passive components were 

identified in the screening process as short-lived components. Components that 

were identified during screening as short-lived were eliminated from the aging 

management review process and the basis for the classification as short-lived 

was documented in the license renewal database. All other in-scope passive 

components were identified in the license renewal database as subject to an 

aging management review. During the aging management review process, if 

detailed review of maintenance procedures and requirements determined that a 

component previously categorized as long-lived was subject to replacement 

based on a qualified life or specified time period; the component was 

re-categorized as short-lived and eliminated from the aging management review 

evaluation process. 

2.1.5.2.2 Staff Evaluation 

The staff reviewed the mechanical screening methodology discussed in LRA Section 2.1.4.1, 

the implementing documents, the scoping and screening reports, and the license renewal 
Scoping and Screening Methodology 

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drawings. The staff determined that the mechanical system screening process began with the 

results from the scoping process and that the applicant reviewed each system evaluation 

boundary as depicted on the P&IDs to identify passive and long-lived components. Additionally, 

the staff determined that the applicant had identified all passive and long-lived components that 

perform or support an intended function within the system evaluation boundaries and 

determined that those components are subject to an AMR. The results of the review are 

documented in the scoping and screening reports, which contain information such as the 

information sources reviewed and the intended functions of the component. 

The staff verified that the applicant established mechanical system evaluation boundaries for 

each system within the scope of license renewal and that it determined these boundaries by 

mapping the system boundary onto P&IDs. The staff confirmed that the applicant reviewed the 

components within the system boundary to determine whether the component supported the 

system intended function. The staff further confirmed that the applicant reviewed those 

components that supported the system’s intended function to determine whether the component 

was passive and long-lived and, therefore, subject to an AMR. 

The staff reviewed selected portions of the UFSAR, plant equipment database, CLB 

documentation, databases and documents, procedures, drawings, specifications, and selected 

scoping and screening reports. The staff conducted detailed discussions with the applicant’s 

license renewal team and reviewed documentation pertinent to the screening process. The staff 

also performed a walkdown of portions of the selected systems with plant engineers to verify 

documentation. The staff assessed whether the mechanical screening methodology outlined in 

the LRA and the associated procedures were appropriately implemented. The staff also 

assessed if the scoping results were consistent with CLB requirements. During the scoping and 

screening methodology audit, the staff discussed the screening methodology with the applicant 

and, on a sampling basis, reviewed the applicant’s screening reports for the safety injection and 

shutdown cooling system, diesel generator fuel oil storage and transfer system, and auxiliary 

feedwater system to verify proper implementation of the screening process. Based on these 

audit activities, the staff did not identify any discrepancies between the methodology 

documented and the implementation results. 

2.1.5.2.3 Conclusion 

On the basis of its review of the LRA, discussions with the applicant, screening implementation 

procedures, UFSAR, plant equipment database, CLB documentation, procedures, drawings, 

specifications, selected scoping and screening reports, and review of a sample of the safety 

injection and shutdown cooling system, diesel generator fuel oil storage and transfer system, 

and auxiliary feedwater system screening reports, the staff concludes that the applicant’s 

methodology for identification of mechanical components within the scope of license renewal 

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

acceptable. 

2.1.5.3 Structural Component Screening 

2.1.5.3.1 Summary of Technical Information in the Application 

LRA Section 2.1.4.2 states the following: 

Structures and structural components typically perform their functions without 

moving parts and without a change in configuration or properties. When a 

structure or structural component was determined to be in-scope of license 

renewal by the scoping process described in Section 2.1.3.2, the structure 

screening methodology classified the component as passive. This is consistent 

with guidance found in NEI 95-10, Revision 6, Appendix B. During the structural 

screening process, the intended function(s) of structural components were 
 Scoping and Screening Methodology 

 2-31 

determined and recorded in the license renewal database. In the structure 

screening process, an evaluation was made to determine whether in-scope 

structural components were subject to replacement based on a qualified time 

period. If an in-scope structural component was determined to be subject to 

replacement based on a qualified time period, the component was identified as 

short-lived and was excluded from an AMR. In such a case, the basis for 

determining that the structural component was short-lived was documented in the 

license renewal database. 

2.1.5.3.2 Staff Evaluation 

The staff reviewed the screening methodology used to identify structural components that are 

subject to an AMR as required in 10 CFR 54.21(a)(1) as discussed in LRA Sections 2.1.4.2, 

implementing procedures, scoping and screening reports, and license renewal drawings. The 

staff confirmed that the applicant had reviewed the structures included within the scope of 

license renewal, identified the passive, long-lived components with component level intended 

functions, and determined that those components are subject to an AMR. 

The staff reviewed selected portions of the UFSAR, structure system information, the plant 

equipment database, and scoping and screening reports that the applicant used to perform the 

structural scoping and screening. The staff also reviewed screening activities on a sampling 

basis that documented the SCs within the scope of license renewal. The staff had detailed 

discussions with the applicant’s license renewal team and reviewed documentation pertinent to 

the screening process to assess if the screening methodology outlined in the LRA and 

associated procedures were appropriately implemented and if the scoping results are consistent 

with CLB requirements. 

During the scoping and screening methodology audit, the staff reviewed, on a sampling basis, 

the applicant’s screening reports for the turbine building to verify proper implementation of the 

screening process. Based on these onsite review activities, the staff did not identify any 

discrepancies between the methodology documented and the implementation results. 

2.1.5.3.3 Conclusion 

Based on the staff’s review of information contained in the LRA, implementing procedures, plant 

equipment database, and a sampling of the turbine building screening results, the staff 

concludes that the applicant’s methodology for identifying structural components within the 

scope of license renewal and subject to an AMR is in accordance with the requirements of 

10 CFR 54.21(a)(1) and, therefore, is acceptable. 

2.1.5.4 Electrical Component Screening 

2.1.5.4.1 Summary of Technical Information in the Application 

LRA Section 2.1.4.3, “Electrical and I&C System Component Screening Methodology,” states 

that the screening of electrical and I&C components used a “spaces” approach that is consistent 

with the guidance in NEI 95-10. This approach is based on identifying areas where the 

bounding environmental conditions exist. It also states that the bounding environmental 

conditions are applied during the AMR in order to evaluate the aging effects that are associated 

with electrical component types that are located within the bounding area. The LRA states that 

the use of the “spaces” approach for AMR of electrical components types eliminates the need to 

associate electrical and I&C components with specific systems that are within the scope of 

license renewal. 

The LRA also states that the applicant categorized in-scope electrical components as “active” or 

“passive” based on the determinations documented in NEI 95-10, Appendix B. Furthermore, the 

LRA states that passive long-lived electrical and I&C components that perform an intended 
Scoping and Screening Methodology 

 2-32 

function without moving parts, or without change in configuration or properties, were grouped 

into component types such as cable, connections, fuse holders, terminal blocks, high-voltage 

transmission conductor, connections and insulators, metal enclosed bus, switchyard bus, and 

connections. The LRA states that component-level intended function(s) were determined for 

each in-scope passive electrical component type, identified in the license renewal database as 

being subject to AMR, and recorded in the license renewal database. 

LRA Table 2.5-1, “Electrical and I&C Component Groups Requiring Aging Management 

Review,” lists that the resulting AMR electrical commodity groups of long-lived passive 

components subject to an AMR are as follows: 

 Cable connections (metallic parts) 

 Connector 

 High voltage insulator 

 Insulated cables and connections 

 Metal enclosed bus (bus or connections) 

 Metal enclosed bus (enclosure) 

 Metal enclosed bus (insulation and insulators) 

 Penetrations electrical 

 Switchyard bus and connections 

 Terminal block 

 Transmission conductors and connections 

2.1.5.4.2 Staff Evaluation 

The staff reviewed the applicant’s methodology used for electrical component screening in LRA 

Section 2.1.4.3, “Electrical and I&C System Component Screening Methodology,” and 

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

Systems,” the applicant’s implementing procedures, bases documents, and electrical AMR 

reports. The staff confirmed that the applicant used the screening process described in these 

documents, along with the information contained in NEI 95-10, Appendix B and the SRP-LR, to 

identify the electrical and I&C components subject to an AMR. 

The staff determined that the applicant identified commodity groups found to meet the passive 

criteria described in NEI 95-10. In addition, the staff determined that the applicant evaluated the 

identified passive commodities to identify if they were subject to replacement based on a 

qualified life or specified period (short-lived) or not subject to replacement based on a qualified 

life or specified period (long-lived). The applicant determined that the remaining passive, 

long-lived components were subject to an AMR. 

The staff performed a review to determine if the screening methodology outlined in the LRA and 

implementing procedures were appropriately implemented and if the scoping results are 

consistent with CLB requirements. During the scoping and screening methodology audit, the 

staff reviewed selected screening reports and discussed the reports with the applicant to verify 

proper implementation of the screening process. Based on these onsite review activities, the 

staff did not identify any discrepancies between the methodology documented and the 

implementation results. 

2.1.5.4.3 Conclusion 

On the basis of its review of the LRA, the screening implementation procedures, selected 

portions of the UFSAR, plant equipment database, CLB documentation, procedures, drawings, 

specifications and selected scoping and screening reports, a sample of the results of the 

screening methodology, and discussion with the applicant, the staff concludes that the 

applicant’s methodology for identification of electrical components within the scope of license 
 Scoping and Screening Methodology 

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

and, therefore, is acceptable. 

2.1.5.5 Screening Methodology Conclusion 

On the basis of its review of the LRA, the screening implementing procedures, a sample review 

of screening results, and discussions with the applicant’s staff, the staff concludes that the 

applicant’s screening methodology is consistent with the guidance contained in the SRP-LR and 

identifies those passive, long-lived components within the scope of license renewal that are 

subject to an AMR. The staff concludes that the applicant’s methodology is consistent with the 

requirements of 10 CFR 54.21(a)(1) and, therefore, is acceptable. 

2.1.6 Summary of Evaluation Findings 

On the basis of its review of the information presented in LRA Section 2.1, the supporting 

information in the scoping and screening implementing procedures and reports, the information 

presented during the scoping and screening methodology audit, the applicant’s responses to the 

staff’s RAIs, sample system reviews, and discussions with the applicant, the staff confirms that 

the applicant’s scoping and screening methodology is consistent with the requirements of 

10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff also concludes that the applicant’s description 

and justification of its scoping and screening methodology are adequate to meet the 

requirements of 10 CFR 54.21(a)(1). Based on this review, the staff concludes that the 

applicant’s methodology for identifying systems and structures within the scope of license 

renewal and SCs requiring an AMR, is acceptable. 

2.2 Plant-Level Scoping Results

2.2.1 Introduction 

In LRA Section 2.1, the applicant described the methodology for identifying SSCs within the 

scope of license renewal. In LRA Section 2.2, the applicant describes the results of the 

application of its scoping methodology to determine which SSCs must be included within the 

scope of license renewal. The staff reviewed the plant-level scoping results to determine 

whether the applicant has properly identified all systems and structures relied upon to mitigate 

DBEs, as required by 10 CFR 54.4(a)(1). In addition, the staff ensured that the applicant noted 

all systems and structures that, if they failed, could prevent satisfactory accomplishment of any 

safety-related functions, as required by 10 CFR 54.4(a)(2) and systems and structures relied on 

in safety analyses or plant evaluations to perform functions required by regulations referenced 

in 10 CFR 54.4(a)(3). 

2.2.2 Summary of Technical Information in the Application 

In LRA Table 2.2-1, the applicant listed the plant mechanical systems, structures, and electrical 

and I&C systems within the scope of license renewal. Based on the DBEs considered in the 

plant’s CLB, other CLB information relating to nonsafety-related systems and structures, and 

certain regulated events, the applicant identified plant-level systems and structures 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 systems and 

structures within the scope of license renewal and subject to an AMR. The staff’s evaluation is 

in SER Section 2.1. To verify that the applicant properly implemented its methodology, the 

staff’s review focused on the implementation results shown in LRA Table 2.2-1 to confirm that 

there were no omissions of plant-level systems or structures from the scope of license renewal. 
Scoping and Screening Methodology 

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The staff determined if the applicant properly identified the systems and structures within the 

scope of license renewal in accordance with 10 CFR 54.4. The staff reviewed selected systems 

and structures that the applicant did not identify as within the scope of license renewal to verify 

if the systems and structures have any intended functions requiring their inclusion within the 

scope of license renewal. The staff’s review of the applicant’s implementation was conducted in 

accordance with the guidance in SRP-LR Section 2.2, “Plant-Level Scoping Results.” 

The staff’s review of LRA Section 2.2 identified an area where 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 2.2-1, dated December 3, 2009, the staff noted the following UFSAR systems and 

structures (see Table 2.2-1) could not be located in LRA Table 2.2-1. 

Table 2.2-1 Missing Systems or Structures in Table 2.2-1 of the LRA 

UFSAR Section System or Structures 

Section 12.2, “Radiation Sources,” Table 12.2-11, “Systems Used In 

Post-Accident Shielding Review” 

Post-Accident Sampling System

Section 14.2.12, “Individual Test Descriptions” Post-Accident Monitoring System

Section 7.2.5, “Supplementary Protection System” Supplementary Protection System

Section 3.2, “Classification of Structures, Components, and Systems,”

Table 3.2-1, “Quality Classification of Structures, Systems, and Components”, 

item 25. Structures 

Equipment building 

The staff asked the applicant to provide the reasoning for not including the above systems and 

structures in LRA Table 2.2-1. 

In its response, by letter dated January 18, 2010, the applicant stated the following: 

The Post Accident Sampling System has been removed from the licensing and 

technical basis of the Palo Verde plant. 

The Post Accident Monitoring System refers to the post accident monitoring 

instrumentation. UFSAR Table 1.8-1 identifies Post Accident Monitoring 

instrumentation in 30 plant systems which perform the Post Accident Monitoring 

function. These 30 systems are included in LRA Table 2.2-1, Scoping Results. 

Supplementary Protection System 

UFSAR Section 7.2.5 identifies the Supplementary Protection System as part of 

the Reactor Protection System. The Reactor Protection System is identified in 

LRA Table 2.2-1 as a system within the scope of license renewal. 

Equipment Building 

UFSAR Table 3.2-1, “Quality Classification of Structures, Systems, and 

Components,” identifies the Equipment Building as part of the Containment 

Building. The Containment Building is identified in LRA Table 2.2-1 as a 

structure within the scope of license renewal. 

Based on its review, the staff finds the applicant’s response to RAI 2.2-1 acceptable because 

the applicant clarified why the post-accident sampling system, post-accident monitoring, 

supplementary protection system, and equipment building are not included in Table 2.2-1. 

Therefore, the staff’s concern described in RAI 2.2-1 is resolved. 
 Scoping and Screening Methodology 

 2-35 

2.2.4 Conclusion 

The staff reviewed LRA Section 2.2, the RAI response, and the UFSAR supporting information 

to determine if the applicant failed to identify any systems and structures within the scope of 

license renewal. The staff finds no such omissions. Based on its review, the staff concludes 

that the applicant adequately identified, in accordance with 10 CFR 54.4, the systems and 

structures within the scope of license renewal. 

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: 

 Reactor vessel, internals, and reactor coolant system (RCS) 

 Engineered safety features (ESFs) 

 Auxiliary systems 

 Steam and power conversion systems 

In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive, 

long-lived SCs within the scope of license renewal and subject to an AMR. To verify that the 

applicant properly implemented its methodology, the staff’s review focused on the 

implementation results. This focus allowed the staff to verify that the applicant identified the 

mechanical system SCs that meet the scoping criteria and are subject to an AMR, confirming 

that there were no omissions. 

The staff evaluated mechanical systems using the evaluation methods described here 

(Section 2.3), in the guidance in SRP-LR Section 2.3, and, where applicable, the system 

functions as described in the UFSAR. The objective was to determine if the applicant has 

identified, in accordance with 10 CFR 54.4, components and supporting structures for 

mechanical systems that meet the license renewal scoping criteria. Similarly, the staff 

evaluated the applicant’s screening results to verify that all passive, long-lived components are 

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

In its scoping evaluation, the staff reviewed the LRA, applicable sections of the UFSAR, and 

license renewal boundary drawings, and other licensing basis documents, as appropriate, for 

each mechanical system within the scope of license renewal. The staff reviewed relevant 

licensing basis documents for each mechanical system to confirm that the LRA specified all 

intended functions defined by 10 CFR 54.4(a). The staff’s review then focused on identifying 

any components with intended functions defined by 10 CFR 54.4(a) that the applicant may have 

omitted from the scope of license renewal. 

After reviewing the scoping results, the staff evaluated the applicant’s screening results. 

For those SCs with intended functions delineated under 10 CFR 54.4(a), the staff verified the 

applicant properly screened out only SCs that have functions performed with moving parts or a 

change in configuration or properties or SCs that are subject to replacement after a qualified life 

or specified time period, as described in 10 CFR 54.21(a)(1). The staff confirmed the remaining 

SCs received an AMR, as required by 10 CFR 54.21(a)(1). The staff asked for additional 

information to resolve any omissions or discrepancies noted. 

2.3.1 Reactor Vessel, Internals, and Reactor Coolant System 

LRA Section 2.3.1 identifies the reactor vessel, reactor vessel internals, and RCS SCs subject 

to an AMR for license renewal. The applicant described the supporting SCs of the reactor 

vessel, internals, and RCS in the following LRA sections: 

 2.3.1.1, “Reactor Vessel and Internals” 
Scoping and Screening Methodology 

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 2.3.1.2, “Reactor Coolant System” 

 2.3.1.3, “Pressurizer” 

 2.3.1.4, “Steam Generators” 

 2.3.1.5, “Reactor Core” 

2.3.1.1 Reactor Vessel and Internals 

2.3.1.1.1 Summary of Technical Information in the Application 

LRA Section 2.3.1.1 states that the reactor is a PWR with two reactor coolant loops. It states 

that the reactor vessel is a vertically mounted cylindrical vessel with a hemispherical lower head 

welded to the vessel and a removable hemispherical upper closure head. The applicant 

describes the reactor internals as comprised of the following component groups: core support 

structure (CSS), upper guide structure (UGS), flow skirt, in-core instrumentation support 

structures that support and orient the fuel assemblies, and control element assemblies (CEA) 

and in-core instrumentation that guide the reactor coolant through the vessel. The applicant 

further states that upper flange of the core support barrel, which rests on a ledge in the reactor 

vessel, supports the CSS at its upper end. It states the CSS consists of the core support barrel 

assembly, the lower support structure assembly, and the core shroud assembly. Further, the 

UGS aligns and laterally supports the upper end of the fuel assemblies, maintaining the control 

element spacing, holding down the fuel assemblies during operation, preventing fuel assemblies 

from being lifted out of position during a severe accident condition, and protecting the control 

elements from the effects of coolant cross flow in the upper plenum. The UGS consists of the 

UGS support barrel assembly, the UGS CEA shroud assembly, and the UGS holddown ring. 

The flow skirt is a right circular cylinder, perforated with flow holes and reinforced with two 

stiffening rings. It reduces inequalities in core inlet flow distributions and prevents the formation 

of large vortices in the lower plenum. The in-core support system begins outside the pressure 

vessel, penetrates the bottom of the vessel boundary, and ends in the upper end of the fuel 

assembly. 

The intended function of the reactor vessel is to support the reactor core and control rod drive 

mechanisms and to provide a pressure boundary for reactor coolant. The reactor internals 

support the core, maintain fuel alignment, direct coolant flow, and provide gamma and neutron 

shielding. Portions of the reactor vessel and internals support fire protection, PTS, and SBO 

requirements. 

LRA Table 2.3.1-1 lists the component types that require an AMR as follows. 

The following components are in the reactor vessel: 

 Control element drive mechanism (CEDM) housing (upper and lower) 

 CEDM nozzles 

 Closure bolting 

 Closure head bolts 

 Flange leak monitoring tube 

 Head vent penetration 

 In-core instrument guide tube 

 In-core instrument nozzle 

 Nozzle safe ends and welds 

 Nozzles 

 Shell 

 Shell bottom head 

 Support pads and shear keys 

The following components are in the reactor vessel internals: 
 Scoping and Screening Methodology 

 2-37 

 Core stop lug and surveillance capsule holder 

 CSS 

 Flow skirt 

 In-core instrument support structures 

 UGS 

2.3.1.1.2 Staff Evaluation and Conclusion 

The staff reviewed LRA Section 2.3.1.1 and UFSAR Sections 3.9.5, 4.1, and 5.3 to determine 

whether the applicant failed to identify any components within the scope of license renewal. In 

addition, the staff’s review determined if the applicant failed to identify any components subject 

to an AMR. The staff found no such omissions. On the basis of its review, the staff concludes 

the applicant has appropriately identified the reactor vessel system mechanical components 

within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has 

adequately identified the mechanical components subject to an AMR in accordance with the 

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

2.3.1.2 Reactor Coolant System 

2.3.1.2.1 Summary of Technical Information in the Application 

LRA Section 2.3.1.2 states the following: 

The reactor is a pressurized water reactor with two coolant loops. The reactor 

coolant system circulates water in a closed cycle, removing heat from the reactor 

core and internals and transferring it to a secondary (steam generating) system. 

The steam generators provide the interface between the reactor coolant 

(primary) system and the main steam (secondary) system. Reactor coolant is 

prevented from mixing with the secondary steam by the steam generator tubes 

and the steam generator tube sheet. 

System pressure is controlled by the pressurizer, where steam and water are 

maintained in thermal equilibrium. Steam is formed by energizing immersion 

heaters in the pressurizer, or is condensed by the pressurizer spray to limit 

pressure variations caused by contraction or expansion of the reactor coolant. 

Reactor coolant loop penetrations include a charging and a letdown nozzle; the 

pressurizer surge line in one reactor vessel outlet pipe; the four safety injection 

inlet nozzles, one in each reactor vessel inlet pipe; two outlet nozzles to the 

shutdown cooling system, one in each reactor vessel outlet pipe; pressurizer 

spray nozzle; vent and drain connections; and sample and instrument 

connections. 

LRA Section 2.3.1.2 goes on to state that the major components of the RCS are the reactor 

vessel and internals; two parallel coolant loops; a pressurizer connected to one of the reactor 

vessel outlet pipes; and associated piping, valves, and instrumentation. Each loop contains one 

steam generator (SG) and two reactor coolant pumps (RCPs). All components are located 

inside the containment building. 

The LRA states that the intended functions of the RCS are to maintain RCS pressure during 

normal operation, maintain system integrity, transfer heat from the reactor to other systems 

during certain DBEs, act as a heat sink, allow for reactivity control, allow for removal of 

non-condensable gases, and provide a barrier against release of radioactivity generated within 

the reactor. Portions of the RCS are within the scope of license renewal as nonsafety-related 

affecting safety-related components. Portions of the RCS support fire protection, EQ, ATWS, 

and SBO requirements. 
Scoping and Screening Methodology 

 2-38 

LRA Table 2.3.1-2 lists the component types that require an AMR as follows: 

 Class 1 piping (greater than or equal to 4 inches) 

 Closure bolting 

 Filter 

 Flame arrestor 

 Flexible hoses 

 Heat exchanger (RCP high-pressure cooler) 

 Heat exchanger (RCP seal cooler) 

 Orifice 

 Piping 

 Pump 

 Sight gauge 

 Tank 

 Thermo well 

 Tubing 

 Valve 

2.3.1.2.2 Staff Evaluation and Conclusion 

The staff reviewed LRA Section 2.3.1.2, UFSAR Sections 5.1 and 5.2, and the license renewal 

boundary drawings to determine if the applicant failed to identify any components within the 

scope of license renewal. In addition, the staff’s review determined if the applicant failed to 

identify any components subject to an AMR. The staff found no such omissions. Based on its 

review, the staff concludes the applicant has appropriately identified the RCS mechanical 

components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the 

applicant has adequately identified the mechanical components subject to an AMR in 

accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.1.3 Pressurizer 

2.3.1.3.1 Summary of Technical Information in the Application 

LRA Section 2.3.1.3 states the following: 

The purpose of the pressurizer is to maintain the reactor coolant system 

operating pressure within acceptable limits. The pressurizer includes one 

pressurizer vessel connected to one of the primary coolant loops for each unit, 

and is part of the reactor coolant pressure boundary. The pressurizer contains 

components for maintaining reactor coolant system pressure, which consist of 

electric heaters to increase reactor coolant system pressure and an internal 

spray nozzle to reduce reactor coolant system pressure. 

The reactor coolant system contains the piping system components associated 

with the pressurizer, excluding the pressurizer vessel and its internals. The 

pressurizer is located in the containment building. 

The LRA goes on to state that the intended functions of the pressurizer are to maintain the RCS 

operating pressure within acceptable limits to mitigate the consequences of accidents by 

regulating the temperature and pressure of the coolant. The pressurizer holds steam and water 

in thermal equilibrium. The pressurizer is part of the reactor coolant pressure boundary and 

supports fire protection and SBO requirements. 

LRA Table 2.3.1-3 lists the component types that require an AMR as follows: 

 Closure bolting 
 Scoping and Screening Methodology 

 2-39 

 Pressurizer heater bundle diaphragm plate 

 Pressurizer heater sheaths and sleeves 

 Pressurizer instrument penetrations 

 Pressurizer integral support 

 Pressurizer lower head 

 Pressurizer manways and covers 

 Pressurizer nozzle thermal sleeves 

 Pressurizer nozzles 

 Pressurizer safe ends 

 Pressurizer shell and upper head 

2.3.1.3.2 Staff Evaluation and Conclusion 

The staff reviewed LRA Section 2.3.1.3, UFSAR Section 5.1, and UFSAR Section 5.4.10 to 

determine if the applicant failed to identify any components within the scope of license renewal. 

In addition, the staff’s review determined if the applicant failed to identify any components 

subject to an AMR. The staff found no such omissions. On the basis of its review, the staff 

concludes the applicant has appropriately identified the pressurizer system mechanical 

components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the 

applicant has adequately identified the mechanical components subject to an AMR in 

accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.1.4 Steam Generators 

2.3.1.4.1 Summary of Technical Information in the Application 

LRA Section 2.3.1.4 states the following: 

The purpose of the steam generator system is to provide heat removal from the 

reactor coolant system through the generation of steam and also to act as an 

assured source of steam to the steam driven auxiliary feedwater pump. The 

system consists of the primary and secondary pressure boundaries of the steam 

generators including all pieces and parts within the pressure boundary and all 

penetrations out to the safe ends of the penetration nozzles. 

The LRA goes on to state that the intended function of the SG is to provide heat removal from 

the coolant by the generation of steam for DBE mitigation, SBO, and fire safe shutdown 

requirements. The SG provides a source of steam to the turbine driven auxiliary feedwater 

pump. The SG primary channel head and tubes form part of the reactor coolant pressure 

boundary. The SG outlet nozzles restrict main steam flow in the event of a main steam line 

break. The SG system supports fire protection, ATWS, and SBO requirements. 

LRA Table 2.3.1-4 lists the component types that require an AMR as follows: 

 SG closure bolting 

 SG feedring 

 SG flow distribution baffle 

 SG internal structures 

 SG plugs and stakes 

 SG primary head 

 SG primary head divider plate 

 SG primary manways and flanges 

 SG primary nozzle dam retention ring 

 SG primary nozzles and safe ends 

 SG secondary manways and flanges 
Scoping and Screening Methodology 

 2-40 

 SG secondary nozzles and safe ends 

 SG secondary shell 

 SG tubes 

 SG tubesheet 

 Tubing 

2.3.1.4.2 Staff Evaluation and Conclusion 

The staff reviewed LRA Section 2.3.1.4 and UFSAR Sections 5.4.2, 5.4.4, and 10.3 to 

determine if the applicant failed to identify any SSC within the scope of license renewal. In 

addition, the staff’s review determined if the applicant failed to identify any components subject 

to an AMR. The staff found no such omissions. On the basis of its review, the staff concludes 

the applicant has appropriately identified the SG system mechanical components within the 

scope of license renewal, as required by 10 CFR 54.4(a) and that the applicant has adequately 

identified the mechanical components subject to an AMR in accordance with the requirements 

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

2.3.1.5 Reactor Core 

2.3.1.5.1 Summary of Technical Information in the Application 

LRA Section 2.3.1.5 states the following: 

The reactor core is composed of 241 fuel assemblies and 89 Control Element 

Assemblies (CEAs). The fuel assembly, which provides for 236 fuel rod and 

20 guide tube positions (16 x 16 array), consists of 5 guide tubes welded to 

11 fuel rod spacer grids and is closed at the top and bottom by end fittings. Each 

of the 5 guide tubes displace four fuel rod positions and provides guidance 

channels for the CEAs over their entire length of travel with in-core 

instrumentation inserted in the central guide tube of selected fuel assemblies. 

The in-core instrumentation is routed into the bottom of the fuel assemblies 

through the bottom head of the reactor vessel. 

Each fuel rod consists of slightly enriched uranium in the form of sintered 

uranium dioxide pellets, enclosed in a pressurized zircaloy or ZIRLO tube that 

forms a hermetic enclosure. 

The LRA goes on to state that the intended system function of the reactor core is for each fuel 

rod to transfer heat to the coolant and cladding. The CEAs and guide tubes control short-term 

reactivity changes and are used for reactor shutdown. The initial reactor reactivity control relies 

on the CEAs that are inserted when the reactor trip breaker is de-energized. However, the CEA 

is short-lived, with a lifetime of about five cycles due to accumulative neutron burn-up. The fuel 

assemblies are also short-lived, since they are replaced at regular intervals based on plant fuel 

cycle. Therefore, the applicant stated that it found no components in the reactor core system 

subject to AMR. 

2.3.1.5.2 Staff Evaluation and Conclusion 

The staff reviewed LRA Section 2.3.1.5 and UFSAR Sections 4.1, 4.2, and 4.3 to determine if 

the applicant failed to identify any components within the scope of license renewal. In addition, 

the staff’s review determined if the applicant failed to identify any components subject to an 

AMR. The staff found no such omissions. On the basis of its review, the staff concludes the 

applicant has appropriately identified that no mechanical components in the reactor core system 

are within the scope of license renewal, as required by 10 CFR 54.4(a). In addition, the staff 

finds that the applicant has adequately identified that there are no mechanical components 

subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 
 Scoping and Screening Methodology 

 2-41 

2.3.2 Engineered Safety Features 

LRA Section 2.3.2 identifies the ESF SCs subject to an AMR for license renewal. ESFs in 

nuclear plants mitigate the consequences of design-basis or loss-of-coolant accidents. 

The applicant described the supporting SCs of the ESFs in the following LRA sections: 

 2.3.2.1, “Containment Leak Test System” 

 2.3.2.2, “Containment Purge System” 

 2.3.2.3, “Containment Hydrogen Control System” 

 2.3.2.4, “Safety Injection and Shutdown Cooling System” 

The staff’s findings, based on the review of LRA Sections 2.3.2.1–2.3.2.4, are in 

SER Sections 2.3.2.1–2.3.2.4, respectively. 

2.3.2.1 Containment Leak Test System 

2.3.2.1.1 Summary of Technical Information in the Application 

LRA Section 2.3.2.1.1 describes the containment leak test system, which is comprised of filters, 

dryers, instrumentation, piping, and valves associated with delivering compressed air to the 

containment for conducting the integrated leak rate test. The LRA also states that the purpose 

of the system is to provide a means for periodic testing of containment leakage by pressurizing 

the containment building and monitoring leakage to the atmosphere. During normal plant 

operation, the system is isolated, and containment penetrations are sealed with blank flanges. 

These blank flanges form part of the containment boundary. 

LRA Table 2.3.2-1 identifies the components subject to an AMR for the containment leak test 

system by component type and intended function. Portions of the system contain safety-related 

components relied upon to remain functional during and following DBEs. 

2.3.2.1.2 Staff Evaluation and Conclusion 

The staff reviewed the LRA, UFSAR Sections 6.2.1, 6.2.4, and 6.2.6, and license renewal 

boundary drawings to determine if the applicant failed to identify any components within the 

scope of license renewal. In addition, the staff’s review determined if the applicant failed to 

identify any components subject to an AMR. The staff found no such omissions. On the basis 

of its review, the staff concludes the applicant has appropriately identified the containment leak 

test system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the mechanical components 

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

2.3.2.2 Containment Purge System 

2.3.2.2.1 Summary of Technical Information in the Application 

LRA Section 2.3.2.2.1 describes the containment purge system that consists of a refueling 

purge and a power access purge. The refueling purge train consists of a supply air handling 

unit (AHU) and an exhaust fan. It is used for high flow rate purge during refueling and is closed 

during normal power generation. The power access purge is comprised of a supply AHU and 

charcoal exhaust filtration unit. It is used for low flow rate purge before and during power 

access periods. 

LRA Table 2.3.2-2 identifies the components subject to an AMR for the containment purge 

system by component type and intended function. The containment purge system contains 

safety-related components relied upon to remain functional during and following DBEs. The 

failure of nonsafety-related SSCs in the containment purge system potentially could prevent the 

satisfactory accomplishment of a safety-related function. In addition, the system performs 

functions that support EQ requirements. 
Scoping and Screening Methodology 

 2-42 

2.3.2.2.2 Staff Evaluation and Conclusion 

The staff reviewed the LRA, UFSAR Sections 6.2.4.2.3, 9.4.6.2.2, and 7.3.1.1.10.1, and license 

renewal boundary drawings to determine if the applicant failed to identify any components within 

the scope of license renewal. In addition, the staff’s review determined if the applicant failed to 

identify any components subject to an AMR. The staff found no such omissions. On the basis 

of its review, the staff concludes the applicant has appropriately identified the containment 

purge system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the mechanical components 

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

2.3.2.3 Containment Hydrogen Control System 

2.3.2.3.1 Summary of Technical Information in the Application 

LRA Section 2.3.2.3.1 describes the containment hydrogen control system, which is comprised 

of two hydrogen recombiners and associated control cabinets and one hydrogen purge exhaust 

air filtration unit. The system is staged in Unit 1 and shared by all three units at the site. The 

system has the necessary electrical and mechanical connections to accommodate installation in 

any unit within 72 hours of a loss of coolant accident (LOCA). The containment hydrogen 

control system monitors the hydrogen concentration in the containment building and maintains 

the hydrogen concentration inside the containment below the lower combustible limit of 

4 percent by volume in air following a LOCA. 

LRA Table 2.3.2-3 identifies the components subject to an AMR for the containment hydrogen 

control system by component type and intended function. The containment hydrogen control 

system contains safety-related components relied upon to remain functional during and 

following DBEs. In addition, the system performs functions that support EQ requirements. 

2.3.2.3.2 Staff Evaluation and Conclusion 

The staff reviewed the LRA, UFSAR Sections 1.2.4, 6.2.4, 6.2.5, Table 3.9-25, Table 3.9-27, 

and Table 6.2.4-1, and license renewal boundary drawings to determine if the applicant failed to 

identify any components within the scope of license renewal. In addition, the staff’s review 

determined if the applicant failed to identify any components subject to an AMR. The staff found 

no such omissions. On the basis of its review, the staff concludes the applicant has 

appropriately identified the containment hydrogen control system mechanical components within 

the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has 

adequately identified the mechanical components subject to an AMR in accordance with the 

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

2.3.2.4 Safety Injection and Shutdown Cooling System 

2.3.2.4.1 Summary of Technical Information in the Application 

LRA Section 2.3.2.4.1 describes the safety injection and shutdown cooling system, which 

provides the high-pressure and low-pressure safety injection functions, the shutdown cooling 

function, and the containment spray function. Each unit has two safety injection trains 

comprised of the high-pressure pump, low-pressure pump, containment spray pump, heat 

exchanger, and safety injection tanks. The system also includes the trisodium phosphate 

baskets, which maintain post-LOCA sump fluid pH levels within acceptable limits; containment 

sumps, including screens and liners; piping that penetrates containment, including the 

necessary containment isolation valves; and the refueling water tank (RWT). 

LRA Table 2.3.2-4 identifies the components subject to an AMR for the safety injection and 

shutdown cooling system by component type and intended function. The safety injection and 

shutdown cooling system contains safety-related components relied upon to remain functional 

during and following DBEs. The failure of nonsafety-related SSCs in the safety injection and 
 Scoping and Screening Methodology 

 2-43 

shutdown cooling system potentially could prevent the satisfactory accomplishment of a 

safety-related function. In addition, the system performs functions that support fire protection, 

EQ, and SBO requirements. 

2.3.2.4.2 Staff Evaluation and Conclusion 

The staff reviewed the LRA; UFSAR Sections 5.4.7, 6.2.2, 6.2.4, 6.3, 6.5.2, and 8.3.1.1.10; and 

license renewal boundary drawings to determine if the applicant failed to identify any 

components within the scope of license renewal. In addition, the staff’s review determined if the 

applicant failed to identify any components subject to an AMR. The staff found no such 

omissions. On the basis of its review, the staff concludes the applicant has appropriately 

identified the safety injection and shutdown cooling system mechanical components within the 

scope of license renewal, as required by 10 CFR 54.4(a). In addition, the staff finds that the 

applicant has adequately identified the mechanical components subject to an AMR in 

accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.3 Auxiliary Systems 

LRA Section 2.3.3 identifies the auxiliary systems SCs subject to an AMR for license renewal. 

The applicant described the supporting SCs of the auxiliary systems in the following LRA 

sections: 

 2.3.3.1, “Fuel Handling and Storage System” 

 2.3.3.2, “Spent Fuel Pool Cooling and Cleanup System” 

 2.3.3.3, “Essential Cooling Water System” 

 2.3.3.4, “Essential Chilled Water System” 

 2.3.3.5, “Normal Chilled Water System” 

 2.3.3.6, “Nuclear Cooling Water System” 

 2.3.3.7, “Essential Spray Pond System” 

 2.3.3.8, “Nuclear Sampling System” 

 2.3.3.9, “Compressed Air System” 

 2.3.3.10, “Chemical Volume and Control System” 

 2.3.3.11, “Control Building HVAC [heating, ventilating and air-conditioning] System” 

 2.3.3.12, “Auxiliary Building HVAC System” 

 2.3.3.13, “Fuel Building HVAC System” 

 2.3.3.14, “Containment Building HVAC System” 

 2.3.3.15, “Diesel Generator Building HVAC System” 

 2.3.3.16, “Radwaste Building HVAC System” 

 2.3.3.17, “Turbine Building HVAC System” 

 2.3.3.18, “Miscellaneous Site Structures/Spray Pond Pump House HVAC System” 

 2.3.3.19, “Fire Protection System” 

 2.3.3.20, “Diesel Generator Fuel Oil Storage and Transfer System” 

 2.3.3.21, “Diesel Generator” 
Scoping and Screening Methodology 

 2-44 

 2.3.3.22, “Domestic Water System” 

 2.3.3.23, “Demineralized Water System” 

 2.3.3.24, “WRF [water reclamation facility] Fuel System” 

 2.3.3.25, “Service Gases (N2 and H2 [nitrogen and hydrogen]) System” 

 2.3.3.26, “Gaseous Radwaste System” 

 2.3.3.27, “Radioactive Waste Drains System” 

 2.3.3.28, “Station Blackout Generator System” 

 2.3.3.29, “Cranes, Hoists, and Elevators” 

 2.3.3.30, “Miscellaneous Auxiliary Systems In-Scope ONLY for Criterion 

10 CFR 54.4(a)(2)” 

Auxiliary Systems Generic Requests for Additional Information. In RAI 2.3-1, dated 

December 3, 2009, the staff noted portions of several systems have spatial interaction as 

nonsafety affecting safety-related components in the fuel building and in the auxiliary building 

and are within the scope of license renewal as nonsafety affecting safety-related components 

based on the criterion of 10 CFR 54.4(a)(2). Many spatial interaction terminations are shown on 

license renewal drawings as license renewal boundaries for 10 CFR 54.4(a)(2) piping. 

However, the basis for the spatial interaction termination cannot be determined (e.g., entering a 

building or room with no safety-related components, becoming buried pipe). The staff asked the 

applicant to provide the bases for the spatial interaction terminations. During the scoping and 

screening audit, the staff verified that 19 of the identified spatial interaction terminations 

complied with the criteria for spatial interaction boundaries. 

In its response, dated January 18, 2010, the applicant clarified that spatial interaction 

terminations are associated only with the following two situations: (1) piping exits an area with 

safety-related components to an area with no safety-related components, and (2) piping has an 

open end to atmosphere. The applicant verified that all of the above identified spatial interaction 

terminations met these two criteria or made corrections to the drawings to meet these criteria. 

Based on its review, the staff finds the applicant’s response to RAI 2.3-1 for those spatial 

interaction terminations to be acceptable because the applicant verified or made corrections to 

the drawings to meet the clarified spatial interaction termination criteria. Therefore, the staff’s 

concern described in RAI 2.3-1 is resolved. 

As part of the staff’s review, the following RAI identified instances of boundary drawing errors 

where the continuation notation for piping from one boundary drawing to another boundary 

drawing could not be found or was incorrect. 

In RAI 2.3-2, dated December 3, 2009, the staff noted drawings where the staff was unable to 

identify the license renewal boundary because: (1) continuations were not provided or were 

incorrect, or (2) the continuation drawing was not provided. The staff asked the applicant to 

provide additional information to locate the continuations. 

In its response, dated January 18, 2010, the applicant provided sufficient information, in 

response to RAIs supplied in the individual system sections, to locate the license renewal 

boundaries. Based on its review, the staff finds the applicant’s response to RAI 2.3-2 

acceptable because the applicant provided the continuation locations. Therefore, the staff’s 

concern described in RAI 2.3-2 is resolved. 
 Scoping and Screening Methodology 

 2-45 

2.3.3.1 Fuel Handling and Storage System 

2.3.3.1.1 Summary of Technical Information 

LRA Section 2.3.3.1 describes the fuel handling and storage system, which consists of cranes, 

elevators, fuel storage racks, lift rigs, machines, transfer systems, and trolleys. The purpose of 

the fuel handling and storage system is to provide onsite storage and manipulation capability for 

fuel assemblies and CEAs, to provide for the servicing of the reactor vessel closure head and 

internals and to provide radiation shielding for spent fuel. 

LRA Table 2.3.3-1 identifies the components subject to an AMR for the fuel handling and 

storage system by component type and intended function. The fuel handling and storage 

system contains safety-related components relied upon to remain functional during and 

following DBEs. The failure of nonsafety-related SSCs in the system potentially could prevent 

the satisfactory accomplishment of a safety-related function. 

2.3.3.1.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.1; UFSAR Sections 9.1.1, 9.1.2, and 9.1.4; and the 

license renewal boundary drawings using the evaluation methodology described in 

SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review 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 2.3.3.1-1, dated December 3, 2009, the staff noted in LRA Section 2.3.3.1, “System 

Description,” the CEA change platform was listed as a component that is within the scope of 

license renewal. The CEA change platform was not included as a component subject to AMR in 

Table 2.3.3-1 for the fuel handling and storage system. The staff asked the applicant to provide 

additional information explaining why the CEA change platform is not included as a component 

subject to an AMR in LRA Table 2.3.3-1. 

In its response, dated January 18, 2010, the applicant stated that the CEA change platform 

consists of several major components—some are passive and subject to AMR and some are 

active and not subject to AMR. The applicant then described the major components and listed 

where these components were included in LRA Table 2.3.3-1. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.1-1 acceptable 

because the applicant clarified which CEA change platform components are subject to AMR and 

included in LRA Table 2.3.3-1. Therefore, the staff’s concern described in RAI 2.3.3.1-1 is 

resolved. 

2.3.3.1.3 Conclusion 

The staff reviewed the LRA Section 2.3.3.1; UFSAR Sections 9.1.1, 9.1.2, and 9.1.4; and the 

RAI response to determine if the applicant failed to identify any components within the scope of 

license renewal. In addition, the staff’s review determined if the applicant failed to identify any 

components subject to an AMR. The staff found no such omissions. On the basis of its review, 

the staff concludes the applicant has appropriately identified the fuel handling and storage 

system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a). The staff also finds that the applicant has adequately identified the mechanical 

components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.3.3.2 Spent Fuel Pool Cooling and Cleanup System 

2.3.3.2.1 Summary of Technical Information 

LRA Section 2.3.3.2 describes the spent fuel pool cooling and cleanup system, which consists 

of two sub-systems—one for removal of decay heat from the spent fuel and one for maintaining 
Scoping and Screening Methodology 

 2-46 

pool clarity and reduction of radiation at the pool’s surface. There are two independent trains for 

each cooling and cleanup subsystem. Each cooling subsystem train includes a spent fuel 

cooling pump, a fuel pool heat exchanger and related piping, valves, and instrumentation. The 

spent fuel pool cooling pumps circulate fuel pool water through the two fuel pool heat 

exchangers. Each cleanup subsystem train includes a strainer, pump, filter, ion exchanger, and 

related piping and instrumentation. During normal operation, one or both trains may be lined up 

to continuously clean the water in the spent fuel pool or the RWT. During refueling, the system 

can be aligned to the refueling pool. Additionally, the system provides a backup source of 

borated water to the chemical and volume control system (CVCS) via the spent fuel pool to 

achieve safe shutdown. 

LRA Table 2.3.3-2 identifies the components subject to an AMR for the spent fuel pool cooling 

and cleanup system by component type and intended function. The spent fuel pool cooling and 

cleanup system contains safety-related components relied upon to remain functional during and 

following DBEs. The failure of nonsafety-related SSCs in the spent fuel pool cooling and 

cleanup system potentially could prevent the satisfactory accomplishment of a safety-related 

function. In addition, portions of the system are necessary to support SBO requirements. 

2.3.3.2.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.2, UFSAR Sections 9.1.3 and 9.3.4.5, and the license 

renewal boundary drawings using the evaluation methodology described in SER Section 2.3 

and the guidance in SRP-LR Section 2.3. The staff’s review 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 2.3.3.2-1, dated December 3, 2009, the staff noted that included on LRA drawing 

LR-PVNGS-PC-01-M-PCP-001 (G-2 and C-2) and in LRA Section 2.3.3.2 is a component 

described as being an ion-exchanger. However, it appears in LRA Table 2.3.3-2 that the 

ion-exchanger is a demineralizer since an ion-exchanger is not listed. The staff asked the 

applicant to provide additional information explaining why the component described as an 

ion-exchanger on the LRA drawing and in LRA Section 2.3.3.2 appears to be identified as a 

demineralizer in LRA Table 2.3.3-2. 

In its response, dated January 18, 2010, the applicant stated that individual component names 

and component types in the LRA are consistent with the component names and component 

types as they appear in the plant equipment database. It listed the ion-exchangers depicted on 

drawing LR-PVNGS-PC-01-M-PCP-001 as component type “demineralizer” consistent with the 

component type assigned within the plant equipment database. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.2-1 acceptable 

because the applicant clarified why the component described as an ion-exchanger on the LRA 

drawing and in LRA Section 2.3.3.2 is identified as a demineralizer in LRA Table 2.3.3-2. 

Therefore, the staff’s concern described in RAI 2.3.3.2-1 is resolved. 

2.3.3.2.3 Conclusion 

The staff reviewed the LRA Section 2.3.3.2, UFSAR Sections 9.1.3 and 9.3.4.5, RAI response, 

and boundary drawings to determine if the applicant failed to identify any components within the 

scope of license renewal. In addition, the staff’s review determined if the applicant failed to 

identify any components subject to an AMR. The staff found no such omissions. On the basis 

of its review, the staff concludes the applicant has appropriately identified the spent fuel pool 

cooling and cleanup system mechanical components within the scope of license renewal, as 

required by 10 CFR 54.4(a), and that the applicant has adequately identified the mechanical 

components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 
 Scoping and Screening Methodology 

 2-47 

2.3.3.3 Essential Cooling Water System 

2.3.3.3.1 Summary of Technical Information 

LRA Section 2.3.3.3 describes the essential cooling water system, which is comprised of two 

separate, independent, and redundant trains including a heat exchanger, surge tank, pump, 

chemical addition tank, piping, valves, and associated I&Cs. The purpose of the system is to 

remove heat from all essential components required for normal and emergency shutdown of the 

plant, except the diesel generators, and reject the heat to the essential spray ponds (ESPs) 

through the essential cooling water heat exchanger. The system also provides a back-up 

source of cooling water for the fuel pool cooling heat exchangers, RCPs, CEDM normal air 

cooling units, nuclear sample coolers, and normal chillers. The system also provides an 

intermediate barrier between the RCS and the ESP system to reduce the possibility of 

radioactive leakage to the environment. 

LRA Table 2.3.3-3 notes the components subject to an AMR for the essential cooling water 

system by component type and intended function. The essential cooling water system contains 

safety-related components relied upon to remain functional during and following DBEs. The 

failure of nonsafety-related SSCs in the system potentially could prevent the satisfactory 

accomplishment of a safety-related function. In addition, the system performs functions that 

support fire protection, EQ, and SBO requirements. 

2.3.3.3.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.3, UFSAR Section 9.2.2.1, and the license renewal 

boundary drawings using the evaluation methodology described in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. The staff’s review 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 2.3.3.3-1, dated December 3, 2009, the staff noted an essential cooling water system 

drawing showed certain 1-inch lines within the scope of license renewal as nonsafety affecting 

safety-related components based on the criterion of 10 CFR 54.4(a)(2). However, the applicant 

showed parts of these lines continuing to the drain as not within the scope of license renewal. 

The staff asked the applicant to provide additional information explaining why the lines to the 

drains are not within the scope of license renewal and justify the boundary locations with 

respect to the applicable requirements of 10 CFR 54.4(a). 

In its response, dated January 18, 2010, the applicant stated that the relief valve drain lines 

have been added to the scope of license renewal based on 10 CFR 54.4(a)(2) criterion. The 

applicant provided a revised drawing to show that it added the relief valve drain lines to the 

scope of license renewal. In addition, the applicant provided a revision to LRA Table 3.3.2-3 to 

add the leakage boundary function for these lines. Based on its review, the staff finds the 

applicant’s response to RAI 2.3.3.3-1 acceptable because the applicant has revised the 

drawings to show the relief valve drain lines within scope for license renewal and added the 

leakage boundary function to LRA Table 3.3.2-3. 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 Section 2.3.3.3, UFSAR Section 9.2.2.1, the RAI response, and 

original and revised boundary drawings to determine if the applicant failed to identify any 

components within the scope of license renewal. In addition, the staff’s review determined if the 

applicant failed to identify any components subject to an AMR. On the basis of its review, the 

staff concludes the applicant has appropriately identified the essential cooling water system 

mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), 
Scoping and Screening Methodology 

 2-48 

and that the applicant has adequately identified the mechanical components subject to an AMR 

in accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.3.4 Essential Chilled Water System 

2.3.3.4.1 Summary of Technical Information 

LRA Section 2.3.3.4 describes the essential chilled water system, which is a closed loop system 

with two independent trains. Each train consists of a chilled water refrigeration unit, a chilled 

water circulation pump, an expansion tank, control valves, instrumentation, and insulated piping. 

The purpose of the system is to cool all ESF air handling equipment so that a suitable 

environment can be maintained for personnel and equipment during a transient or DBE. The 

system does not operate under normal operations, but the applicant starts it upon actuation of 

an ESF signal. 

LRA Table 2.3.3-4 identifies the components subject to an AMR for the essential chilled water 

system by component type and intended function. The essential chilled water system contains 

safety-related components relied upon to remain functional during and following DBEs. The 

failure of nonsafety-related SSCs in the system potentially could prevent the satisfactory 

accomplishment of a safety-related function. In addition, the system performs functions that 

support fire protection and SBO requirements. 

2.3.3.4.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.4; UFSAR Sections 6.4, 9.2.9.2 and 9.5.1; and the license 

renewal boundary drawings using the evaluation methodology described in SER Section 2.3 

and the guidance in SRP-LR Section 2.3. The staff’s review 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 2.3.3.4-1, dated December 3, 2009, the staff noted an essential chilled water system 

drawing showed several lines in and out of the air conditioning units (ACUs) within the scope of 

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

18 ACUs as not within the scope of license renewal. The staff asked the applicant to provide 

additional information explaining why the ACUs are not within the scope of license renewal and 

to justify the boundary locations with respect to the applicable requirements of 10 CFR 54.4(a). 

In its response, dated January 18, 2010, the applicant confirmed that the ACUs are within scope 

of license renewal. The applicant showed the ACUs as dashed lines on the drawing, indicating 

that the units are in other plant systems, and it correctly highlighted them in those plant 

systems. Based on its review, the staff finds the applicant’s response to RAI 2.3.3.4-1 

acceptable because the applicant clarified the scoping classification of the ACUs in question, 

and the staff verified that the applicant properly highlighted the ACUs on the essential chilled 

water system boundary drawings. Therefore, the staff’s concern described in RAI 2.3.3.4-1 

is resolved. 

In RAI 2.3.3.4-2, dated December 3, 2009, the staff noted an essential chilled water system 

drawing showed 11⁄2- and 2-inch lines within the scope of license renewal as nonsafety affecting 

safety-related components based on the criteria of 10 CFR 54.4(a)(2). However, the applicant 

showed portions of these lines, downstream of seismic anchors, as not within the scope of 

license renewal for spatial interaction. The staff asked the applicant to give additional 

information explaining why these sections of pipe are not within the scope of license renewal. 

In its response, dated January 18, 2010, the applicant stated that the pipe lines are not in scope 

as they are open-ended gas lines that pose no potential for spatial interaction. Based on its 

review, the staff finds the applicant’s response to RAI 2.3.3.4-2 acceptable because the 

applicant clarified the scoping classification of the pipe lines in question, and the staff agrees 
 Scoping and Screening Methodology 

 2-49 

that there is no potential for spatial interaction. Therefore, the staff’s concern described in 

RAI 2.3.3.4-2 is resolved. 

In RAI 2.3.3.4-3, dated December 3, 2009, the staff noted an essential chilled water system 

drawing showed a valve and the capped end upstream of the valve as within the scope of 

license renewal for 10 CFR 54.4(a)(1) and 10 CFR 54.4(a)(2), respectively. However, the 

applicant showed a small portion of the line, in between the valve and capped end, as out of 

scope for license renewal. The staff asked the applicant to provide additional information 

explaining why this section of pipe is not within the scope of license renewal and to justify the 

boundary locations with respect to the applicable requirements of 10 CFR 54.4(a). 

In its response, dated January 18, 2010, the applicant stated that it inadvertently omitted the 

highlighting of the pipe between the valve and the capped end of the pipe. The applicant 

provided a revised drawing to show the pipe segment as within scope. Based on its review, the 

staff finds the applicant’s response to RAI 2.3.3.4-3 acceptable because the applicant clarified 

the scoping classification for the pipe segment in question and provided a revised drawing. 

Therefore, the staff’s concern described in RAI 2.3.3.4-3 is resolved. 

In RAI 2.3.3.4-4, dated December 3, 2009, the staff noted an essential chilled water system 

drawing shows a 11⁄2-inch line as within the scope of license renewal for 10 CFR 54.4(a)(2). 

The applicant showed the continuation of this line on another license renewal drawing not within 

the scope of license renewal. The staff asked the applicant to provide additional information 

explaining the discrepancy. In its response, dated January 18, 2010, the applicant stated the 

drawing has been revised to include the 11⁄2-inch line as within the scope of license renewal 

based on the criteria of 10 CFR 54.4(a)(2). Based on its review, the staff finds the applicant’s 

response to RAI 2.3.3.4-4 acceptable because the applicant clarified the scoping classification 

for the line in question, and the staff received updated drawings. Therefore, the staff’s concern 

described in RAI 2.3.3.4-4 is resolved. 

2.3.3.4.3 Conclusion 

The staff reviewed the LRA Section 2.3.3.4; UFSAR Sections 6.4, 9.2.9.2, and 9.5.1; RAI 

responses; and original and revised boundary drawings to determine if the applicant failed to 

identify any components within the scope of license renewal. In addition, the staff’s review 

determined if the applicant failed to identify any components subject to an AMR. On the basis 

of its review, the staff concludes the applicant has appropriately identified the essential chilled 

water system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the mechanical components 

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

2.3.3.5 Normal Chilled Water System 

2.3.3.5.1 Summary of Technical Information 

LRA Section 2.3.3.5 describes the normal chilled water system, which is a closed-loop system 

consisting of chilled water refrigeration units, chilled water circulation pumps, an expansion tank, 

control valves, instrumentation, and insulated piping. The applicant states the purpose of the 

system is to supply cooling to air handling equipment so that plant ventilation can maintain a 

suitable environment for personnel and equipment. Further, the system operates during normal 

plant operations, during hot standby, and during scheduled refueling or maintenance shutdown 

periods. 

LRA Table 2.3.3-5 identifies the components subject to an AMR for the normal chilled water 

system by component type and intended function. The LRA states that the normal chilled water 

system contains safety-related components relied upon to remain functional during and 

following DBEs. It further states that the failure of nonsafety-related SSCs in the system 
Scoping and Screening Methodology 

 2-50 

potentially could prevent the satisfactory accomplishment of a safety-related function. 

In addition, portions of the system perform functions that support EQ requirements. 

2.3.3.5.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.5, UFSAR Section 9.2.9.1 and Table 6.2.4-1, and the 

license renewal boundary drawings using the evaluation methodology described in 

SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review 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 2.3.3.5-1, dated December 3, 2009, the staff noted a license renewal normal chilled 

water system drawing showed several lines in and out of ACUs and AHUs within the scope of 

license renewal under 10 CFR 54.4(a)(2). However, the applicant showed 12 ACUs and AHUs 

as not within the scope of license renewal. The staff asked the applicant to give additional 

information explaining why these components are not within the scope of license renewal and to 

justify the boundary locations with respect to the applicable requirements of 10 CFR 54.4(a). 

In its response, dated January 18, 2010, the applicant confirmed that the 12 ACUs and AHUs 

are within the scope of license renewal. The applicant showed the ACUs and AHUs as dashed 

lines on the drawing, indicating that the units are in other plant systems, and it correctly 

highlighted them in those plant systems. Based on its review, the staff finds the applicant’s 

response to RAI 2.3.3.5-1 acceptable because the applicant clarified the scoping classification 

of the ACUs and AHUs in question. The staff verified that the applicant highlighted the ACUs 

and AHUs as in scope for license renewal on the identified drawings and included them in 

Section 2.3.3.5. Therefore, the staff’s concern described in RAI 2.3.3.5-1 is resolved. 

In RAI 2.3.3.5-2, dated December 3, 2009, the staff noted on a license renewal normal chilled 

water system drawing that 11 lines attached to 10 CFR 54.4(a)(2) lines are shown as not within 

scope for license renewal. The staff asked the applicant to provide additional information 

explaining why these pipe sections are not within the scope of license renewal and to justify the 

boundary locations with respect to the applicable requirements of 10 CFR 54.4(a). 

In its response, dated January 18, 2010, the applicant submitted a revised drawing showing the 

11 relief valve drain and AHU pan drain lines within the scope of license renewal under 

10 CFR 54.4 (a)(2). Based on its review, the staff finds the applicant’s response to 

RAI 2.3.3.5-2 acceptable because the staff confirmed that the applicant revised the drawing to 

show the relief valve drain and AHU pan drain lines in question as within scope of license 

renewal and subject to AMR. Therefore, the staff’s concern described in RAI 2.3.3.5-2 is 

resolved. 

2.3.3.5.3 Conclusion 

The staff reviewed the LRA Section 2.3.3.5, UFSAR Section 9.2.9.1 and Table 6.2.4-1, RAI 

responses, and original and revised boundary drawings to determine if the applicant failed to 

identify any components within the scope of license renewal. In addition, the staff’s review 

determined if the applicant failed to identify any components subject to an AMR. On the basis 

of its review, the staff concludes the applicant has appropriately identified the normal chilled 

water system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the mechanical components 

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

2.3.3.6 Nuclear Cooling Water System 

2.3.3.6.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.6 describes the nuclear cooling water system, which consists of 

one closed-loop train including two, full-capacity pumps, redundant heat exchangers, an 
 Scoping and Screening Methodology 

 2-51 

expansion tank, heat exchangers associated with nonsafety-related plant auxiliary systems and 

components, instrumentation, and piping. The purpose of the system is to provide cooling to 

auxiliary systems and components such as the RCPs, the boric acid concentrator, the waste 

gas compressor, the radwaste evaporator, the normal chilled water chillers, the letdown heat 

exchanger, the fuel pool heat exchangers, the CEDMs, the auxiliary steam vent condenser, and 

various sample coolers. 

LRA Table 2.3.3-6 identifies the components subject to an AMR for the nuclear cooling water 

system by component type and intended function. The applicant states that the nuclear cooling 

water system contains safety-related components relied upon to remain functional during and 

following DBEs. The applicant also identifies that the failure of nonsafety-related SSCs in the 

system potentially could prevent the satisfactory accomplishment of a safety-related function. In 

addition, the system performs functions that support fire protection and EQ requirements. 

2.3.3.6.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.6; UFSAR Sections 6.2.4, 8.3.1.1.3, 9.2.2.2, 9.5.1, and 

15.6.5; and the license renewal boundary drawings using the evaluation methodology described 

in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review 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 2.3.3.6-1, dated December 3, 2009, the staff noted several portions of the nuclear 

cooling water system are within the scope of license renewal as nonsafety affecting 

safety-related components based on the criterion of 10 CFR 54.4(a)(2). However, the applicant 

showed 26 lines attached to 10 CFR 54.4(a)(2) lines as not within the scope of license renewal. 

The staff asked the applicant to provide additional information explaining why these sections of 

pipe are not within the scope of license renewal and to justify the boundary locations with 

respect to the applicable requirements of 10 CFR 54.4(a). 

In its response, dated January 18, 2010, the applicant provided revised license renewal 

boundary drawings showing the relief valve drain lines and drain lines within the scope of 

license renewal under 10 CFR 54.4(a)(2). The applicant also provided a revised Table 3.3.2-6 

to include a leakage boundary spatial function for the relief valve drain lines and to include drain 

lines in a wetted gas environment. Based on its review, the staff finds the applicant’s response 

to RAI 2.3.3.6-1 acceptable because the applicant clarified the scoping classification of the relief 

valve drain lines in question and included appropriate components as subject to AMR. 

Therefore, the staff’s concern described in RAI 2.3.3.6-1 is resolved. 

In RAI 2.3.3.6-2, dated December 3, 2009, the staff noted a license renewal nuclear cooling 

water system drawing showed several lines in and out of the ACUs within the scope of license 

renewal for 10 CFR 54.4(a)(2). However, the applicant showed two ACUs as not within the 

scope of license renewal. The staff asked the applicant to provide additional information 

explaining why the units are not within the scope of license renewal and to justify the boundary 

locations with respect to the applicable requirements of 10 CFR 54.4(a). 

In its response, dated January 18, 2010, the applicant confirmed that the ACUs are in scope for 

license renewal. The applicant showed the ACUs as dashed lines on the drawing, indicating 

that the units are in other plant systems. The applicant correctly highlighted the ACUs as in 

scope of license renewal on the corresponding system drawing. Based on its review, the staff 

finds the applicant’s response to RAI 2.3.3.6-2 acceptable because the applicant clarified the 

scoping classification of the ACUs in question, and the staff verified that the applicant properly 

highlighted the ACUs on the corresponding system drawing. Further, the staff verified that 

these components have been included in Section 2.3.3.6 as subject to AMR. Therefore, the 

staff’s concern described in RAI 2.3.3.6-2 is resolved. 
Scoping and Screening Methodology 

 2-52 

In RAI 2.3.3.6-3, dated December 3, 2009, the staff noted a license renewal nuclear cooling 

water system drawing showed an 8-inch line as within the scope of license renewal for 

10 CFR 54.4(a)(3) whereas a small portion of the same line is shown as not within the scope of 

license renewal for 10 CFR 54.4(a)(2). The staff asked the applicant to provide additional 

information to clarify the scoping classification for this pipe section. In its response, dated 

January 18, 2010, the applicant stated the drawing has been revised to indicate the line is within 

scope of license renewal based on 10 CFR 54.4(a)(3). The applicant provided the revised 

drawing. Based on its review, the staff finds the applicant’s response to RAI 2.3.3.6-3 

acceptable because the applicant clarified the scoping classification of the pipe line in question, 

and the staff verified the change on the revised drawing. Therefore, the staff’s concern 

described in RAI 2.3.3.6-3 is resolved. 

2.3.3.6.3 Conclusion 

The staff reviewed the LRA Section 2.3.3.6; UFSAR Sections 6.2.4, 8.3.1.1.3, 9.2.2.2, 9.5.1, 

and 15.6.5; RAI responses; and original and revised boundary drawings to determine if the 

applicant failed to identify any components within the scope of license renewal. In addition, the 

staff’s review determined if the applicant failed to identify any components subject to an AMR. 

On the basis of its review, the staff concludes the applicant has appropriately identified the 

nuclear cooling water system mechanical components within the scope of license renewal, as 

required by 10 CFR 54.4(a), and that the applicant has adequately identified the mechanical 

components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.3.3.7 Essential Spray Pond System 

2.3.3.7.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.7 describes the ESP system, which is comprised of two separate, redundant 

trains including a pump, ESP, piping, valves, and I&Cs. The applicant states that the purpose of 

the system is to provide cooling water to nuclear safety-related components and dissipate heat 

to the atmosphere by the ESPs (ultimate heat sink) under normal and accident conditions. Also, 

the LRA states that each train alone has a 100-percent heat dissipation capacity for safe 

shutdown during a loss of offsite power. 

LRA Table 2.3.3-7 lists the components subject to an AMR for the ESP system by component 

type and intended function. The applicant describes the ESP pond system as containing 

safety-related components relied upon to remain functional during and following DBEs. The 

failure of nonsafety-related SSCs in the system potentially could prevent the satisfactory 

accomplishment of a safety-related function. In addition, the system performs functions that 

support fire protection and SBO requirements. 

2.3.3.7.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.7, UFSAR Sections 9.2.1 and 9.2.5, and the license 

renewal boundary drawings using the evaluation methodology described in SER Section 2.3 

and the guidance in SRP-LR Section 2.3. The staff’s review 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 2.3.3.7-1, dated December 3, 2009, the staff noted a license renewal ESP system 

drawing showed two 1-inch lines as within the scope of license renewal for 10 CFR 54.4(a)(2). 

However, the applicant showed the continuation of these lines, after the seismic anchor to the 

drains, as not within the scope of license renewal. The staff asked the applicant to provide 

additional information explaining why portions of these lines are not within the scope of license 

renewal and to justify the boundary locations with respect to the applicable requirements of 

10 CFR 54.4(a). 
 Scoping and Screening Methodology 

 2-53 

In its response, dated January 18, 2010, the applicant stated the relief valve drain lines have 

been added to the scope of license renewal based on the criteria of 10 CFR 54.4(a)(2). The 

applicant revised the drawing to reflect the drain lines as within the scope of license renewal. 

The applicant also revised LRA Table 3.3.2-7 to include drain lines in a wetted gas environment. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.7-1 acceptable 

because the applicant clarified that the drain lines are in scope of license renewal, and the staff 

verified the revised drawings show the relief drain valve lines within scope for license renewal. 

Further, the staff confirmed that these components were included in the LRA as subject to AMR. 

Therefore, the staff’s concern described in RAI 2.3.3.7-1 is resolved. 

2.3.3.7.3 Conclusion 

The staff reviewed the LRA Section 2.3.3.7, UFSAR Sections 9.2.1, and 9.2.5, RAI response, 

and original and revised boundary drawings to determine if the applicant failed to identify any 

components within the scope of license renewal. In addition, the staff’s review determined if the 

applicant failed to identify any components subject to an AMR. On the basis of its review, the 

staff concludes the applicant has appropriately identified the ESP system mechanical 

components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the 

applicant has adequately identified the mechanical components subject to an AMR in 

accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.3.8 Nuclear Sampling System 

2.3.3.8.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.8 describes the nuclear sampling system, which allows collection of samples 

from the RCS and auxiliary systems for analysis during normal and post-accident conditions 

without requiring access to containment. Sample points include the RCS hot leg, pressurizer 

surge line, pressurizer steam space, safety injection and shutdown cooling system, and CVCSs. 

The LRA states that the nuclear sampling system consists of sampling lines, heat exchangers, 

sample vessels, sample sinks or racks, analysis equipment, and instrumentation. 

LRA Table 2.3.3-8 lists the components subject to an AMR for the nuclear sampling system by 

component type and intended function. Portions of the nuclear sampling system contain 

safety-related components relied upon to remain functional during and following DBEs. The 

failure of portions of the nonsafety-related SSCs in the system potentially could prevent the 

satisfactory accomplishment of a safety-related function. In addition, the system performs 

functions that support fire protection and EQ requirements. 

2.3.3.8.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.8; UFSAR Sections 3.11, 6.2.4, 8.3.2.1, 9.3.2, 9.5.1, and 

15.6.5; and the license renewal boundary drawings using the evaluation methodology described 

in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review 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 2.3.3.8-1, dated December 3, 2009, the staff noted that a license renewal drawing for the 

nuclear sampling system showed the continuation of a 1-inch pipe section, in scope for criteria 

10 CFR 54.4(a)(2), to another drawing where the continuation was not within the scope of 

license renewal. The staff asked the applicant to provide additional information to justify the 

discrepancy. 

In its response, dated January 18, 2010, the applicant stated that the 1-inch line is not within the 

scope of license renewal because it is not safety-related and neither connects to safety-related 

equipment nor passes through areas occupied by safety-related equipment for spatial 

interaction. The applicant also stated that it inadvertently colored the origin of 1-inch line as 
Scoping and Screening Methodology 

 2-54 

within the scope of license renewal. The applicant revised this drawing and submitted it to the 

staff. Based on its review, the staff finds the applicant’s response to RAI 2.3.3.8-1 acceptable 

because the applicant clarified why the 1-inch pipe was not within the scope of license renewal. 

The staff verified the corrected highlighting on revised drawing. Therefore, the staff’s concern 

described in RAI 2.3.3.8-1 is resolved. 

In RAI 2.3.3.8-2, dated December 3, 2009, the staff noted a license renewal drawing for the 

nuclear sampling system showed a continuation of a 2-inch pipe section in scope for license 

renewal, to a “hot lab sink drain” on an associated drawing; however, the continuation was not 

shown as within the scope of license renewal. The staff asked the applicant to provide 

additional information to justify the discrepancy. 

In its response, dated January 18, 2010, the applicant stated that the 2-inch line is within the 

scope of license renewal in the nuclear sampling system but not within the scope in the 

chemical waste system. The applicant also stated that the drawing has been revised to add a 

spatial interaction termination flag on the 2-inch line and the highlighting downstream of the 

spatial interaction termination flag before the continuation to the license renewal boundary 

drawing was removed. The applicant submitted the revised drawing to the staff. Based on its 

review, the staff finds the applicant’s response to RAI 2.3.3.8-2 acceptable because the 

applicant justified the reason for not including the continuation on the drawing within scope. 

The staff confirmed changes to the license renewal boundary drawing. Therefore, the staff’s 

concern described in RAI 2.3.3.8-2 is resolved. 

In RAI 2.3.3.8-3, dated December 3, 2009, the staff noted a license renewal drawing for the 

nuclear sampling system showed a continuation of a 1⁄2-inch pipe section to “equipment drain 

tank” on an associated license renewal drawing. The associated license renewal drawing 

referred to a third drawing, but this drawing was not consistent with the other two. The staff 

asked the applicant to provide additional information to locate the continuation of the 1⁄2-inch 

pipe section. 

 In its response, dated January 18, 2010, the applicant stated that the 1⁄2-inch pipe section 

continues from both drawings and is shown on both drawings. The inconsistency was noted in 

the continuation grid coordinates, which was caused by using a Unit 3 P&ID with a continuation 

to a Unit 1 drawing. Based on its review, the staff finds the applicant’s response to 

RAI 2.3.3.8-3 acceptable because the applicant clarified the inconsistency in grid locations. 

Therefore, the staff’s concern described in RAI 2.3.3.8-3 is resolved. 

2.3.3.8.3 Conclusion 

The staff reviewed the LRA Section 2.3.3.8; UFSAR Sections 3.11, 6.2.4, 8.3.2.1, 9.3.2, 9.5.1 

and 15.6.5; RAI responses; and original and revised boundary drawings to determine if the 

applicant failed to identify any components within the scope of license renewal. In addition, the 

staff’s review determined if the applicant failed to identify any components subject to an AMR. 

On the basis of its review, the staff concludes the applicant has appropriately identified the 

nuclear sampling system mechanical components within the scope of license renewal, as 

required by 10 CFR 54.4(a), and that the applicant has adequately identified the mechanical 

components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.3.3.9 Compressed Air System 

2.3.3.9.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.9 describes the compressed air system as comprised of two subsystems: 

the instrument air system and the service and breathing air system. The applicant stated that 

the instrument air subsystem provides filtered, dry, oil-free air for pneumatic instrument 

operation and the control of pneumatic actuators using three air compressors, three air 
 Scoping and Screening Methodology 

 2-55 

receivers, and six air dryer units. The applicant also stated the instrument air system also has 

nitrogen back-up capability. The service and breathing air subsystem supplies oil-free 

breathable air using one air compressor, two air receivers, and one refrigerated air dryer to 

service air stations and breathing air stations throughout the plant. The instrument air 

subsystem is required for normal plant operation but is not required for safe shutdown of the 

plant. 

LRA Table 2.3.3-9 identifies the components subject to an AMR for the compressed air system 

by component type and intended function. This section states that the compressed air system 

contains safety-related components relied upon to remain functional during and following DBEs. 

The applicant stated the failure of nonsafety-related SSCs in the system potentially could 

prevent the satisfactory accomplishment of a safety-related function. In addition, portions of the 

system perform functions that support fire protection, EQ, and SBO requirements. 

2.3.3.9.2 Staff Evaluation and Conclusion 

The staff reviewed the LRA Section 2.3.3.9, UFSAR Section 9.3.1, and license renewal 

boundary drawings to determine if the applicant failed to identify any components within the 

scope of license renewal. In addition, the staff’s review determined if the applicant failed to 

identify any components subject to an AMR. The staff found no such omissions. On the basis 

of its review, the staff concludes the applicant has appropriately identified the compressed air 

system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the mechanical components 

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

2.3.3.10 Chemical Volume and Control System 

2.3.3.10.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.10 describes the chemical volume and control system, which adjusts the 

purity, volume, and boric acid concentration of the reactor coolant. The system’s major 

components are the RWT, the reactor drain tank, the equipment drain tank, the gas stripper, the 

boric acid concentrator, heat exchangers, filters, ion exchangers, piping, valves, and various 

pumps, including the charging pumps. The LRA states that the system has many functions 

including those listed below: 

 Maintain the chemistry and purity of the reactor coolant 

 Maintain volume in the RCS 

 Receive, store, separate, and process reactor grade, borated waste 

 Provide borated water to the emergency core cooling system for injection to the RCS 

 Control the boron concentration in the RCS 

 Provide auxiliary pressurizer spray for control of pressure and cooling 

 Provide and receive injection water to and from the RCP seals 

 Supply demineralized reactor makeup water to various auxiliary equipment 

 Provide a means for continuous removal of noble gases from the reactor coolant 

 Provide makeup to the spent fuel pool 

 Provide purification of shutdown cooling flow 

 Provide makeup to the reactor coolant system for losses from small leaks 

 Provide water to the auxiliary feedwater system as makeup for reactor heat removal 

LRA Table 2.3.3-10 identifies the components subject to an AMR for the chemical volume and 

control system by component type and intended function. The chemical volume and control 

system contains safety-related components relied upon to remain functional during and 

following DBEs. The failure of nonsafety-related SSCs in the system potentially could prevent 
Scoping and Screening Methodology 

 2-56 

the satisfactory accomplishment of a safety-related function. In addition, the system performs 

functions that support fire protection, EQ, and SBO requirements. 

2.3.3.10.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.10; UFSAR Sections 1.2.10.2, 3.11, 6.2.4, 8.3.1.1.10, and 

9.3.4; and the license renewal boundary drawings using the evaluation methodology described 

in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review 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 2.3.3.10-1, dated December 3, 2009, the staff noted portions of the CVCS are within the 

scope of license renewal as nonsafety affecting safety-related components based on the 

criterion of 10 CFR 54.4(a)(2). However, the applicant showed 22 lines attached to 

10 CFR 54.4(a)(2) lines as not within the scope of license renewal. The staff asked the 

applicant to provide additional information explaining why these sections of pipe are not within 

the scope of license renewal and to justify the boundary locations with respect to the applicable 

requirements of 10 CFR 54.4(a). 

In its response, dated January 18, 2010, the applicant provided additional information for each 

of the 22 locations on their scoping status and, in all cases, submitted revised license renewal 

boundary drawings to clarify the boundary locations. The applicant also revised Table 3.3.2-10 

to include components in a wetted gas environment. Based on its review, the staff finds the 

applicant’s response to RAI 2.3.3.10-1 acceptable because the applicant clarified boundary 

locations, and the staff verified the revised drawings. Therefore, the staff’s concern described in 

RAI 2.3.3.10-1 is resolved. 

In RAI 2.3.3.10-2, dated December 3, 2009, the staff noted that the applicant did not provide a 

continuation drawing in the license renewal package for certain license renewal boundary 

drawings. The staff asked the applicant to provide additional information to locate the license 

renewal boundaries. 

In its response, dated January 18, 2010, the applicant provided additional information to clarify 

the boundary locations. Based on its review, the staff finds the applicant’s response to 

RAI 2.3.3.10-2 acceptable because the boundary locations were provided. Therefore, the staff’s 

concern described in RAI 2.3.3.10-2 is resolved. 

In RAI 2.3.3.10-3, dated December 3, 2009, the staff noted that license renewal drawings 

showed 16 lines as not within the scope of license renewal, but the lines are connected to piping 

and tanks, which are shown as within the scope of license renewal. The staff asked the 

applicant to provide additional information to justify why these lines are not within the scope of 

license renewal. 

In its response, dated January 18, 2010, the applicant provided additional information for each 

of the 16 locations on their scoping status and, in many cases, submitted revised license 

renewal boundary drawings to clarify the boundary locations. The applicant also revised 

Table 3.3.2-10 to include components in a wetted gas environment. Based on its review, the 

staff finds the applicant’s response to RAI 2.3.3.10-3 acceptable because the boundary 

locations were provided. The staff reviewed and verified the revised boundary drawings. 

Therefore, the staff’s concern described in RAI 2.3.3.10-3 is resolved. 

2.3.3.10.3 Conclusion 

The staff reviewed the LRA Section 2.3.3.10; UFSAR Sections 1.2.10.2, 3.11, 6.2.4, 8.3.1.1.10, 

and 9.3.4; RAI responses; and original and revised boundary drawings to determine if the 

applicant failed to identify any components within the scope of license renewal. In addition, the 

staff’s review determined if the applicant failed to identify any components subject to an AMR. 
 Scoping and Screening Methodology 

 2-57 

On the basis of its review, the staff concludes the applicant has appropriately identified the 

chemical volume and control system mechanical components within the scope of license 

renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the 

mechanical components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.3.3.11 Control Building Heating, Ventilation, and Air Conditioning System 

2.3.3.11.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.11 describes the control building HVAC system, which is comprised of 

four subsections: (1) control room normal HVAC, (2) control building normal HVAC, (3) control 

room essential HVAC, and (4) control building essential HVAC. The LRA states that the 

functions of the control building HVAC system are to maintain an environment in the control 

room complex, suitable for prolonged occupancy throughout the duration of postulated 

accidents; to provide control room isolation to prevent intrusion of poisonous gases, smoke, or 

airborne radioactivity; to maintain a suitable environment for the ESF switchgear, ESF 

equipment rooms, and battery rooms during postulated accidents; and to ventilate and exhaust 

battery rooms to maintain hydrogen below flammable concentrations. 

LRA Table 2.3.3-11 identifies the components subject to an AMR for the control building HVAC 

system by component type and intended function. The applicant further stated that the control 

building HVAC system contains safety-related components relied upon to remain functional 

during and following DBEs. The failure of portions of the nonsafety-related SSCs in the system 

potentially could prevent the satisfactory accomplishment of a safety-related function. In 

addition, portions of the system perform functions that support fire protection and SBO 

requirements. 

2.3.3.11.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.11, UFSAR Sections 6.4 and 9.4.1, and the license 

renewal boundary drawings using the evaluation methodology described in SER Section 2.3 

and the guidance in SRP-LR Section 2.3. The staff’s review of LRA Section 2.3.3.11 identified 

an area in which additional information was necessary to complete the review of the applicant’s 

scoping and screening results. The applicant responded to the staff’s RAI as discussed below. 

In RAI 2.3.3.11-1, dated November 13, 2009, the staff requested that the applicant explain the 

scoping status of the fixed louvers in the air inlet and outlet. The applicant did not highlight the 

louvers as being in scope on the license renewal boundary drawings. 

In its response, dated December 11, 2009, the applicant stated that the fixed louvers installed in 

an exterior wall of the control building are structural components within scope of license 

renewal. The applicant stated that these louvers were included in the component types of 

“barrier” and “structural steel” in LRA Section 2.4.2. The applicant explained that the license 

renewal drawings did not have the louvers highlighted because those drawings are mechanical 

boundary drawings, and only mechanical components within the license renewal scope are 

highlighted on those drawings. The single license renewal drawing for structures was based on 

the site plan. Based on its review, the staff finds the applicant’s response to RAI 2.3.3.11-1 

acceptable because the applicant clarified that the items (louvers) identified in the RAI are within 

scope and are addressed in LRA Section 2.4.2. Therefore, the staff’s concern described in 

RAI 2.3.3.11-1 is resolved. 

2.3.3.11.3 Conclusion 

The staff reviewed the LRA Section 2.3.3.11, UFSAR Sections 6.4 and 9.4.1, RAI response, 

and license renewal boundary drawings to determine if the applicant failed to identify any 

components within the scope of license renewal. In addition, the staff’s review determined if the 
Scoping and Screening Methodology 

 2-58 

applicant failed to identify any components subject to an AMR. On the basis of its review, the 

staff concludes the applicant has appropriately identified the control building HVAC system 

mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), 

and that the applicant has adequately identified the mechanical components subject to an AMR 

in accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.3.12 Auxiliary Building Heating, Ventilation, and Air Conditioning System 

2.3.3.12.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.12 describes the auxiliary building HVAC system, which consists of two 

subsystems: (1) the auxiliary building normal HVAC and (2) the auxiliary building essential 

HVAC. The auxiliary building normal HVAC subsystem maintains environmental conditions 

suitable for personnel comfort and safe operation of equipment during normal plant operation. 

The auxiliary building essential HVAC subsystem maintains the required thermal environment 

for the ESF equipment rooms and auxiliary feedwater pump rooms during accident conditions. 

LRA Table 2.3.3-12 identifies the components subject to an AMR for the auxiliary building 

HVAC system by component type and intended function. The auxiliary building HVAC system 

contains safety-related components relied upon to remain functional during and following DBEs. 

The failure of portions of the nonsafety-related SSCs in the system potentially could prevent the 

satisfactory accomplishment of a safety-related function. In addition, portions of the system 

perform functions that support fire protection, EQ, and SBO requirements. 

2.3.3.12.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.12, UFSAR Section 9.4.2, and the license renewal 

boundary drawings using the evaluation methodology described in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. The staff’s review of LRA Section 2.3.3.12 identified an area 

in which additional information was necessary to complete the review of the applicant’s scoping 

and screening results. The applicant responded to the staff’s RAI as discussed below. 

In RAI 2.3.3.12-1, dated November 13, 2009, the staff requested that the applicant explain the 

scoping status of two fire dampers on a license renewal drawing for auxiliary building HVAC 

system. The applicant did not highlight these fire dampers as being in scope on the drawing. 

In its response, dated December 11, 2009, the applicant stated that it should have highlighted 

one fire damper as being in scope as it has fire barrier and non-safety-related structural support 

functions. The applicant described this as an apparent drawing preparation oversight and 

corrected it. The applicant stated that the other fire damper was not in scope; thus, was 

correctly not highlighted on the drawing. This damper is not mounted in a fire barrier wall. 

Although not depicted on the drawing, the air that passes through the damper comes from the 

open areas of the elevations above via stairwells. Based on its review, the staff finds the 

applicant’s response to RAI 2.3.3.12-1 acceptable because the applicant clarified that one fire 

damper was in scope and that the other fire damper was not in scope, as the wall in which it 

was mounted was not a fire barrier. Therefore, the staff’s concern described in RAI 2.3.3.12-1 

is resolved. 

2.3.3.12.3 Conclusion 

The staff reviewed LRA Section 2.3.3.12, UFSAR Section 9.4.2, license renewal boundary 

drawings, and RAI response to determine if the applicant failed to properly identify any 

components within the scope of license renewal. In addition, the staff’s review determined 

whether the applicant failed to identify any components subject to an AMR. On the basis of its 

review, the staff concludes the applicant has appropriately identified the auxiliary building HVAC 

system mechanical components within the scope of license renewal, as required by 
 Scoping and Screening Methodology 

 2-59 

10 CFR 54.4(a), and that the applicant has adequately identified the mechanical components 

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

2.3.3.13 Fuel Building Heating, Ventilation, and Air Conditioning System 

2.3.3.13.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.13 describes the fuel building HVAC system, which consists of the fuel 

building normal and essential HVAC subsystems. The LRA states that the fuel building normal 

HVAC subsystem operates during normal modes of operation and distributes tempered outside 

air throughout the building. The subsystem maintains environmental conditions suitable for 

personnel comfort and safe operation of equipment during normal operation. The fuel building 

essential HVAC subsystem operates only in the event of a fuel handling accident or LOCA and 

directs filtered exhaust to the fuel building vents to minimize airborne radiation releases. If 

radiation monitors detect high radiation levels, the fuel building is isolated, the essential air 

filtration units start, the normal AHUs are secured, and negative pressure is established in 

the building. 

LRA Table 2.3.3-13 identifies the components subject to an AMR for the fuel building HVAC 

system by component type and intended function. The fuel building HVAC system contains 

safety-related components relied upon to remain functional during and following DBEs. The 

failure of portions of nonsafety-related SSCs in the system potentially could prevent the 

satisfactory accomplishment of a safety-related function. In addition, portions of the system 

perform functions that support fire protection and EQ requirements. 

2.3.3.13.2 Staff Evaluation and Conclusion 

The staff reviewed LRA Section 2.3.3.13, UFSAR Sections 6.5.1 and 9.4.5, and the license 

renewal boundary drawings using the evaluation methodology described in SER Section 2.3 

and the guidance in SRP-LR Section 2.3 to determine if the applicant failed to identify any 

components within the scope of license renewal. In addition, the staff’s review determined if the 

applicant failed to identify any components subject to an AMR. The staff found no such 

omissions. On the basis of its review, the staff concludes the applicant has appropriately 

identified the fuel building HVAC system mechanical components within the scope of license 

renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the 

mechanical components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.3.3.14 Containment Building Heating, Ventilation, and Air Conditioning System 

2.3.3.14.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.14 describes the containment building HVAC system, which controls air 

temperature to ensure operability of containment building equipment, provide filtration to 

maintain airborne radioactivity levels below permissible limits, and provide an environment 

suitable for maintenance and refueling activities. 

The LRA also states that containment building HVAC system functions during normal plant 

operations, containment pre-access periods, or during extended shutdowns. It is comprised of 

the following subsystems: 

 Containment building normal cooling subsystem 

 Containment building normal cleanup subsystem 

 CEDM cooling subsystem 

 Reactor cavity cooling subsystem 

 Pressurizer cooling subsystem 

 Tendon gallery ventilation subsystem 
Scoping and Screening Methodology 

 2-60 

 Main steam support structure ventilation subsystem 

LRA Table 2.3.3-14 identifies the components subject to an AMR for the containment building 

HVAC system by component type and intended function. The containment building HVAC 

system contains safety-related components relied upon to remain functional during and 

following DBEs. The failure of portions of the nonsafety-related SSCs in the system potentially 

could prevent the satisfactory accomplishment of a safety-related function. In addition, portions 

of the system perform functions that support fire protection and EQ requirements. 

2.3.3.14.2 Staff Evaluation and Conclusion 

The staff reviewed LRA Section 2.3.3.14, UFSAR Sections 6.2.4 and 9.4.6, and the license 

renewal boundary drawings using the evaluation methodology described in SER Section 2.3 

and the guidance in SRP-LR Section 2.3 to determine if the applicant failed to identify any 

components within the scope of license renewal. In addition, the staff’s review determined if the 

applicant failed to identify any components subject to an AMR. The staff found no such 

omissions. On the basis of its review, the staff concludes the applicant has appropriately 

identified the containment building HVAC system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 

the mechanical components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.3.3.15 Diesel Generator Building Heating, Ventilation, and Air Conditioning System 

2.3.3.15.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.15 describes the diesel generator building HVAC system, which is comprised 

of two separate and independent HVAC trains, one for each of the diesel generator 

compartments in each diesel generator building. Each train consists of the diesel generator 

building normal and essential HVAC subsystems. The normal subsystem maintains 

environmental conditions during normal operation suitable for personnel comfort and safe 

operation of equipment when the diesel generator is not running. The essential HVAC 

subsystem maintains the appropriate environment for the diesel generator and its auxiliaries 

during emergency conditions when the diesel generator is required to operate. 

LRA Table 2.3.3-15 identifies the components subject to an AMR for the diesel generator 

building HVAC system by component type and intended function. The diesel generator building 

HVAC system contains safety-related components relied upon to remain functional during and 

following DBEs. The failure of portions of the nonsafety-related SSCs in the system potentially 

could prevent the satisfactory accomplishment of a safety-related function. In addition, portions 

of the system perform functions that support fire protection and SBO requirements. 

2.3.3.15.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.15, UFSAR Section 9.4.7, and the license renewal 

boundary drawings using the evaluation methodology described in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. The staff’s review of LRA Section 2.3.3.15 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 2.3.3.15-1, dated November 13, 2009, the staff asked that the applicant explain the 

scoping status of the fixed ventilation louvers shown on the license renewal drawing for the 

diesel generator building HVAC system. The staff noted that the applicant did not highlight 

these louvers as being in scope on the drawing. 

In its response, dated December 11, 2009, the applicant stated that these fixed louvers are 

installed in an external wall and interior wall of the building and are included in scope as 

described in LRA Section 2.4.3 as part of the structural steel component type providing 
 Scoping and Screening Methodology 

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structural support and shelter and protection functions. The drawing did not have the louvers 

highlighted because that drawing is a mechanical boundary drawing and only mechanical 

components within the license renewal scope are highlighted on those drawings. The single 

license renewal drawing for structures was based on the site plan. Based on its review, the staff 

finds the applicant’s response to RAI 2.3.3.15-1 acceptable because the applicant clarified that 

the items (louvers) identified in the RAI were in scope and were addressed in LRA 

Section 2.4.3. 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 Section 2.3.3.15, UFSAR Section 9.4.7, license renewal boundary 

drawings, and RAI response to determine if the applicant failed to identify any components 

within the scope of license renewal. In addition, the staff’s review determined if the applicant 

failed to identify any components subject to an AMR. On the basis of its review, the staff 

concludes the applicant has appropriately identified the diesel generator building HVAC system 

mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), 

and that the applicant has adequately identified the mechanical components subject to an AMR 

in accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.3.16 Radwaste Building Heating, Ventilation, and Air Conditioning System 

2.3.3.16.1 Summary of License Renewal Application Technical Information 

LRA Section 2.3.3.16 describes the radwaste building HVAC system, which is a once-through 

ventilation system with no recirculation, except for the radwaste control room, which has a 

recirculation AHU. The system provides a suitable environment for personnel comfort and safe 

operation of equipment. Further, the building airflow patterns inhibit the spread of airborne 

radioactivity and maintain a slight negative pressure in the building. 

LRA Table 2.3.3-16 identifies the components subject to an AMR for the radwaste building 

HVAC system by component type and intended function. The failure of portions of the 

nonsafety-related SSCs in the radwaste building HVAC system potentially could prevent the 

satisfactory accomplishment of a safety-related function. In addition, portions of the system 

perform functions that support fire protection requirements. 

2.3.3.16.2 Staff Evaluation and Conclusion 

The staff reviewed LRA Section 2.3.3.16, UFSAR Section 9.4.3 and Appendix 9B.2.10, and the 

license renewal boundary drawings using the evaluation methodology described in 

SER Section 2.3 and the guidance in SRP-LR Section 2.3 to determine if the applicant failed to 

identify any components within the scope of license renewal. In addition, the staff’s review 

determined if the applicant failed to identify any components subject to an AMR. The staff found 

no such omissions. On the basis of its review, the staff concludes the applicant has 

appropriately identified the radwaste building HVAC system mechanical components within the 

scope of license renewal, as required by 10 CFR 54.4(a). The staff also finds that the applicant 

has adequately identified the mechanical components subject to an AMR in accordance with the 

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

2.3.3.17 Turbine Building Heating, Ventilation, and Air Conditioning System 

2.3.3.17.1 Summary of License Renewal Application Technical Information in the Application 

LRA Section 2.3.3.17 describes the turbine building HVAC system, which is comprised of three 

major subsystems. The general area HVAC subsystem maintains environmental conditions 

suitable for equipment operation during normal plant operations and shutdown periods. The 

battery and switchgear room HVAC subsystem prevents the accumulation of hydrogen gas in 

the battery room during normal plant operation and shutdown periods. The lube oil room HVAC 
Scoping and Screening Methodology 

 2-62 

subsystem removes combustible gases and heat from the lube oil room during normal plant 

operation and shutdown periods. 

LRA Table 2.3.3-17 identifies the components subject to an AMR for the turbine building HVAC 

system by component type and intended function. Portions of the turbine building HVAC 

system perform functions that support fire protection and SBO requirements. 

2.3.3.17.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.17, UFSAR Section 9.4.4 and Appendix 9B.2.20.1, and 

the license renewal boundary drawings using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review of LRA 

Section 2.3.3.17 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 2.3.3.17-1, dated November 13, 2009, the staff requested that the applicant explain the 

scoping status of the backdraft dampers and ducting downstream of certain fire dampers 

because the applicant highlighted the fire dampers as in the scope of license renewal on the 

license renewal drawings. 

In its response, dated December 11, 2009, the applicant stated that these fire dampers are 

installed in a two-hour fire barrier wall, but are not credited for a fire protection function. The fire 

dampers are credited for a SBO function; therefore, they are in the scope of license renewal and 

are highlighted on the drawing. The downstream ducting and backdraft dampers do not have a 

fire protection or a SBO function and are not in scope; thus, the applicant did not highlight them 

on the drawing. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.17-1 acceptable 

because the applicant clarified that fire dampers were in scope for a SBO function, and the 

downstream ducting and backdraft dampers were not in scope. Therefore, the staff’s concern 

described in RAI 2.3.3.15-1 is resolved. 

2.3.3.17.3 Conclusion 

The staff reviewed the LRA, UFSAR Section 9.4.4 and Appendix 9B.2.20.1, license renewal 

boundary drawings, and the RAI response to determine if the applicant failed to identify any 

components within the scope of license renewal. In addition, the staff’s review determined if the 

applicant failed to identify any components subject to an AMR. On the basis of its review, the 

staff concludes the applicant has appropriately identified the turbine building HVAC system 

mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), 

and that the applicant has adequately identified the mechanical components subject to an AMR 

in accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.3.18 Miscellaneous Site Structures and Spray Pond Pump House Heating, 

Ventilation, and Air Conditioning System 

2.3.3.18.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.18 describes the miscellaneous site structures HVAC systems, including the 

spray pond pump house HVAC system. The spray pond pump house HVAC system is the only 

miscellaneous site structures HVAC system that is within the scope of license renewal. Each 

unit has two redundant ESP pump houses located next to the ESPs. Each house is equipped 

with one essential ventilation exhaust fan, which maintains room temperature at or below the 

spray pond qualification temperature during emergency or post accident operation of the 

ESP system. 
 Scoping and Screening Methodology 

 2-63 

LRA Table 2.3.3-18 identifies the components subject to an AMR for the miscellaneous site 

structures and the spray pond pump house HVAC system by component type and intended 

function. The spray pond pump house HVAC system contains safety-related components relied 

upon to remain functional during and following DBEs. Additionally, portions of the spray pond 

pump house HVAC system perform functions that support fire protection and SBO 

requirements. 

2.3.3.18.2 Staff Evaluation and Conclusion 

The staff reviewed LRA Section 2.3.3.18, UFSAR Section 9.4.8, Appendix 9B.2.7, and 

Appendix 9B.2.8, and the license renewal boundary drawings using the evaluation methodology 

described in SER Section 2.3 and the guidance in SRP-LR Section 2.3 to determine if the 

applicant failed to identify any components within the scope of license renewal. In addition, the 

staff’s review determined if the applicant failed to identify any components subject to an AMR. 

The staff found no such omissions. On the basis of its review, the staff concludes the applicant 

has appropriately identified the ESP pump house HVAC system mechanical components within 

the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has 

adequately identified the mechanical components subject to an AMR in accordance with the 

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

2.3.3.19 Fire Protection System 

2.3.3.19.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.19 describes the fire protection system as comprised of the following: 

 Two 50-percent diesel-driven fire water pumps, one 50-percent motor-driven fire pump, 

fire water pump drivers, fire water tanks, and underground distribution system including 

outside loop, hydrants, sectional control valves, and isolation valves 

 Hose stations, standpipes, halon, CO2, deluge, and preaction systems within the power 

block, including control valves, spray nozzles, and sprinkler heads 

 Diesel fuel oil supply to the motor-driven fire pumps 

 A jockey pump with associated piping 

The LRA states that the purpose of the fire protection system is to minimize the effects of fire on 

plant SSCs important to safety, such that a fire will not compromise the ability to achieve safe 

shutdown of the plant. Further, the LRA states that the safety-related components at the 

containment penetrations are included in this system. 

LRA Table 2.3.3-19 identifies the components subject to an AMR for the fire protection system 

by component type and intended function. According to the LRA, the fire protection system has 

intended functions under 10 CFR 54.4(a)(1), 10 CFR 54.4(a)(2), and 10 CFR 54.4(a)(3). 

2.3.3.19.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.19, UFSAR Section 9.5.1 and Appendix 9B, and license 

renewal drawings using the evaluation methodology described in SER Section 2.3 and guidance 

in SRP-LR, Section 2.3. During its review, the staff evaluated the system functions described in 

the LRA and UFSAR to verify that the applicant had not omitted from the scope of license 

renewal any components with intended functions under 10 CFR 54.4(a). The staff then 

reviewed those components that the applicant identified as within the scope of license renewal 

to verify that the applicant had not omitted any passive or long-lived components subject to an 

AMR in accordance with 10 CFR 54.21(a)(1). 

The staff also reviewed the fire protection CLB documents listed in the Operating License 

Conditions (2.C(7), 2.C(6), and 2.F) and NUREG-0857, “Safety Evaluation Report related to the 
Scoping and Screening Methodology 

 2-64 

operation of Palo Verde Nuclear Generating Station Units 1, 2 and 3,” dated November 1981 

through Supplement 11. 

This review included the applicant’s commitments to 10 CFR 50.48, “Fire protection” (i.e., 

approved fire protection program), as provided in the responses to Appendix A to the BTP 

Auxiliary Systems Branch (APS) 9.5-1, documented in PVNGS, Units 1, 2, and 3, SER, and 

NUREG-0857, dated November 1981 through Supplement 11. 

During its review of LRA Section 2.3.3.19, the staff identified areas in which additional 

information was necessary to complete its review of the applicant’s scoping and screening 

results. The applicant responded to the staff’s RAIs as discussed below. 

In RAI 2.3.3.19-1, dated November 12, 2009, the staff questioned why a license renewal 

drawing for the fire protection system shows the fire water system and associated components 

(outside transformers) as outside the scope of license renewal (i.e., not highlighted). In the RAI, 

the staff requested that the applicant verify if these fire water systems and associated 

components are within the scope of license renewal, in accordance with 10 CFR 54.4(a) and 

subject to an AMR, in accordance with 10 CFR 54.21(a)(1). The staff asked that the applicant 

justify excluding these components from the scope of license renewal and an AMR. 

In its response, dated December 23, 2009, the applicant provided scoping and screening results 

for the fire protection system components in question. The applicant stated the following: 

Transformers shown on drawing LR-PVNGS-FP-01-M-FPP-002 at coordinates 

B-2 through B-7 are electrical components within the scope of license renewal. 

These transformers are excluded from aging management review in accordance 

with 10 CFR 54.21(a)(1). NEI 95-10 Appendix B item 104 identifies that 

transformers are excluded from an AMR under 10 CFR 54.21(a)(1). 

These structures, systems, and components (SSCs) were not highlighted on 

drawing LR-PVNGS-FP-01-M-FPP-002 because those drawings are mechanical 

boundary drawings and only mechanical components within scope of license 

renewal are highlighted on mechanical boundary drawings. The scoping and 

screening methodology for mechanical systems is further detailed in the PVNGS 

LRA Section 2.1.3.1, and the scoping and screening methodology for electrical 

systems is further detailed in PVNGS LRA Section 2.1.3.3. A single license 

renewal drawing, LR-PVNGS-ELEC-E-MAA-001, was created for electrical [staff] 

based on the switchyard one-line diagram. 

In evaluating this response, the staff found that it was incomplete and that review of LRA 

Section 2.3.3.19 could not be completed. The applicant did not explain why fire water systems 

installed on outdoor transformers are not within the scope of license renewal and subject to an 

AMR. The applicant indicated that electrical components are within the scope of license 

renewal, but transformers are excluded from an AMR in accordance with 10 CFR 54.21(a)(1). 

The staff’s question concerned scoping and AMR of fire water systems installed on outdoor 

transformers. This resulted in the staff holding a telephone conference with the applicant on 

January 18, 2010, to discuss information necessary to resolve the concern in RAI 2.3.3.19-1. 

During the call, the applicant explained that the fire water systems were determined to have no 

license renewal intended function. The applicant stated that PVNGS complies with Appendix A 

to BTP APCSB 9.5-1 by locating all oil-filled transformers 50-feet from any building containing 

safety-related systems. 

The staff reviewed the commitment to 10 CFR 50.48, “Fire protection” (i.e., approved fire 

protection program) and performed a point-by-point comparison with BTP APCSP 9.5-1 as 

documented in the UFSAR, Table 9B.3-1. Section D.1(h) of the BTP APCSP 9.5-1 

recommends that buildings containing safety-related systems should be protected from 
 Scoping and Screening Methodology 

 2-65 

exposure or spill fires involving oil filled transformers by location of the transformers at least 

50 feet away or verifying that building walls within 50-feet of oil filled transformers are without 

openings and have a fire resistance rating of at least 3-hours. UFSAR Table 9B.3-1 states that 

oil filled transformers are located at least 50-feet from any building containing safety-related 

systems with the exception of the west ESF transformer, which is located approximately 48 feet 

from the 3-hour rated auxiliary building exterior wall. Based on the applicant’s information in 

UFSAR Table 9B.3-1 and the applicant’s compliance statements, the staff finds that the fire 

protection systems for the subject outdoor oil filled transformers are correctly excluded from the 

scope of the license renewal. Therefore, the staff’s concern described in RAI 2.3.3.19-1 is 

resolved. 

In RAI 2.3.3.19-2, dated November 12, 2009, the staff questioned why the license renewal fire 

protection drawing identified the fuel tank dikes and fire protection system valves and drains in 

the cable spreading room and radwaste building as out of the scope of license renewal. 

In the RAI, the staff requested that the applicant verify if these fire protection system 

components are within the scope of license renewal, in accordance with 10 CFR 54.4(a) and 

subject to an AMR, in accordance with 10 CFR 54.21(a)(1). The staff requested that the 

applicant justify excluding these components from the scope of license renewal and an AMR. 

In its response, dated December 23, 2009, the applicant provided scoping and screening results 

for the fire protection system components in question in the license renewal drawing. For the 

upper and lower cable spreading room and radwaste building, the applicant stated the following: 

LRA drawing LR-PVNGS-FP-01-M-FPP-003 has been revised to reflect that the 

fire water system valves and drains in the Upper and Lower Cable Spreading 

Room and Radwaste Building are within the scope of license renewal. The 

additional components have been highlighted in green on Revision 1 of LRA 

drawing LR-PVNGS- FP-01-M-FPP-003. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.19-2 acceptable 

because it indicated that the fire protection system and the components in question are within 

scope of license renewal and subject to an AMR. 

For fire water system valves and drains, the applicant stated the following: 

LRA drawing LR-PVNGS-FP-01-M-FPP-006 has been revised to reflect that the 

fire water system valves and drains are within the scope of license renewal, with 

the exception of the valves noted below. The additional components are 

highlighted in green on Revision 1 of LRA drawing 

LR-PVNGS-FP-01-M-FPP-006. 

The following valves shown on LRA drawing LR-PVNGS-FP-01-M-FPP-006 are 

not within the scope of license renewal because they are not part of the criteria 

(a)(3) pressure boundary and do not have a criterion (a)(2) function. Criterion 

(a)(2) components are non-safety-related and are in rooms where there is 

potential for spatial interaction with safety-related equipment. These valves are 

not located in rooms with the potential for spatial interaction. 

Fire water system valves not within the scope of license renewal: 

 V407 & V408, Preaction Valve V711 vent & drain 

 V419 & V420, Preaction Valve V729 vent & drain 

 V421 & V422, Preaction Valve V726 vent & drain 

 V423 & V424, Preaction Valve V723 vent & drain 
Scoping and Screening Methodology 

 2-66 

 V425 & V426, Preaction Valve V732 vent & drain 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.19-2 acceptable 

because it indicated that the water system valves and drains in question are within the scope of 

license renewal and subject to an AMR, with the exception of the valves mentioned above. 

These valves are drain valves and can be isolated from the rest of the system to maintain the 

fire water system pressure boundary. Therefore, these valves are not relied on to perform a 

pressure boundary intended function, and are not subject to an AMR. The applicant stated that 

the failure of the drain valves will not prevent satisfactory accomplishment of a safety function 

and are not required to demonstrate compliance with 10 CFR 54.4(a)(3). The staff agrees with 

the applicant’s exclusion of the valves from the scope of license renewal since these valves can 

be isolated and do not perform a 10 CFR 54.4(a)(1) or (3) function; therefore, the staff’s concern 

is resolved. 

For fire water system valves, drains, and fuel tank dikes on the license renewal drawing for fire 

protection, the applicant stated the following: 

LRA drawing LR-PVNGS-FP-AO-M-FPP-001 has been revised to show fire water 

system valves and drains within the scope of license renewal, with the exception 

of the items noted below. The additional components are highlighted in green on 

Revision 1 of LRA drawing LR-PVNGS-FP-AO-M-FPP-001. 

Portions of the fire water system shown on drawing 

LR-PVNGS-FP-AO-M-FPP-001 and listed below do not have a criteria (a)(3) 

function or a criterion (a)(2) function. Criterion (a)(2) components are 

non-safety-related and are in rooms where there is potential for spatial interaction 

with safety-related equipment. These valves are not located in rooms with the 

potential for spatial interaction. 

Portions of the Fire Water System not within the scope of license renewal: 

 Caustic Injection Pump & associated piping and valves 

 Sulfite Injection Pump & associated piping and valves 

 Motor Driven Recirculation Pump & associated piping and valves (for 

chemical addition) 

 Fire Water Pump test/recirculation piping and valves 

 Water Reclamation fire suppression piping and valves 

 Chemical Storage Building fire suppression piping and valves 

 Vehicle Maintenance Facility fire suppression piping and valves 

 Station Blackout Gas Turbine General Area fire suppression piping and 

valves 

 Low Level Radioactive Waste Material Storage Facility fire suppression 

piping and valves 

The fuel oil tank dikes are in the scope of license renewal and screened in as 

generic concrete components in LRA Section 2.4.13, “Yard Structures.” The fuel 

oil tank dikes are not highlighted in green on LRA drawing 

LR-PVNGS-FP-AO-M-FPP-001 because they are not mechanical components. 

Only mechanical components within scope of license renewal are highlighted on 

mechanical boundary drawings. A single license renewal drawing, 

LR-PVNGS-STR-OOB-001, was created for structures based on the site plan. 
 Scoping and Screening Methodology 

 2-67 

As a result of these changes, LRA Tables 2.3.3-19 and 3.3.2-19 have been 

revised and are included in Enclosure 2 as LRA Amendment 6. A cast iron 

orifice for the branch line associated with the jockey pump in the Fire Pump 

House has been added to LRA Tables 2.3.3-19 and 3.3.2-19. The material for 

the small diameter system air check valves for preaction valves was corrected 

from cast iron to copper alloy and resulted in an additional line on LRA 

Table 2.3.3-19 for the interior environment associated with the copper alloy 

check valves. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.19-2 acceptable 

because it indicated that the water system valves and drains in question are within the scope of 

license renewal and subject to an AMR, with exception of the certain fire protection 

components. The components do not have a license renewal intended function and are, 

therefore, outside the scope of license renewal and are not subject to an AMR. Further, the 

applicant identified that the fuel oil tank dikes are within the scope of license renewal and 

included in LRA Section 2.4.13, “Yard Structures.” In addition, the applicant identified which 

portions of the fire protection system and components are excluded from the scope of license 

renewal in accordance with 10 CFR 54.21(a)(2) and 10 CFR 54.21(a)(3). The staff’s concern 

is resolved. 

In RAI 2.3.3.19-3, dated November 12, 2009, the staff questioned why a license renewal fire 

protection drawing identified certain components associated with the carbon dioxide (CO2) fire 

suppression system in the Auxiliary Building as outside the scope of license renewal and not 

subject to an AMR. 

In the RAI, the staff requested that the applicant verify whether these CO2 fire suppression 

system components are in the scope of license renewal, in accordance with 10 CFR 54.4(a) and 

subject to an AMR, in accordance with 10 CFR 54.21(a)(1). The staff requested that the 

applicant justify excluding these components from the scope of license renewal and an AMR. 

In its response, dated December 23, 2009, the applicant provided the scoping and screening 

results for the CO2 fire suppression system components in question in license renewal drawing 

LR-PVNGS-FP-01-M-FPP-004. For the CO2 fire suppression system components, the applicant 

stated the following: 

LRA drawing LR-PVNGS-FP-01-M-FPP-004 has been revised (Revision 1) to 

show the following additional components within scope of license renewal 

(highlighted in green): 

 Drain valve V380 at coordinate B-5 

 Switchgear Building CO2 hose stations 

 CO2 Storage Unit components VE052, VW001, V743, UV116 and 

associated piping 

The Electric Vaporizer and CO2 supply line for the Main Generator purge do not 

have a license renewal intended function and are not within the scope of license 

renewal. 

Based on its review, the staff finds applicant’s response to RAI 2.3.3.19-3 acceptable because it 

indicated that the CO2 fire suppression system components in question are within the scope of 

license renewal and subject to an AMR. Further, the applicant determined that the electric 

vaporizer and CO2 supply line for the main generator have no license renewal intended function 

and, therefore, are not within the scope of license renewal and subject to an AMR. The staff 

finds this acceptable, and the staff’s concern is resolved. 
Scoping and Screening Methodology 

 2-68 

In RAI 2.3.3.19-4, dated November 12, 2009, the staff stated that LRA Tables 2.3.3-19 and 

3.3.2-19 exclude several types of fire protection components that appear in NUREG-0857, 

“Safety Evaluation Report Related to the Operation of Palo Verde Nuclear Generating Station, 

Units 1, 2, and 3,” and license renewal drawings. These components include the following: 

 Pipe fittings, pipe supports, hangers, and couplings 

 Fire hose stations, connections, and racks 

 Filter housings 

 Halon 1301 storage bottles 

 Dikes for oil spill confinement 

 Floor drains and curbs for fire-fighting water 

 Passive components in the diesel fuel fire pump 

The staff requested that the applicant verify whether LRA Tables 2.3.3-19 and 3.3.2-19 should 

include the components listed above. If they are excluded from the scope of license renewal 

and not subject to an AMR, the staff requested that the applicant justify their exclusion. 

In its response, dated December 23, 2009, the applicant stated that it evaluated the list of 

components and determined no changes to the LRA are required as described below: 

Pipe fittings and couplings. Pipe fittings and couplings are evaluated as the 

component type “piping.” This is consistent with the definition of piping, piping 

components, and piping elements noted in the Generic Aging Lessons Learned 

Report, Chapter IX.B. The component type “piping” is identified in LRA 

Table 2.4-14 as a component within the scope of license renewal and subject to 

an AMR. 

Pipe supports and hangers. Fire protection pipe supports and hangers are 

evaluated as structural component type “supports non-ASME” and are identified 

in LRA Table 2.4-14 as components within the scope of license renewal and 

subject to an AMR. 

Fire hose stations, connections and racks. Fire hose stations, connections and 

racks are evaluated as component types “piping” and “valve” and are identified in 

LRA Table 2.3.3-19 as components within the scope of license renewal and 

subject to an AMR. 

Filter housings. Filter housings are evaluated as part of the component type 

“Filter” in LRA Table 2.3.3-19 as components within the scope of license renewal 

and subject to an AMR. 

Halon 1301 storage bottles. The component type of “tank” specified in LRA 

Table 2.3.3-19 includes Halon 1301 storage bottles within the scope of license 

renewal and subject to an AMR. This is consistent with the definition of tanks 

noted in the Generic Aging Lessons Learned Report, Chapter IX.B. 

Dikes for oil spill confinement. The response to question 9A.86(c) documents 

that in the diesel generator building, the day tank room door curbs are sized to a 

height to contain the full volume of the day tank and its associated piping. These 

curbs are evaluated as component type “concrete element” and are identified in 

LRA Table 2.4-3 as components within the scope of license renewal and subject 

to an AMR for fire protection. There are no oil containment dikes in the outside 

areas that are within the scope of license renewal and subject to an AMR. The 

UFSAR, Table 9B.3-1, Section D.1(h), documents that all oil filled transformers 

are located at least 50 feet from any building containing safety-related systems 

with the exception of the west ESF transformer, which is located approximately 
 Scoping and Screening Methodology 

 2-69 

48 feet from the 3-hour-rated auxiliary building exterior wall. Therefore, dikes for 

oil spill confinement are not within the scope of license renewal. The UFSAR, 

Section 3.8.4.1 documents that the diesel generator fuel oil storage tanks are 

located underground with approximately 10 feet of earth cover. 

Floor drains and curbs for fire-fighting water. Floor drains are evaluated as 

component type “piping” and are identified in LRA Table 2.3.3-30 as components 

within the scope of license renewal and subject to an AMR. Curbs for containing 

fire-fighting water are evaluated as component type “concrete element” and are 

identified for each building in LRA Section 2.4 as components within the scope of 

license renewal and subject to an AMR. 

Passive components in the diesel fuel fire pump engine. These components do 

not have unique component identification numbers and are integral to the diesel 

engine, and are evaluated as part of the engine. The fire pump diesel engine is 

an active component and is excluded from an AMR in accordance with 

10 CFR 54.21(a)(1) as further detailed in NEI 95-10 Appendix B, which states 

that fire pump diesel engines are excluded from an AMR under 

10 CFR 54.21(a)(1). 

In reviewing the applicant’s response to the RAI, the staff found it had resolved each item in the 

RAI. Although the description of the “piping” line item, provided in LRA Tables 2.3.3-19 and 

3.3.2-19, does not list these components specifically, the applicant stated that it considers this 

line item to include the pipe fittings and couplings. In addition, the applicant addressed pipe 

support and hangers in LRA Table 2.4-14, “Supports,” under component type “support 

non-ASME.” The applicant said that it evaluated the fire hose station, connection, and racks 

under the component types “piping” and “valves” in LRA Table 2.3.3.19, with AMR results 

provided in Table 3.3.2-19. The applicant addressed the filter housing under the component 

type “filter” in LRA Table 2.3.3.19, with AMR results in Table 3.3.2.19. Similarly, the applicant 

addressed Halon 1301 storage bottles under the component type “tank” in LRA Table 2.3.3.19, 

with AMR results in Table 3.3.2.19. The applicant addressed the structural AMR of dikes for oil 

spill confinement and curbs for containing fire-fighting water under the component type 

“concrete element” in LRA Table 2.4-3, “Diesel Generator Building.” Floor drains for fire-fighting 

water are considered under component type “piping” in LRA Table 2.3.3-30, “Miscellaneous 

Auxiliary Systems In-Scope only based on Criterion 10 CFR 54.4(a)(2).” 

In its response, the applicant also confirmed that it evaluated passive components in the diesel 

fuel fire pump engine as part of the engine because these components do not have unique 

component identification numbers and are integral to the diesel engine. Further, the staff 

agrees with the applicant’s determination that the fire pump diesel engines are excluded from an 

AMR under 10 CFR 54.21(a)(1). 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.19-4 acceptable 

because it confirms that the components in question are within the scope of license renewal and 

subject to an AMR. The staff’s concern is resolved. 

2.3.3.19.3 Conclusion 

The staff reviewed the LRA Section 2.3.3.19, UFSAR Section 9.5.1 and Appendix 9B, RAI 

responses, and license renewal drawings to determine if the applicant failed to identify any fire 

protection systems and components within the scope of license renewal. In addition, the staff’s 

review determined if the applicant failed to identify any components subject to an AMR. On the 

basis of its review, the staff concludes that the applicant has adequately identified the fire 

protection system components within the scope of license renewal, as required by 

10 CFR 54.4(a). The staff also finds that the applicant has adequately identified the fire 
Scoping and Screening Methodology 

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protection system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.3.3.20 Diesel Generator Fuel Oil Storage and Transfer System 

2.3.3.20.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.20 describes the diesel generator fuel oil storage and transfer system, which 

is comprised of an underground diesel fuel oil storage tank, diesel fuel oil transfer pump, diesel 

fuel oil day tank, piping, valves, and instrumentation for each diesel generator. The purpose of 

the system is to provide fuel oil for the emergency diesel generators (EDGs). 

LRA Table 2.3.3-20 identifies the components subject to an AMR for the diesel generator fuel oil 

storage and transfer system by component type and intended function. The diesel generator 

fuel oil storage and transfer system contains safety-related components relied upon to remain 

functional during and following DBEs. The failure of portions of the nonsafety-related SSCs in 

the system potentially could prevent the satisfactory accomplishment of a safety-related 

function. In addition, portions of the system perform functions that support fire protection 

requirements. 

2.3.3.20.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.20, UFSAR Section 9.5.4 and Appendix 9B.2.1, and the 

license renewal boundary drawings using the evaluation methodology described in 

SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review 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 2.3.3.20-1, dated December 3, 2009, the staff noted that a drawing specified in 

LRA Section 2.3.3.20, could not be found in the package. The staff asked the applicant to 

provide additional information to verify which drawing was the correct drawing to use during the 

scoping and screening review. 

In its response, dated January 18, 2010, the applicant stated that the drawing number in 

LRA Section 2.3.3.20 is incorrect, but the provided drawing is the correct drawing. The 

applicant submitted a correction to the LRA. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.20-1 acceptable 

because the staff confirmed that the applicant corrected LRA Section 2.3.3.20 to include the 

appropriate drawing. 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 Section 2.3.3.20, UFSAR Section 9.5.4 and Appendix 9B.2.1, RAI 

response, and boundary drawings to determine if the applicant failed to identify any components 

within the scope of license renewal. In addition, the staff’s review determined if the applicant 

failed to identify any components subject to an AMR. On the basis of its review, the staff 

concludes the applicant has appropriately identified the diesel generator fuel oil storage and 

transfer system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a). The staff also finds that the applicant has adequately identified the mechanical 

components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.3.3.21 Diesel Generator 

2.3.3.21.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.21 describes the diesel generator system, which is comprised of two diesel 

generators per unit, each driven by a four-cycle, 20-cylinder diesel engine. The purpose of the 
 Scoping and Screening Methodology 

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system is to provide a reliable onsite power source capable of starting and supplying the 

essential loads necessary to shut down the plant safely and maintain it in a safe shutdown 

condition if a loss of offsite power should occur. 

The diesel generator system consists of the following subsystems: 

 Diesel generator cooling water system 

 Diesel generator starting system 

 Diesel generator lubrication system 

 Diesel generator combustion air intake and exhaust system 

 Fuel oil system 

LRA Table 2.3.3-21 identifies the components subject to an AMR for the diesel generator 

system by component type and intended function. The diesel generator system contains 

safety-related components relied upon to remain functional during and following DBEs. The 

failure of portions of the nonsafety-related SSCs in the system potentially could prevent the 

satisfactory accomplishment of a safety-related function. In addition, portions of the system 

perform functions that support fire protection and SBO requirements. 

2.3.3.21.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.21; UFSAR Sections 7.4.1.1.1, 8.3.1.1.4, 9.5.4, 9.5.5, 

9.5.6, 9.5.7, and 9.5.8 and the license renewal boundary drawings using the evaluation 

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The 

staff’s review 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 2.3.3.21-1, dated December 3, 2009, the staff noted components that are within the 

scope of license renewal for criteria 10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(2) but are not 

included in Table 2.3.3-21. The staff asked the applicant to provide additional information 

explaining why specified components are not included as component types subject to an AMR 

in LRA Table 2.3.3-21. 

In its response, dated January 18, 2010, the applicant stated that individual component names 

and component types in the LRA are consistent with the component names and component 

types as they appear in the plant equipment database as follows: 

 Diesel air intake silencers are included in LRA Table 2.3.3-21 with the component type 

“filter.” 

 Local observation glasses, LG 344 and LG 343, are included in LRA Table 2.3.3-21 as 

component type “sight gauge.” 

 Turbocharger housings are included in LRA Table 2.3.3-21 as component type “blower.” 

 Diesel generator air intake manifolds are evaluated as within scope of license renewal 

as integral parts of the EDG. 

 Starting air headers are included in LRA Table 2.3.3-21 and subject to AMR with the 

component type “piping.” 

In a follow-up response, dated March 1, 2010, the applicant stated that it evaluated injector 

housings as within the scope of license renewal as integral parts of the EDG. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.21-1 acceptable 

because the applicant clarified how each of the components listed above that are subject to an 
Scoping and Screening Methodology 

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AMR are presented in Table 2.3.3-21 and provided the rationale for those components not 

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, dated December 3, 2009, the staff noted that the three pipelines lack drawing 

continuation information at the end locations of criterion 10 CFR 54.4(a)(2) pipe. The staff 

asked the applicant to provide additional information to locate the license renewal boundary. 

In its response, dated January 18, 2010, the applicant stated that the appropriate license 

renewal terminal component symbol has been added to the end locations of each of the 

three 10 CFR 54.4(a)(2) pipes. The applicant provided revised drawings to the staff. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.21-2 acceptable 

because the appropriate license renewal terminal component symbol has been added to the 

drawing continuation locations. The staff verified the additions by reviewing the revised 

drawings. Therefore, the staff’s concern described in RAI 2.3.3.21-2 is resolved. 

2.3.3.21.3 Conclusion 

The staff reviewed the LRA Section 2.3.3.21; UFSAR Sections 7.4.1.1.1, 8.3.1.1.4, 9.5.4, 9.5.5, 

9.5.6, 9.5.7, and 9.5.8; RAI responses; and original and revised boundary drawings to 

determine if the applicant failed to identify any components within the scope of license renewal. 

In addition, the staff’s review determined if the applicant failed to identify any components 

subject to an AMR. On the basis of its review, the staff concludes the applicant has 

appropriately identified the diesel generator mechanical components within the scope of license 

renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the 

mechanical components subject to an AMR in accordance with the requirements stated 

in 10 CFR 54.21(a)(1). 

2.3.3.22 Domestic Water System 

2.3.3.22.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.22 describes the domestic water system, which is comprised of a well water 

supply subsystem, a water treatment subsystem, and a storage and transfer subsystem, which 

are all shared facilities. The LRA states that the purpose of the system is to process local onsite 

well water to remove suspended solids and part of the dissolved solids, chlorinate and 

neutralize the processed water, and store and transfer the domestic water to each unit and 

common facilities at the site. 

LRA Table 2.3.3-22 identifies the components subject to an AMR for the domestic water system 

by component type and intended function. The failure of portions of the nonsafety-related SSCs 

in the domestic water system potentially could prevent the satisfactory accomplishment of a 

safety-related function. In addition, portions of the system perform functions that support fire 

protection requirements. 

2.3.3.22.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.22, UFSAR Section 9.2.4, and the license renewal 

boundary drawings using the evaluation methodology described in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. The staff’s review 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 2.3.3.22-1, dated December 3, 2009, the staff noted that a license renewal drawing for 

the domestic water system shows the continuation of two 11⁄2-inch lines as within the scope of 

license renewal. The continuations on the associated drawing are not within the scope of 

license renewal. The staff asked the applicant to provide additional information to clarify the 

scoping classification for these pipe sections. 
 Scoping and Screening Methodology 

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In its response, dated January 18, 2010, the applicant stated the highlighting of the continuation 

of the 11⁄2-inch lines was inadvertently omitted on the drawing. The applicant revised the 

drawing to highlight these continuations and provided it to the staff. Based on its review, the 

staff finds the applicant’s response to RAI 2.3.3.22-1 acceptable because the applicant has 

revised the drawing to highlight these lines as within scope. The staff verified the additions by 

reviewing the revised drawings. Therefore, the staff’s concern described in RAI 2.3.3.22-1 is 

resolved. 

In RAI 2.3.3.22-2, dated December 3, 2009, the staff noted that a license renewal drawing for 

the domestic water system shows a continuation of line that could not be located. The applicant 

was requested to provide additional information to locate the license renewal boundary. 

In its response, dated January 18, 2010, the applicant stated that the line has been cut and 

capped and no longer continues to the associated drawing. The drawing was revised to show 

that the line is cut and capped and does not continue. The applicant provided the staff with a 

revised drawing. Based on its review, the staff finds the applicant’s response to RAI 2.3.3.22-2 

acceptable because the applicant stated the line is currently cut and capped and does not 

continue. The staff verified the additions by reviewing the revised drawings. Therefore, the 

staff’s concern described in RAI 2.3.3.22-2 is resolved. 

In RAI 2.3.3.22-3, dated December 3, 2009, the staff noted license renewal drawings for the 

domestic water system show components and associated relief valves and drain lines as not 

within the scope of license renewal. The staff noted that similar components on other domestic 

water system drawings are within the scope of license renewal. The staff asked the applicant to 

provide additional information to explain why the components and associated relief valves and 

drain lines are not within the scope of license renewal. 

In its response, dated January 18, 2010, the applicant stated that it revised the drawing to 

reflect that the components and associated relief and drain lines have been added to the scope 

of license renewal based on the criterion of 10 CFR 54.4(a)(2). The applicant provided the staff 

with revised drawings. Additionally, the applicant revised LRA Section 3.3.2.1.22 and LRA 

Table 3.3.2-22 to add components in a wetted gas environment. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.22-3 acceptable 

because the applicant added the components with its associated relief valves and drain lines as 

within the scope of license renewal. The staff verified the additions by reviewing the revised 

drawings. Therefore, the staff’s concern described in RAI 2.3.3.22-3 is resolved. 

2.3.3.22.3 Conclusion 

The staff reviewed the LRA Section 2.3.3.22, UFSAR Section 9.2.4, RAI responses, and original 

and revised boundary drawings to determine if the applicant failed to identify any components 

within the scope of license renewal. In addition, the staff’s review determined if the applicant 

failed to identify any components subject to an AMR. On the basis of its review, the staff 

concludes the applicant has appropriately identified the domestic water system mechanical 

components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the 

applicant has adequately identified the mechanical components subject to an AMR in 

accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.3.23 Demineralized Water System 

2.3.3.23.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.23 describes the demineralized water system, which is comprised of piping 

components, pumps, tanks and demineralizers. It removes dissolved gas and solids from the 

water processed from the reverse osmosis units of the domestic water system. The system 
Scoping and Screening Methodology 

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also stores and transfers demineralized water to multiple systems in each unit and to common 

facilities in the chemical production system. 

LRA Table 2.3.3-23 identifies the components subject to an AMR for the demineralized water 

system by component type and intended function. The demineralized water system contains 

safety-related components relied upon to remain functional during and following DBEs. The 

failure of portions of the nonsafety-related SSCs in the system potentially could prevent the 

satisfactory accomplishment of a safety-related function. 

2.3.3.23.2 Staff Evaluation and Conclusion 

The staff reviewed LRA Section 2.3.3.23, UFSAR Section 9.2.3, and the license renewal 

boundary drawings using the evaluation methodology described in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3 to determine if the applicant failed to identify any components 

within the scope of license renewal. In addition, the staff’s review determined if the applicant 

failed to identify any components subject to an AMR. The staff found no such omissions. 

On the basis of its review, the staff concludes the applicant has appropriately identified the 

demineralized water system mechanical components within the scope of license renewal, as 

required by 10 CFR 54.4(a), and that the applicant has adequately identified the mechanical 

components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.3.3.24 Water Reclamation Facility Fuel System 

2.3.3.24.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.24 describes the WRF fuel system that receives, stores, and supplies fuel oil 

for the lime re-calcining furnaces, the auxiliary boilers, and the SBO generators. 

LRA Table 2.3.3-24 identifies the component types subject to an AMR for the WRF fuel system 

by component type and intended function. Portions of the WRF fuel system perform functions 

that support SBO. 

2.3.3.24.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.24, UFSAR Sections 1.2.10.3.9 and 8.3.1.1.10, and the 

license renewal boundary drawings using the evaluation methodology described in 

SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review 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 2.3.3.24-1, dated December 3, 2009, the staff noted the license renewal drawing for the 

WRF fuel system shows two lines as not within the scope of license renewal that are connected 

to tanks which are shown as within the scope of license renewal. There is also no indication as 

to where these lines go. The staff asked the applicant to provide additional information as to 

why these lines are not in the scope of license renewal and to identify the line continuations. 

In its response, dated January 18, 2010, the applicant provided additional information and 

submitted a revised license renewal boundary drawing to locate the license renewal boundary. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.24-1 acceptable 

because the applicant provided boundary locations. This was verified by staff review of the 

revised drawing. Therefore, the staff’s concern described in RAI 2.3.3.24-1 is resolved. 

In RAI 2.3.3.24-2, dated December 3, 2009, the staff noted on the license renewal drawing for 

the WRF fuel system that certain pipe lines attached to the fuel oil storage tanks lack drawing 

continuation information at the end locations of pipe. The staff asked the applicant to provide 

additional information to locate the license renewal boundaries. 
 Scoping and Screening Methodology 

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In its response, dated January 18, 2010, the applicant provided additional information for each 

of the locations on the drawing including the license renewal boundaries. Based on its review, 

the staff finds the applicant’s response to RAI 2.3.3.24-2 acceptable because the boundary 

locations were provided. Therefore, the staff’s concern described in RAI 2.3.3.24-2 is resolved. 

2.3.3.24.3 Conclusion 

The staff reviewed the LRA Section 2.3.3.24, UFSAR Sections 1.2.10.3.9 and 8.3.1.1.10, RAI 

responses, and original and revised boundary drawings to determine if the applicant failed to 

identify any components within the scope of license renewal. In addition, the staff’s review 

determined if the applicant failed to identify any components subject to an AMR. On the basis 

of its review, the staff concludes the applicant has appropriately identified the WRF fuel system 

mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), 

and that the applicant has adequately identified the mechanical components subject to an AMR 

in accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.3.25 Service Gases (Nitrogen and Hydrogen) System 

2.3.3.25.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.25 describes the service gases system, which consists of two subsystems 

that supply nitrogen and hydrogen gas to various systems. 

LRA Table 2.3.3-25 identifies the components subject to an AMR for the service gases system 

by component type and intended function. The applicant stated that the service gases system 

contains safety-related components relied upon for containment isolation. The failure of 

portions of the nonsafety-related SCs in the system potentially could prevent the satisfactory 

accomplishment of a safety-related function. In addition, portions of the system perform 

functions that support EQ and SBO requirements. 

2.3.3.25.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.25; UFSAR Sections 6.2.4, 9.3.6, and Table 6.4.2-1; and 

the license renewal boundary drawings using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review 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 2.3.3.25-1, dated December 3, 2009, the staff noted the license renewal service gases 

system drawing shows continuation of a pipe section in scope for license renewal from the 

nitrogen accumulators to another drawing. Review of the associated drawing shows no 

apparent continuation. The staff asked the applicant to provide additional information to locate 

the license renewal boundary. 

In its response, dated January 18, 2010, the applicant stated that the continuation of the 

pipelines is within the scope of license renewal and specified the drawing. Based on its review, 

the staff finds the applicant’s response to RAI 2.3.3.25-1 acceptable because the applicant 

provided information to locate the license renewal boundaries. The staff reviewed the drawing 

and verified the license renewal boundaries. Therefore, the staff’s concern described in 

RAI 2.3.3.25-1 is resolved. 

2.3.3.25.3 Conclusion 

The staff reviewed LRA Section 2.3.3.25, UFSAR Sections 6.2.4, 9.3.6, and Table 6.4.2-1, RAI 

response, and original and revised boundary drawings to determine if the applicant failed to 

identify any components within the scope of license renewal. In addition, the staff’s review 

determined if the applicant failed to identify any components subject to an AMR. On the basis 

of its review, the staff concludes the applicant has appropriately identified the service gases 
Scoping and Screening Methodology 

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system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the mechanical components 

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

2.3.3.26 Gaseous Radwaste System 

2.3.3.26.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.26 describes the gaseous radwaste system, which is comprised of a waste 

gas surge tank and three waste gas decay tanks, waste gas compressors, piping, and valves. 

The system collects and processes radioactive and potentially radioactive waste gas and limits 

the release of gaseous activity. 

LRA Table 2.3.3-26 identifies the components subject to an AMR for the gaseous radwaste 

system by component type and intended function. The gaseous radwaste system contains 

safety-related components relied upon for containment isolation. The failure of portions of the 

nonsafety-related SCs in the system potentially could prevent the satisfactory accomplishment 

of a safety-related function. In addition, portions of the system perform functions that support 

EQ requirements. 

2.3.3.26.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.26, UFSAR Section 11.3 and Table 6.2.4-1, and the 

license renewal boundary drawings using the evaluation methodology described in 

SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review 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 2.3.3.26-1, dated December 3, 2009, the staff noted the license renewal drawing for the 

gaseous radwaste system shows continuation of a 1-inch pipe section that is shown as within 

the scope of license renewal from the volume control tank relief to another drawing. The staff 

noted that the pipe section on the associated drawing was not within the scope of license 

renewal. The staff asked the applicant to provide additional information to clarify the scoping 

classification for this pipe section. 

In its response, dated January 18, 2010, the applicant stated the drawing was not correct. 

The 1-inch line is not within scope of license renewal based on the scoping criteria of 

10 CFR 54.4(a). The applicant provided the staff with a revised drawing. Based on its review, 

the staff finds the applicant’s response to RAI 2.3.3.26-1 acceptable because the applicant 

clarified that the 1-inch line was not scoped correctly. The staff reviewed the drawing and 

verified the changes. Therefore, the staff’s concern described in RAI 2.3.3.26-1 is resolved. 

2.3.3.26.3 Conclusion 

The staff reviewed the LRA Section 2.3.3.26, UFSAR Section 11.3 and Table 6.2.4-1, RAI 

response, and original and revised boundary drawings to determine if the applicant failed to 

identify any components within the scope of license renewal. In addition, the staff’s review 

determined if the applicant failed to identify any components subject to an AMR. On the basis 

of its review, the staff concludes the applicant has appropriately identified the gaseous radwaste 

system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the mechanical components 

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

2.3.3.27 Radioactive Waste Drains System 

2.3.3.27.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.27 describes the radioactive waste drains system, which consists of piping 

components, valves, filters, drains and pumps. The radioactive waste drains system collects 
 Scoping and Screening Methodology 

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non-corrosive, radioactive or potentially radioactive liquid wastes from equipment and floor 

drains of various buildings and pumps the collected liquid wastes to the liquid radwaste system 

for processing. In addition, the radioactive waste drains system provides for indication of 

flooding of watertight rooms and leakage detection for the refueling pool and fuel pool liner 

plate. 

LRA Table 2.3.3-27 identifies the components subject to an AMR for the radioactive waste 

drains system by component type and intended function. The radioactive waste drains system 

contains safety-related components relied upon for containment isolation. The failure of 

portions of the nonsafety-related SCs in the system potentially could prevent the satisfactory 

accomplishment of a safety-related function. In addition, portions of the system perform 

functions that support EQ requirements. 

2.3.3.27.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.27, UFSAR Section 9.3.3 and Table 6.2.4-1, and the 

license renewal boundary drawings using the evaluation methodology described in 

SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review 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 2.3.3.27-1, dated December 3, 2009, the staff noted the license renewal drawing for the 

radioactive waste drains system shows a section of piping continuing from another drawing 

(essential ACU) as not within the scope of license renewal. The essential ACU piping section is 

included within scope for 10 CFR 54.4(a)(2). The staff asked the applicant to provide additional 

information to justify why this section of piping is included within the scope of license renewal on 

one drawing (essential ACU drawing) and not within the scope of license renewal on the 

radioactive waste drains system drawing. 

In its response, dated January 18, 2010, the applicant stated the portion of the line extending 

onto the radioactive waste drains system license renewal boundary drawing has been revised to 

include the line within the scope of license renewal based on criterion 10 CFR 54.4(a)(2). The 

applicant provided the staff with a revised drawing. Based on its review, the staff finds the 

applicant’s response to RAI 2.3.3.27-1 acceptable because the applicant indicated the 

continuation of the line as within scope. The staff reviewed the drawing and verified the 

changes. Therefore, the staff’s concern described in RAI 2.3.3.27-1 is resolved. 

In RAI 2.3.3.27-2 and RAI 2.3.3.27-3, dated December 3, 2009, the staff noted the license 

renewal radioactive waste drains system drawing shows continuations of pipe sections, in scope 

for license renewal, to drawings that show the lines as not within the scope of license renewal. 

The staff asked the applicant to provide additional information to explain the discrepancy. 

In its response, dated January 18, 2010, the applicant stated the continuations of the pipe 

sections are within scope of license renewal and should have been shown as within scope for 

10 CFR 54.4(a)(2). The applicant provided the staff with revised drawings for both RAIs. Based 

on its review, the staff finds the applicant’s response to RAI 2.3.3.27-2 and RAI 2.3.3.27-3 

acceptable because the applicant included the continuations in scope for 10 CFR 54.4(a)(2) on 

the revised drawings. The staff reviewed the drawings and verified the changes. Therefore, the 

staff’s concerns, described in RAI 2.3.3.27-2 and RAI 2.3.3.27-3, are resolved. 

2.3.3.27.3 Conclusion 

The staff reviewed the LRA Section 2.3.3.27, UFSAR Section 9.3.3 and Table 6.2.4-1, RAI 

responses, and original and revised boundary drawings to determine if the applicant failed to 

identify any components within the scope of license renewal. In addition, the staff’s review 

determined if the applicant failed to identify any components subject to an AMR. On the basis 

of its review, the staff concludes the applicant has appropriately identified the radioactive waste 
Scoping and Screening Methodology 

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drains system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the mechanical components 

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

2.3.3.28 Station Blackout Generator System 

2.3.3.28.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.28 describes the SBO generator system, which consists of two 100-percent 

capacity turbine generators. The SBO generator system provides alternate AC power to 

necessary station loads via the safety-related 4.16 kV buses during an SBO event in any 

one unit. 

LRA Table 2.3.3-28 identifies the components subject to an AMR for the SBO generator system 

by component type and intended function. Portions of the SBO generator system perform 

functions that support SBO requirements. 

2.3.3.28.2 Staff Evaluation and Conclusion 

The staff reviewed LRA Section 2.3.3.28, UFSAR Section 1.2.10.3.9, and the license renewal 

boundary drawings using the evaluation methodology described in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3 to determine if the applicant failed to identify any components 

within the scope of license renewal. In addition, the staff’s review determined if the applicant 

failed to identify any components subject to an AMR. The staff found no such omissions. On 

the basis of its review, the staff concludes the applicant has appropriately identified the SBO 

generator system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a). In addition, the staff finds that the applicant has adequately identified the 

mechanical components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.3.3.29 Cranes, Hoists, and Elevators 

2.3.3.29.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.29 describes the cranes, hoists, and elevators group, which provide lifting 

and maneuvering capacity in various buildings. The applicant identified the following cranes 

and trolleys in the LRA as within the scope of license renewal: 

 Auxiliary building 4-ton trolleys 

 Main steam supply system south room 140-foot elevation hoist assemblies 

 Diesel generator building train A, 5-ton bridge crane 

 Diesel generator building train B, 5-ton bridge crane 

 Diesel generator building room 1, 25-ton trolley 

 Diesel generator building room 2, 25-ton trolley 

LRA Table 2.3.3-29 identifies the components subject to an AMR for the cranes, hoists, and 

elevators group by component type and intended function. The cranes, hoists, and elevators 

group contains nonsafety-related components, the failure of which potentially could prevent the 

satisfactory accomplishment of a safety-related function. 

2.3.3.29.2 Staff Evaluation and Conclusion 

The staff reviewed LRA Section 2.3.3.29 and the license renewal boundary drawings using the 

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3 

to determine if the applicant failed to identify any components within the scope of license 

renewal. In addition, the staff’s review determined if the applicant failed to identify any 

components subject to an AMR. The staff found no such omissions. On the basis of its review, 

the staff concludes the applicant has appropriately identified the cranes, hoists and elevators 
 Scoping and Screening Methodology 

 2-79 

group mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the mechanical components 

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

2.3.3.30 Miscellaneous Auxiliary Systems In-Scope ONLY for Criterion 10 CFR 54.4(a)(2) 

2.3.3.30.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.30 describes those nonsafety-related auxiliary systems or nonsafety-related 

portions of auxiliary systems with the potential for adverse spatial interaction with safety-related 

systems or components. The applicant identified the following auxiliary systems in the LRA as 

within the scope of license renewal based only on the criterion of 10 CFR 54.4(a)(2): 

Auxiliary Steam. The auxiliary steam system consists of an auxiliary boiler, transfer pumps, 

receivers, tanks, piping, and valves, and provides a source of steam for various 

nonsafety-related functions during plant startup, shutdown, normal operations, and testing 

evolutions. 

Chemical Waste. The chemical waste system consists of the following five sub-systems: 

(1) the radioactive chemical waste sub-system that collects the corrosive radioactive waste from 

the chemical laboratory and decontamination stations; (2) the cooling water waste sub-system 

that collects the chemically treated cooling water from the auxiliary and radwaste buildings for 

reuse or disposal; (3) the condensate polisher regeneration waste sub-system that collects the 

rinse washes from the condensate polisher demineralizers and neutralizes the waste for 

disposal; (4) the spent regenerate waste sub-system that collects and neutralizes the rinse 

washes from the makeup demineralizers for disposal; and (5) the yard areas chemical tank 

drains sub-system. 

Liquid Radwaste. The liquid radwaste system collects, processes, monitors, and recycles or 

disposes of liquid radwaste. The liquid radwaste system consists of instrumentation and 

process components such as piping, filters, pumps, tanks, and an evaporator. 

Oily Waste and Non-Radioactive Waste. The oily waste and non-radioactive waste system 

collects and transports liquid waste from equipment and floor drains of the turbine building, the 

control building, the diesel generator buildings, the fire pump house, and the yard area. The 

system removes entrained oil from the wastewater for disposal and conveys the oil-free water to 

the evaporation pond. 

Solid Radwaste. The solid radwaste system consists of the following four subsystems: 

(1) spent resin transfer subsystem, (2) wet waste processing subsystem, (3) dry waste disposal 

subsystem, and (4) the filter handling and disposal subsystem. The system, comprised of 

piping, valves, tanks and pumps, provides processing and packaging capability for concentrated 

waste solutions and spent resins. 

Sanitary Sewage and Treatment. The sanitary sewage and treatment system collects the 

sanitary wastewater from facilities throughout the plant through drain piping and transports it 

through one wet well, one sewage lift station, and one surge tank to the three package sewage 

treatment units, where the waste is treated and clarified. 

Secondary Chemical Control. The secondary chemical control system is an integrated system 

that operates concurrently to maintain the required operating water chemistry of the condensate 

and feedwater under all normal operating and upset or abnormal conditions. It is comprised of 

the following four subsystems: (1) the condensate demineralizer subsystem that maintains 

required water chemistry of the condensate and feedwater loop during upset or abnormal 

conditions; (2) the SG blowdown processing subsystem that compensates for the concentrating 

effect of the SGs by continuous blowdown and processing; (3) the chemical monitoring and 

addition subsystems that establish and maintain the proper chemistry within the condensate, 
Scoping and Screening Methodology 

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feedwater, and SG secondary side water and provide continuous indication of significant 

chemical parameters in the secondary system; and (4) the online process sampling subsystem 

that takes continuous samples from the main condenser, condensate demineralizers, main 

feedwater lines, SG blowdown lines and downcomer, and circulating water lines. 

LRA Table 2.3.3-30 identifies the components subject to an AMR for the miscellaneous systems 

within the scope of license renewal only for criterion 10 CFR 54.4(a)(2) by component type and 

intended function. The miscellaneous systems described above contain nonsafety-related SCs 

that potentially could prevent the satisfactory accomplishment of a safety-related function. 

Portions of the system (oily waste and non-radioactive waste system) perform functions that 

support fire protection requirements. 

2.3.3.30.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.30, UFSAR Sections 3.6, 9.3.2, 9.3.3, 10.4.6, 11.2.2.3, 

and 11.4, and the license renewal boundary drawings using the evaluation methodology 

described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review 

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 2.3.3.30-1, dated December 3, 2009, the staff noted the license renewal drawing for the 

non-radioactive waste system shows sections of 4-inch lines as not within the scope of license 

renewal. The two lines are connected to lines which are shown within the scope of license 

renewal based on 10 CFR 54.4(a)(2). The staff asked the applicant to justify why the 4-inch 

lines, attached to lines that are within scope for license renewal, are shown as not within the 

scope for license renewal. 

In its response, dated January 18, 2010, the applicant stated that the 4-inch lines are drain lines 

from the fuel oil day tank floors, and they are within the scope of license renewal. The drawing 

was revised to add this piping and associated components within the scope of license renewal 

for 10 CFR 54.4(a)(3). In addition, the applicant revised LRA Table 2.2-1 and Section 2.3.3.30 

to delete the oily waste and non-radioactive waste system due to the addition of the fire 

protection intended functions. Various LRA sections were created to identify that the oily waste 

and non-radioactive waste system also supports fire protection requirements based on the 

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

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.30-1 acceptable 

because the applicant reanalyzed the components in question and found them to be within 

scope for license renewal per 10 CFR 54.4(a)(3), and it revised the LRA accordingly. The staff 

verified the changes by reviewing the revised drawing and LRA sections. Therefore, the staff’s 

concern described in RAI 2.3.3.30-1 is resolved. 

In RAI 2.3.3.30-2, dated December 3, 2009, the staff noted that 4-inch piping lines on the 

license renewal drawing for oily waste and non-radioactive waste system are shown as within 

scope for 10 CFR 54.4(a)(2). Several lines attached to these 4-inch lines, however, are shown 

as not within the scope of license renewal for 10 CFR 54.4(a)(2). The staff asked the applicant 

to provide additional information to justify why the attached lines are not within the scope of 

license renewal. 

In its response, dated January 18, 2010, the applicant stated that all vent and drain lines 

attached to the 4-inch drain lines are within the scope of license renewal in accordance with 

criterion of 10 CFR 54.4(a)(2). The applicant provided a revised drawing. In addition, the 

applicant revised LRA Section 3.3.2.1.31 and LRA Table 3.3.2-31 to add the oily waste and 

non-radioactive system vent lines to the scope of license renewal. This resulted in revisions to 
 Scoping and Screening Methodology 

 2-81 

LRA Table 3.3.2-31 and the addition of a poly-vinyl chloride (PVC) material to the list of oily 

waste and non-radioactive system materials in LRA Section 3.3.2.1.31. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.30-2 acceptable 

because the applicant reanalyzed the components in question and justified the associated 

license renewal boundaries. The staff reviewed the revised drawings and verified the changes. 

Therefore, the staff’s concern described in RAI 2.3.3.30-2 is resolved. 

In RAI 2.3.3.30-3, dated December 3, 2009, the staff noted that a 4-inch piping line on the 

license renewal drawing for oily waste and non-radioactive waste system was shown as not 

within scope for 10 CFR 54.4(a)(2). Several adjacent lines are shown as within the scope of 

license renewal. The staff asked the applicant to provide additional information to justify why 

the attached lines are not within the scope of license renewal. 

In its response, dated January 18, 2010, the applicant stated that highlighting of the continuation 

of the 4-inch pipe line was inadvertently omitted on the license renewal boundary drawing. The 

applicant revised the drawing to show the 4-inch pipe line continuation as highlighted, including 

the 6-inch pipe line where the piping connects to the sump cover. Based on its review, the staff 

finds the applicant’s response to RAI 2.3.3.30-3 acceptable because the applicant 

acknowledged the inadvertent omission of highlighted piping, clarified the license renewal 

boundary, and revised the LRA drawings accordingly. The staff reviewed the revised drawings 

and verified the changes. Therefore, the staff’s concern described in RAI 2.3.3.30-3 is resolved. 

2.3.3.30.3 Conclusion 

The staff reviewed the LRA Section 2.3.3.30; UFSAR Sections 3.6, 9.3.2, 9.3.3, 10.4.6, 

11.2.2.3, and 11.4; RAI responses; and original and revised boundary drawings to determine if 

the applicant failed to identify any components within the scope of license renewal. In addition, 

the staff’s review determined if the applicant failed to identify any components subject to an 

AMR. On the basis of its review, the staff concludes the applicant has appropriately identified 

the miscellaneous auxiliary systems in-scope only for criterion 10 CFR 54.4(a)(2) mechanical 

components within the scope of license renewal, as required by 10 CFR 54.4(a). In addition, 

the staff finds that the applicant has adequately identified the mechanical components subject to 

an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.4 Steam and Power Conversion Systems 

LRA Section 2.3.4 identifies the steam and power conversion systems SCs within the scope of 

license renewal and subject to an AMR. The applicant described the supporting SCs of the 

steam and power conversion systems in the following LRA sections: 

 2.3.4.1, “Main Steam System” 

 2.3.4.2, “Condensate Storage and Transfer System” 

 2.3.4.3, “Auxiliary Feedwater System” 

 2.3.4.4, “Condensate System” 

 2.3.4.5, “Feedwater System” 

 2.3.4.6, “Main turbine System” 

 2.3.4.7, “SG Feedwater Pump Turbine System” 

 2.3.4.8, “Feedwater Heater Extraction, Drains and Vents System” 

2.3.4.1 Main Steam System 

2.3.4.1.1 Summary of Technical Information in the Application 

LRA Section 2.3.4.1 describes the main steam system, which is comprised of the main steam 

supply system, turbine bypass system, portions of the feedwater system, and portions of the SG 

blowdown system. The main steam system delivers steam from the SGs to the high-pressure 
Scoping and Screening Methodology 

 2-82 

turbine for a range of operating conditions. Each main steam line contains a 

pneumatically-operated atmospheric dump valve, five spring-loaded safety valves, one main 

steam isolation valve, a cross-tie header, and associated vent and drain valves. The turbine 

bypass system contains eight air-operated valves and has the capability to remove the heat 

from the SGs to minimize transient effects on the RCS during startup, hot shutdown, cooldown, 

and load rejection. 

LRA Table 2.3.4-1 identifies the components subject to an AMR for the main steam system by 

component type and intended function. The main steam system contains safety-related 

components relied upon to remain functional during and following DBEs. The failure of portions 

of the nonsafety-related SSCs in the system potentially could prevent the satisfactory 

accomplishment of a safety-related function. In addition, portions of the system perform 

functions that support fire protection, EQ, SBO, and ATWS requirements. 

2.3.4.1.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.4.1; UFSAR Sections 10.3, 10.4.4, 10.4.7, and 10.4.9; and 

the license renewal boundary drawings using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review 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 2.3.4.1-1, dated December 3, 2009, the staff noted license renewal drawings show 

several locations where the license renewal spatial interaction termination cannot be determined 

(listed below). The staff asked the applicant to provide additional information to locate the 

license renewal spatial interaction terminations. 

Drawing LR-PVNGS-SG-01-M-SGP-002: 

Piping N-007-DCDA-8′′ upstream of valve UV-172 (G-13) 

Piping N-010-DBDB-8′′ upstream of valve UV-175 (C-13) 

Piping E-039-DABA-6′′ downstream of valve UV-5000 (E-2) 

Piping E-048-DABA-6′′ downstream of valve UV-5008 (B-2) 

Drawing LR-PVNGS-SG-01-M-SGP-001-02: 

Piping N-335-HDDA-1′′ upstream of valve V346 (G-4) 

Piping N-335-HDDA-1′′ upstream of valve V348 (G-4) 

Piping N-321-HDDA-1′′ upstream of valve V358 (D-4) 

Piping N-321-HDDA-1′′ upstream of valve V357 (D-4) 

In its response, dated January 18, 2010, the applicant provided additional information for each 

of the locations described above and submitted a revised license renewal boundary drawing to 

clarify the spatial interaction terminations. Based on its review, the staff finds the applicant’s 

response to RAI 2.3.4.1-1 acceptable because it clarified the spatial interaction terminations. 

The staff reviewed the revised drawing and verified the spatial interaction terminations. 

Therefore, the staff’s concern described in RAI 2.3.4.1-1 is resolved. 

In RAI 2.3.4.1-2, dated December 3, 2009, the staff noted license renewal drawing 

LR-PVNGS-SG-01-M-SGP-002 (D-8 and G-8) shows two flow nozzles out of each of the SGs 

as not within the scope of license renewal. The staff asked the applicant to provide additional 

information explaining why the flow nozzles out of the SGs are not within the scope of license 

renewal. 

In its response, dated January 18, 2010, the applicant stated the flow nozzles are in scope and 

submitted a revised license renewal boundary drawing. Based on its review, the staff finds the 

applicant’s response to RAI 2.3.4.1-2 acceptable because the applicant stated the flow nozzles 

are within scope. The staff verified the modifications on the revised license renewal boundary 
 Scoping and Screening Methodology 

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drawing and found them acceptable. Therefore, the staff’s concern described in RAI 2.3.4.1-2 

is resolved. 

In RAI 2.3.4.1-3, dated December 3, 2009, the staff noted license renewal drawing 

LR-PVNGS-SG-01-M-SGP-001-01 shows eight boxes on the main steam piping downstream of 

the main steam isolation valves that the applicant did not define (listed below). The staff asked 

the applicant to provide additional information explaining this box symbol and if this component 

type is subject to an AMR. 

 Two boxes on piping E-206-DLBB-28 inches downstream of valve UV-170 (G-9) 

 Two boxes on piping E-207-DLBB-28 inches downstream of valve UV-180 (E-9) 

 Two boxes on piping E-208-DLBB-28 inches downstream of valve UV-171 (D-9) 

 Two boxes on piping E-209-DLBB-28 inches downstream of valve UV-181 (B-9) 

In its response, dated January 18, 2010, the applicant stated the box symbols represent pipe 

whip restraints that are within scope and subject to an AMR. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.4.1-3 acceptable 

because the applicant stated the boxes represent pipe whip restraints and are within scope and 

subject to an AMR. Therefore, the staff’s concern described in RAI 2.3.4.1-3 is resolved. 

In RAI 2.3.4.1-4, dated December 3, 2009, the staff noted license renewal drawing 

LR-PVNGS-SG-01-M-SGP-001-02 (D-8 and G-8) shows two drag resistors N-299-HBDB-54” 

and N-300-HBDB-54” as not within the scope of license renewal. However, the inlet piping 

E-059-DLBB-12” and E-084-DLBB-12” as well as the outlet piping N-306-GBDB-1” and 

N-312-GBDB-1” are within the scope of license renewal. In addition, the applicant showed 

FX-178 and FX-179 as within the scope of license renewal inside of the drag resistors. The 

staff asked the applicant to provide additional information explaining why the drag resistors are 

not within the scope of license renewal. 

In its response, dated January 18, 2010, the applicant stated the pipe shrouds and drag 

resistors have been added to the scope of license renewal for 10 CFR 54.4(a)(2). The applicant 

submitted a revised drawing. Based on its review, the staff finds the applicant’s response to 

RAI 2.3.4.1-4 acceptable because the pipe shrouds and drag resistors to the scope of license 

renewal. The staff reviewed revised drawing LR-PVNGS-SG-01-M-SGP-001-02 and verified 

that the drawing shows the pipe shroud and drag resistors as within scope of license renewal. 

Therefore, the staff’s concern described in RAI 2.3.4.1-4 is resolved. 

2.3.4.1.3 Conclusion 

The staff reviewed LRA Section 2.3.4.1; UFSAR Sections 10.3, 10.4.4, 10.4.7, and 10.4.9; RAI 

responses; and original and revised boundary drawings to determine if the applicant failed to 

identify any components within the scope of license renewal. In addition, the staff’s review 

determined if the applicant failed to identify any components subject to an AMR. On the basis 

of its review, the staff concludes the applicant has appropriately identified the main steam 

system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the mechanical components 

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

2.3.4.2 Condensate Storage and Transfer System 

2.3.4.2.1 Summary of Technical Information in the Application 

LRA Section 2.3.4.2 describes the condensate storage and transfer system, which is comprised 

of one CST, two condensate transfer pumps, and associated piping, valves, and I&Cs. The 

condensate storage and transfer system provides the source of feedwater for the auxiliary 

feedwater system for reactor decay heat removal during hot standby conditions and for cooling 

the reactor. The system also maintains feedwater inventory in the secondary system during 
Scoping and Screening Methodology 

 2-84 

startup, shutdown, hot standby, and normal power operations. The condensate storage and 

transfer system also provides makeup water for the essential cooling water system, essential 

chilled water system, diesel generator system, and the spent fuel pool. 

LRA Table 2.3.4-2 identifies the components subject to an AMR for the condensate storage and 

transfer system by component type and intended function. The condensate storage and 

transfer system contains safety-related components relied upon to remain functional during and 

following DBEs. The failure of portions of the nonsafety-related SSCs in the system potentially 

could prevent the satisfactory accomplishment of a safety-related function. In addition, portions 

of the system perform functions that support fire protection and SBO requirements. 

2.3.4.2.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.4.2, UFSAR Sections 3.8.4.1.7 and 9.2.6, and the license 

renewal boundary drawings using the evaluation methodology described in SER Section 2.3 

and the guidance in SRP-LR Section 2.3. The staff’s review 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 2.3.4.2-1, dated December 3, 2009, the staff noted license renewal drawing 

LR-PVNGS-CT-01-M-CTP-001 (C-2) shows line N-031-HCDA-3” as not within the scope of 

license renewal for 10 CFR 54.4(a)(2). However, the continuation of this 3-inch line on drawing 

LR-PVNGS-PC-01-M-PCP-001 (H-11) shows this line is within the scope of license renewal for 

10 CFR 54.4(a)(2). The staff asked the applicant to provide additional information explaining 

why there is a difference in the scope classification between the drawing 

LR-PVNGS-CT-01-M-CTP-001 and the continuation drawing. 

In its response, dated January 18, 2010, the applicant stated that it inadvertently omitted 

highlighting of the continuation of pipe line N-031-HCDA-3”. The applicant revised the drawing 

to show the pipe line N-031-HCDA-3” continuation as within the scope of license renewal. The 

revised drawing was provided to the staff. Based on its review, the staff finds the applicant’s 

response to RAI 2.3.4.2-1 acceptable because it corrected the drawing continuation 

discrepancy. The staff reviewed the revised drawing and verified the continuation of the line is 

highlighted as within scope for license renewal. Therefore, the staff’s concern described in 

RAI 2.3.4.2-1 is resolved. 

2.3.4.2.3 Conclusion 

The staff reviewed LRA Section 2.3.4.2, UFSAR Sections 3.8.4.1.7 and 9.2.6, RAI response, 

and original and revised boundary drawings to determine if the applicant failed to identify any 

components within the scope of license renewal. In addition, the staff’s review determined if the 

applicant failed to identify any components subject to an AMR. On the basis of its review, the 

staff concludes the applicant has appropriately identified the condensate storage and transfer 

system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a). The staff also finds that the applicant has adequately identified the mechanical 

components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.3.4.3 Auxiliary Feedwater System 

2.3.4.3.1 Summary of Technical Information in the Application 

LRA Section 2.3.4.3 describes the auxiliary feedwater system, which is comprised of two 

motor-driven pumps, one turbine-driven pump, and associated piping and valves. The auxiliary 

feedwater system supplies feedwater from the CST to the SGs during fill, startup, hot standby, 

normal shutdown, and emergency conditions. 
 Scoping and Screening Methodology 

 2-85 

LRA Table 2.3.4-3 identifies the components subject to an AMR for the auxiliary feedwater 

system by component type and intended function. The auxiliary feedwater system contains 

safety-related components relied upon to remain functional during and following DBEs. The 

failure of portions of the nonsafety-related SSCs in the system potentially could prevent the 

satisfactory accomplishment of a safety-related function. In addition, portions of the system 

perform functions that support fire protection, EQ, SBO, and ATWS requirements. 

2.3.4.3.2 Staff Evaluation and Conclusion 

The staff reviewed LRA Section 2.3.4.3; UFSAR Sections 7.3.5, 9.2.6, and 10.4.9; and the 

license renewal boundary drawings to determine if the applicant failed to identify any 

components within the scope of license renewal. In addition, the staff’s review determined if the 

applicant failed to identify any components subject to an AMR. The staff found no such 

omissions. On the basis of its review, the staff concludes the applicant has appropriately 

identified the auxiliary feedwater system mechanical components within the scope of license 

renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the 

mechanical components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.3.4.4 Condensate System 

2.3.4.4.1 Summary of Technical Information in the Application 

LRA Section 2.3.4.4 describes the condensate system, which is comprised of the main 

condenser, condenser hotwell, condensate pumps, and associated piping and valves. The 

condensate system collects condensate from the exhaust steam of the main turbines, feedwater 

pump turbines, and steam cycle drains in the main condenser hotwell and delivers de-aerated 

water to the suction of the main feedwater pumps. 

LRA Table 2.3.4-4 identifies the components subject to an AMR for the condensate system by 

component type and intended function. The condensate system does not contain safety-related 

components relied upon to remain functional during and following DBEs. Portions of the system 

perform functions that support fire protection requirements. The function to meet these 

requirements is performed by electrical components; therefore, there are no mechanical 

components in the condensate system requiring an AMR. 

2.3.4.4.2 Staff Evaluation and Conclusion 

The staff reviewed LRA Section 2.3.4.4, UFSAR Sections 10.4.1 and 10.4.7, and applicable 

boundary drawings to determine if the applicant failed to identify any components within the 

scope of license renewal. In addition, the staff’s review determined if the applicant failed to 

identify any components subject to an AMR. The staff found no such omissions. On the basis 

of its review, the staff concludes that the applicant has appropriately identified the condensate 

system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the mechanical system 

components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.3.4.5 Feedwater System 

2.3.4.5.1 Summary of Technical Information in the Application 

LRA Section 2.3.4.5 describes the feedwater system, which is comprised of two interconnected 

trains with turbine-driven feedwater pumps, three stages of high-pressure feedwater heaters, 

and associated piping, valves, and components. The feedwater system receives condensate 

from the condensate system and delivers feedwater, at required pressure and temperature, to 

the SGs. 
Scoping and Screening Methodology 

 2-86 

LRA Table 2.3.4-5 identifies the components subject to an AMR for the feedwater system by 

component type and intended function. The feedwater system does not contain safety-related 

components relied upon to remain functional during and following DBEs. Portions of the system 

perform functions that support fire protection requirements. The function to meet these 

requirements is performed by electrical components; therefore, there are no mechanical 

components in the feedwater system requiring an AMR. 

2.3.4.5.2 Staff Evaluation and Conclusion 

The staff reviewed LRA Section 2.3.4.5, UFSAR Section 10.4.7, and applicable boundary 

drawings to determine if the applicant failed to identify any components within the scope of 

license renewal. In addition, the staff’s review determined if the applicant failed to identify any 

components subject to an AMR. The staff found no such omissions. On the basis of its review, 

the staff concludes the applicant has appropriately identified the feedwater system mechanical 

components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the 

applicant has adequately identified the mechanical components subject to an AMR in 

accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.4.6 Main Turbine System 

2.3.4.6.1 Summary of Technical Information in the Application 

LRA Section 2.3.4.6 describes the main turbine system, which is comprised of one double-flow 

high-pressure turbine, three double-flow low-pressure turbines, four moisture 

separator-re-heaters, and the associated piping, valves, and instrumentation. The purpose of 

the main turbine system is to convert steam from the main steam system to mechanical energy 

to drive the main generator. In addition, the system supplies extraction steam for feedwater 

heating and hot reheat steam for the main feedwater pump turbines. 

LRA Table 2.3.4-6 identifies the components subject to an AMR for the main turbine system by 

component type and intended function. The main turbine system does not contain 

safety-related components relied upon to remain functional during and following DBEs. Portions 

of the system perform functions that support ATWS requirements. The function to meet these 

requirements is performed by electrical components; therefore, there are no mechanical 

components in the main turbine system requiring an AMR. 

2.3.4.6.2 Staff Evaluation and Conclusion 

The staff reviewed LRA Section 2.3.4.6, UFSAR Section 10.2, and applicable boundary 

drawings to determine if the applicant failed to identify any components within the scope of 

license renewal. In addition, the staff’s review determined if the applicant failed to identify any 

components subject to an AMR. The staff found no such omissions. On the basis of its review, 

the staff concludes the applicant has appropriately identified the main turbine system 

mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), 

and that the applicant has adequately identified the mechanical components subject to an AMR 

in accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.4.7 Steam Generator Feedwater Pump Turbine System 

2.3.4.7.1 Summary of Technical Information in the Application 

LRA Section 2.3.4.7 describes the SG feedwater pump turbine system, which is comprised of 

pump turbines, hydraulic actuator systems, and associated piping systems. The SG feedwater 

pump turbines provide the motive force to drive the SG turbine-driven feedwater pumps. 

LRA Table 2.3.4-7 identifies the components subject to an AMR for the SG feedwater turbine 

system by component type and intended function. The SG feedwater turbine system does not 

contain safety-related components relied upon to remain functional during and following DBEs. 
 Scoping and Screening Methodology 

 2-87 

Portions of the system perform functions that support fire protection requirements. The function 

to meet these requirements is performed by electrical components and active portions of the 

main feedwater pump turbine stop valves. No passive mechanical components are relied upon 

to perform this function. Therefore, there are no mechanical components in the SG feedwater 

turbine system requiring an AMR. 

2.3.4.7.2 Staff Evaluation and Conclusion 

The staff reviewed LRA Section 2.3.4.7, UFSAR Section 10.4.7, and applicable boundary 

drawings to determine if the applicant failed to identify any components within the scope of 

license renewal. In addition, the staff’s review determined if the applicant failed to identify any 

components subject to an AMR. The staff found no such omissions. On the basis of its review, 

the staff concludes the applicant has appropriately identified the SG feedwater pump turbine 

system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a). The staff also finds that the applicant has adequately identified the mechanical 

components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.3.4.8 Feedwater Heater Extraction, Drains, and Vents System 

2.3.4.8.1 Summary of Technical Information in the Application 

LRA Section 2.3.4.8 describes the feedwater heater extraction, drains, and vents system, which 

is comprised of three trains of four-stage low-pressure heaters, two trains of three-stage 

high-pressure heaters, and associated piping, drains, and vents. The feedwater heater 

extraction, drains, and vents system supplies preheated feedwater to the SGs to improve cycle 

efficiency and minimize thermal stress on the feedwater piping and SG feedwater nozzles. 

LRA Table 2.3.4-8 identifies the components subject to an AMR for the feedwater heater 

extraction, drains, and vents system by component type and intended function. The feedwater 

heater extraction, drains, and vents system does not contain safety-related components relied 

upon to remain functional during and following DBEs. Portions of the system perform functions 

that support fire protection requirements. The function to meet these requirements is performed 

by electrical components; therefore, there are no mechanical components in the feedwater 

heater extraction, drains, and vents system requiring an AMR. 

2.3.4.8.2 Staff Evaluation and Conclusion 

The staff reviewed LRA Section 2.3.4.8, UFSAR Sections 10.2.2 and 10.4.7, and applicable 

boundary drawings to determine if the applicant failed to identify any components within the 

scope of license renewal. In addition, the staff’s review determined if the applicant failed to 

identify any components subject to an AMR. The staff found no such omissions. On the basis 

of its review, the staff concludes the applicant has appropriately identified the feedwater heater 

extraction, drains, and vents system mechanical components within the scope of license 

renewal, as required by 10 CFR 54.4(a). In addition, the staff finds that the applicant has 

adequately identified the mechanical components subject to an AMR in accordance with the 

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

2.4 Scoping and Screening Results: Structures

This section documents the staff’s review of the applicant’s scoping and screening results for 

structures. Specifically, this section discusses the following structures: 

 2.4.1, “Containment Building” 

 2.4.2, “Control Building” 

 2.4.3, “Diesel Generator Building” 
Scoping and Screening Methodology 

 2-88 

 2.4.4, “Turbine Building” 

 2.4.5, “Auxiliary Building” 

 2.4.6, “Radwaste Building” 

 2.4.7, “Main Steam Support Structure” 

 2.4.8, “Station Blackout Generator Structures” 

 2.4.9, “Fuel Building” 

 2.4.10, “Spray Pond and Associated Water Control Structures” 

 2.4.11, “Tank Foundations and Shells” 

 2.4.12, “Transformer Foundations and Electrical Structures” 

 2.4.13, “Yard Structures (In-scope)” 

 2.4.14, “Supports” 

 2.4.15, “Fire Barriers” 

In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant listed passive, 

long-lived SCs 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. The staff confirmed that there were no omissions of structural 

components that meet the scoping criteria and are subject to an AMR. 

The staff evaluated the information provided in the LRA in the same manner for all structures. 

The objective of the review was to determine if the structural components that appeared to meet 

the scoping criteria specified in 10 CFR 54.4 were identified by the applicant as within the scope 

of license renewal, in accordance with 10 CFR 54.4. Similarly, the staff evaluated the 

applicant’s screening results to verify that all long-lived, passive SCs were subject to an AMR in 

accordance with 10 CFR 54.21(a)(1). 

To perform its evaluation, the staff reviewed the applicable LRA sections, focusing its review on 

SCs 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 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 licensing basis documents to 

determine if the applicant specified all intended functions delineated under 10 CFR 54.4(a) in 

the LRA. If the staff found omissions, it requested additional information to resolve the 

discrepancies. 

Once the staff completed its review of the scoping results, the staff evaluated the applicant’s 

screening results. For those SCs with intended functions, the staff sought to determine if the 

functions are performed with moving parts or a change in configuration or properties or if they 

are subject to replacement based on a qualified life or specified time period, as described in 

10 CFR 54.21(a)(1). For those that did not meet either of these criteria, the staff sought to 

confirm that these structural components were subject to an AMR as required by 

10 CFR 54.21(a)(1). If the staff found discrepancies, it requested additional information to 

resolve them. 

2.4.1 Containment Building 

2.4.1.1 Summary of Technical Information in the Application 

In LRA Section 2.4.1, the applicant stated that the containment building is a seismic Category I 

structure. The shell of the building is a pre-stressed, reinforced concrete, cylindrical structure 

with a hemispherical dome roof. The applicant also stated that the containment building 

foundation is a conventionally reinforced concrete mat, circular in plan, constructed separately 

from other structures. The applicant further stated that the interior of the containment building 

shell is lined with carbon steel plates welded together to form a barrier which is essentially leak 
 Scoping and Screening Methodology 

 2-89 

tight. The liner is thickened locally around the penetrations, large brackets, and major 

attachments that transfer loads through the liner plate to the concrete structure. Attachments to 

the shell wall are brackets for support of the polar crane, electrical conduit and cable tray, spray 

piping, lighting, and ventilation. The major structural components of the containment building 

are as follows: 

 Post-tensioning system 

 Steel liner plate 

 Penetrations 

 Containment building internal structures 

 Emergency sumps 

LRA Table 2.4-1 identifies the components subject to an AMR for the containment building by 

component type and intended function. 

2.4.1.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.1 using the evaluation methodology described in 

SER Section 2.4 and the guidance in SRP-LR Section 2.4. During its review of the LRA 

Section 2.4.1, the staff identified areas in which additional information was necessary to 

complete the evaluation of the applicant’s scoping and screening results for the containment 

building. 

In RAI 2.4.1-1, dated November 2, 2009, the staff requested that the applicant provide 

additional information to confirm that the hatches and plug, caulking, and sealant are to be 

included in the scope of license renewal and subject to an AMR or to justify their exclusion. 

In its response to the RAI, dated December 17, 2009, the applicant stated that the containment 

access hatches and associated components are identified as component types 

“hatch-emergency airlock,” “hatch-equipment,” and “hatch-personnel airlock” in LRA 

Table 2.4-1. Component type “hatch-equipment” includes the concrete missile barrier for the 

equipment hatch. The applicant also stated that it noted these components as within the scope 

of license renewal and subject to an AMR. The applicant further stated that the seals in the 

containment building are identified as component types “compressible joints and seals” or “fire 

barrier seals” in LRA Table 2.4-1. LRA Table 2.4-1 lists these components as components 

within the scope of license renewal and subject to an AMR. 

Based on its review, the staff finds the response to RAI 2.4.1-1 acceptable because the hatches 

and plug, caulking, and sealant, as described by the applicant, do perform a 10 CFR 54.4(a) 

intended function for license renewal and are subject to an AMR. The staff’s concern described 

in RAI 2.4.1-1 is resolved. 

2.4.1.3 Conclusion 

The staff reviewed LRA Section 2.4.1; UFSAR Sections 2.5.4.5, 3.8.1, 6.2.2, 6.2.6.2 and 

Appendix 9B.2.11; RAI response; and applicable boundary drawings to determine if the 

applicant failed to identify any components within the scope of license renewal. In addition, the 

staff’s review determined if the applicant failed to identify any components subject to an AMR. 

The staff found no such omissions. On the basis of its review, the staff concludes the applicant 

has appropriately identified the containment building structural components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 

the structural components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 
Scoping and Screening Methodology 

 2-90 

2.4.2 Control Building 

2.4.2.1 Summary of Technical Information in the Application 

In LRA Section 2.4.2, the applicant stated that the control building is a safety-related, seismic 

Category I structure that provides support, shelter, and protection to ESF and nuclear auxiliary 

systems. The applicant also stated that the control building is within the scope of license 

renewal based on the criteria of 10 CFR 54.4(a)(1). The applicant further stated that the control 

building shelters and protects nonsafety-related SSCs whose failure could prevent performance 

of a safety-related function. Therefore, it is within the scope of license renewal based on the 

criterion of 10 CFR 54.4(a)(2). The applicant further stated that the portions of the control and 

corridor buildings support fire protection, ATWS, and SBO requirements based on the criteria of 

10 CFR 54.4(a)(3). 

LRA Table 2.4-2 lists the components subject to an AMR for the control building by component 

type and intended function. 

2.4.2.2 Staff Evaluation and Conclusion 

The staff reviewed LRA Section 2.4.2; UFSAR Sections 2.5.4.8.1, 3.8.4.1.3, and 3.8.4; and 

applicable boundary drawings to determine if the applicant failed to identify any components 

within the scope of license renewal. In addition, the staff’s review determined if the applicant 

failed to identify any components subject to an AMR. The staff found no such omissions. On 

the basis of its review, the staff concludes the applicant has appropriately identified the control 

building structural components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the structural components 

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

2.4.3 Diesel Generator Building 

2.4.3.1 Summary of Technical Information in the Application 

In LRA Section 2.4.3, the applicant stated that the diesel generator building is a seismic 

Category I, multi-story, box-type, structural steel and reinforced concrete structure, which 

houses the EDGs, fuel oil day tanks, exhaust silencers, and exhaust stacks. The applicant 

stated that the diesel generator building provides structural support and protection of 

components relied upon to perform a safe shutdown and maintain the plant in a safe shutdown 

condition; therefore, it is with the scope of license renewal based on the criteria of 

10 CFR 54.4(a)(1). The applicant also stated that the diesel generator building shelters and 

protects nonsafety-related SSCs whose failure could prevent performance of a safety-related 

function. Therefore, it is within the scope of license renewal based on the criteria of 

10 CFR 54.4(a)(2). The applicant further stated that the portions of the diesel generator building 

support SBO requirements and provide support, shelter, and protection for components 

necessary to demonstrate compliance with fire protection requirements. The diesel generator 

building is within the scope of license renewal based on the criteria of 10 CFR 54.4(a)(3). 

LRA Table 2.4-3 identifies the components subject to an AMR for the diesel generator building 

by component type and intended function. 

2.4.3.2 Staff Evaluation and Conclusion 

The staff reviewed LRA Section 2.4.3.2, UFSAR Section 3.8.4.1.4 and Appendix 9B2.4, and 

applicable boundary drawings to determine if the applicant failed to identify any components 

within the scope of license renewal. In addition, the staff’s review determined if the applicant 

failed to identify any components subject to an AMR. The staff found no such omissions. On 

the basis of its review, the staff concludes the applicant has appropriately identified the diesel 

generator building structural components within the scope of license renewal, as required by 
 Scoping and Screening Methodology 

 2-91 

10 CFR 54.4(a), and that the applicant has adequately identified the structural components 

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

2.4.4 Turbine Building 

2.4.4.1 Summary of Technical Information in the Application 

In LRA Section 2.4.4, the applicant stated that the turbine building is a seismic Category II 

structure, whose behavior was analyzed under the extreme environmental loads (e.g., tornado, 

safe-shutdown earthquake) to verify that a collapse would not occur. The applicant also stated 

that the turbine building is within the scope of license renewal based on the criteria of 

10 CFR 54.4(a)(2). The applicant further stated that the turbine building physically supports and 

protects systems and components that are required for fire protection and SBO based on the 

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

LRA Table 2.4-4 identifies the components subject to an AMR for the turbine building by 

component type and intended function. 

2.4.4.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.4 and UFSAR Sections 3.3.2.3, 3.8.4.4, and 

Appendix 9B.2.20.1 using the evaluation methodology described in SER Section 2.4 and the 

guidance in SRP-LR Section 2.4. 

During its review of the LRA Section 2.4.4, the staff identified areas in which additional 

information was necessary to complete the evaluation of the applicant’s scoping and screening 

results for the turbine building. 

In RAI 2.4.4-1, dated November 2, 2009, the staff requested that the applicant provide 

additional information to confirm the inclusion or justify the exclusion of the compressible joints 

and seals, since it is not clear if it was included in the LRA Table 2.4-4 as being within the scope 

of license renewal and subsequently evaluated for an AMR. 

In its response to the RAI, dated December 17, 2009, the applicant stated that the structural 

seals in the turbine building are identified as component types “fire barrier seals” or “roofing 

membrane” in LRA Table 2.4-4. The applicant stated that these components are identified as 

within the scope of license renewal and subject to an AMR. 

Based on its review, the staff finds the response to RAI 2.4.4-1 acceptable because the 

compressible joints and seals in the turbine building, as described by the applicant, do perform 

a 10 CFR 54.4(a) intended function for license renewal and are subject to an AMR. The staff’s 

concern described in RAI 2.4.4-1 is resolved. 

2.4.4.3 Conclusion 

The staff reviewed LRA Section 2.4.4; UFSAR Sections 3.3.2.3, 3.8.4.4, and 

Appendix 9B.2.20.1; RAI response; and applicable boundary drawings to determine if the 

applicant failed to identify any components within the scope of license renewal. In addition, the 

staff’s review determined if the applicant failed to identify any components subject to an AMR. 

The staff found no such omissions. On the basis of its review, the staff concludes the applicant 

has appropriately identified the turbine building structural components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 

the structural components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 
Scoping and Screening Methodology 

 2-92 

2.4.5 Auxiliary Building 

2.4.5.1 Summary of Technical Information in the Application 

In LRA Section 2.4.5, the applicant stated that the auxiliary building is a multi-story structural 

steel and reinforced concrete seismic Category I structure, housing the safety injection system, 

containment spray system, containment combustible gas control system, CVCS, and 

containment isolation system. The applicant also stated that the auxiliary building provides 

support, shelter, and protection to the ESF and nuclear auxiliary systems. In addition, the 

auxiliary building performs functions that support fire protection and SBO. 

LRA Table 2.4-5 identifies the components subject to an AMR for the auxiliary building by 

component type and intended function. 

2.4.5.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.5 using the evaluation methodology described in 

SER Section 2.4 and the guidance in SRP-LR Section 2.4. 

During its review of the LRA Section 2.4.5, the staff identified areas in which additional 

information was necessary to complete the evaluation of the applicant’s scoping and screening 

results for the auxiliary building. 

In RAI 2.4.5-1, dated November 2, 2009, the staff requested that the applicant provide 

additional information to confirm that the boot seal penetrations are to be included in the scope 

of license renewal and subject to an AMR or to justify their exclusion. 

In its response to the RAI, dated December 17, 2009, the applicant stated that the structural 

seals in the auxiliary building are identified as component types in the LRA as, “roofing 

membrane,” “fire barrier seals,” “compressible joints or seals,” or “caulking or sealant.” The 

component type “caulking or sealant” includes boot seal penetrations. LRA Table 2.4-5 

identifies these components as within the scope of license renewal and subject to an AMR. 

Based on its review, the staff finds the response to RAI 2.4.5-1 acceptable because the boot 

seal penetrations in the auxiliary building, as described by the applicant, do perform a 

10 CFR 54.4(a) intended function for license renewal and are subject to an AMR. The staff’s 

concern described in RAI 2.4.5-1 is resolved. 

2.4.5.3 Conclusion 

The staff reviewed LRA Section 2.4.5, UFSAR Sections 2.5.4.8.1 and 3.8.4.1, RAI response, 

and applicable boundary drawings to determine if the applicant failed to identify any 

components within the scope of license renewal. In addition, the staff’s review determined if the 

applicant failed to identify any components subject to an AMR. The staff found no such 

omissions. On the basis of its review, the staff concludes the applicant has appropriately 

identified the auxiliary building structural components within the scope of license renewal, as 

required by 10 CFR 54.4(a), and that the applicant has adequately identified the structural 

components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.4.6 Radwaste Building 

2.4.6.1 Summary of Technical Information in the Application 

In LRA Section 2.4.6, the applicant stated that the radwaste building is a rectangular, multistory, 

reinforced concrete structure that houses radioactive waste treatment facilities, tanks, filters, 

and other miscellaneous equipment. The applicant also stated that the radwaste building is a 

seismic Category II structure, whose behavior was checked under the extreme environmental 

(e.g., tornado, safe-shutdown earthquake) loads to verify that a collapse would not occur. This 
 Scoping and Screening Methodology 

 2-93 

ensures that external safety-related SSCs would not be damaged by the radwaste building 

during a DBE; therefore, the radwaste building is within the scope of license renewal under the 

criteria of 10 CFR 54.4(a)(2). The applicant also stated that the radwaste building physically 

supports and protects systems and components that are required for fire protection based on 

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

LRA Table 2.4-6 identifies the components subject to an AMR for the radwaste building by 

component type and intended function. 

2.4.6.2 Staff Evaluation and Conclusion 

The staff reviewed LRA Section 2.4.6, UFSAR Sections 3.8.4.4 and Table 9B3-1, and 

applicable boundary drawings to determine if the applicant failed to identify any components 

within the scope of license renewal. In addition, the staff’s review determined if the applicant 

failed to identify any components subject to an AMR. The staff found no such omissions. On 

the basis of its review, the staff concludes the applicant has appropriately identified the 

radwaste building structural components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the structural components 

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

2.4.7 Main Steam Support Structure 

2.4.7.1 Summary of Technical Information in the Application 

In LRA Section 2.4.7, the applicant stated that the MSSS is a box-type reinforced concrete 

seismic Category I structure supported by a reinforced concrete basemat founded on granular 

backfill. It houses the atmospheric dump valves, main steam isolation valves, feedwater 

isolation valves, and essential auxiliary feedwater pumps and their equipment. 

The applicant stated that MSSS is safety-related since it provides support, shelter, and 

protection to ESFs and nuclear auxiliary systems; therefore, it is within the scope of license 

renewal based on the criteria of 10 CFR 54.4(a)(1). The applicant also stated that the MSSS 

shelters and protects nonsafety-related SSCs whose failure could prevent performance of a 

safety-related function; therefore, it is within the scope of license renewal based on the criterion 

of 10 CFR 54.4(a)(2). 

The applicant finally stated that the portions of the MSSS support fire protection and SBO 

requirements based on the criteria of 10 CFR 54.4(a)(3). 

LRA Table 2.4-7 identifies the components subject to an AMR for the MSSS by component type 

and intended function. 

2.4.7.2 Staff Evaluation and Conclusion 

The staff reviewed LRA Section 2.4.7, UFSAR Sections 2.5.4.8.1 and 3.8.4.1.5, and applicable 

boundary drawings to determine if the applicant failed to identify any components within the 

scope of license renewal. In addition, the staff’s review determined if the applicant failed to 

identify any components subject to an AMR. The staff found no such omissions. On the basis 

of its review, the staff concludes the applicant has appropriately identified the MSSS structural 

components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the 

applicant has adequately identified the structural components subject to an AMR in accordance 

with the requirements stated in 10 CFR 54.21(a)(1). 
Scoping and Screening Methodology 

 2-94 

2.4.8 Station Blackout Generator Structures 

2.4.8.1 Summary of Technical Information in the Application 

In LRA Section 2.4.8, the applicant stated that the SBO generator structures consist of the SBO 

generator concrete foundation and the turbine control building, which is a steel structure with 

metal siding and concrete foundation. The applicant also stated that the fuel oil tanks, which 

are located plant north of the SBO generators, are founded directly on compacted backfill and 

there are no structural components that require aging management. The applicant further 

stated that the SBO generator structures are nonsafety-related structures that provide support, 

shelter, and protection for components required to demonstrate compliance with SBO 

requirements based on the criteria of 10 CFR 54.4(a)(3). 

LRA Table 2.4-8 identifies the components subject to an AMR for the SBO generator structures 

by component type and intended function. 

2.4.8.2 Staff Evaluation and Conclusion 

The staff reviewed LRA Section 2.4.8, UFSAR Section 8.3.1.1.10, and applicable boundary 

drawings to determine if the applicant failed to identify any components within the scope of 

license renewal. In addition, the staff’s review determined if the applicant failed to identify any 

components subject to an AMR. The staff found no such omissions. On the basis of its review, 

the staff concludes the applicant has appropriately identified the SBO generator structures 

structural components within the scope of license renewal, as required by 10 CFR 54.4(a), and 

that the applicant has adequately identified the structural components subject to an AMR in 

accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.4.9 Fuel Building 

2.4.9.1 Summary of Technical Information in the Application 

In LRA Section 2.4.9, the applicant stated that the fuel building is a seismic Category I 

rectangular reinforced concrete structure supported on a reinforced concrete base slab, founded 

on granular backfill. The elevated floors and roof are reinforced concrete, supported by 

reinforced concrete bearing walls. The applicant also stated that the fuel building contains the 

spent fuel pool, new fuel storage area, the dry spent fuel storage system loading and transfer 

equipment, the spent fuel pool cooling heat exchangers and pumps, and other miscellaneous 

equipment. 

The applicant further stated that the spent fuel pool, including the transfer canal, cask loading 

pit, and cask wash down area consist of reinforced concrete walls and floors lined with stainless 

steel plates. The applicant also stated that the cask loading pit and cask wash down area gate 

seals are designed as seismic Category I. These seals are designed to remain functional 

during and after accident conditions under the criteria of 10 CFR 54.4(a)(1). The applicant 

stated that the fuel building shelters and protects nonsafety-related SSCs whose failure could 

prevent performance of a safety-related function; therefore, it is within the scope of license 

renewal based on the criterion of 10 CFR 54.4(a)(2). The applicant also stated that portions of 

the fuel building support fire protection requirements based on the criteria of 10 CFR 54(a)(3). 

The fuel transfer canal gate seals are designed as seismic Category II. The applicant further 

stated that during accident conditions, the water elevation would remain above the pool cooling 

system suction piping and more than 10 feet of water coverage would be available to shield the 

spent fuel assemblies. 

LRA Table 2.4-9 identifies the components subject to an AMR for the fuel building by 

component type and intended function. 
 Scoping and Screening Methodology 

 2-95 

2.4.9.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.9 using the evaluation methodology described in 

SER Section 2.4 and the guidance in SRP-LR Section 2.4. 

During its review of the LRA Section 2.4.9, the staff identified areas in which additional 

information was necessary to complete the evaluation of the applicant’s scoping and screening 

results for the fuel building. In RAI 2.4.9-1, dated November 2, 2009, the staff requested that 

the applicant provide additional information to confirm whether the fire barrier coatings and 

wraps are to be included in the scope of license renewal and subject to an AMR or to justify 

their exclusion. 

In its response to the RAI, dated December 17, 2009, the applicant stated that there are no fire 

barrier coatings or wraps within the scope of license renewal and subject to an AMR in the fuel 

building. The UFSAR, Appendix 9B.2, “Fire Hazards Analysis,” describes the fire protection 

evaluation for the fuel building in UFSAR Section 9B.2.6. The applicant indicated that this 

evaluation documents that no fire barrier coatings or wraps are credited for protection of 

structural members or raceways in the fuel building. 

Based on its review, the staff finds the response to RAI 2.4.9-1 acceptable because it states that 

no fire barrier coatings or wraps are credited for protection of structural members or raceways in 

the fuel building. Therefore, the staff’s concern described in RAI 2.4.9-1 is resolved. 

2.4.9.3 Conclusion 

The staff reviewed LRA Section 2.4.9; UFSAR Sections 1.2.12.4, 3.8.4.1.2, and 9.1; the RAI 

response; and applicable boundary drawings to determine if the applicant failed to identify any 

components within the scope of license renewal. In addition, the staff’s review determined if the 

applicant failed to identify any components subject to an AMR. The staff found no such 

omissions. On the basis of its review, the staff concludes the applicant has appropriately 

identified the fuel building structural components within the scope of license renewal, as 

required by 10 CFR 54.4(a), and that the applicant has adequately identified the structural 

components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.4.10 Spray Pond and Associated Water Control Structures 

2.4.10.1 Summary of Technical Information in the Application 

In LRA Section 2.4.10, the applicant stated that the spray pond and associated water control 

structures include two ESPs per unit. Each pond has an intake structure to feed the cooling 

loop and a pond inlet for the return line. The applicant also stated that the ESPs, the pump 

houses, the intake structures, and the sumps are safety-related, seismic Category I, reinforced 

concrete structures, and founded on natural sands. Each pond serves one train of the ESP 

system to provide the ultimate heat sink for cooling auxiliary systems required for safe reactor 

shutdown; therefore, they are within the scope of license renewal based on the criteria of 

10 CFR 54.4(a)(1). The applicant stated that the spray pond and associated water control 

structures shelter and protect nonsafety-related SSCs whose failure could prevent performance 

of a safety-related function; therefore, they are within the scope of license renewal based on the 

criterion of 10 CFR 54.4(a)(2). Finally, the applicant stated that the ESPs, the pump houses, 

and the intake structures provide structural support fire protection and SBO requirements and 

are within the scope of license renewal based on the criteria of 10 CFR 54.4(a)(3). 

LRA Table 2.4-10 identifies the components subject to an AMR for the spray pond and 

associated water control structures by component type and intended function. 
Scoping and Screening Methodology 

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2.4.10.2 Staff Evaluation and Conclusion 

The staff reviewed LRA Section 2.4.10, UFSAR Sections 2.4.11.6 and 3.8.4.1.6, and applicable 

boundary drawings to determine if the applicant failed to identify any components within the 

scope of license renewal. In addition, the staff’s review determined if the applicant failed to 

identify any components subject to an AMR. The staff found no such omissions. On the basis 

of its review, the staff concludes the applicant has appropriately identified the spray pond and 

associated water control structures structural components within the scope of license renewal, 

as required by 10 CFR 54.4(a). In addition, the staff finds that the applicant has adequately 

identified the structural components subject to an AMR in accordance with the requirements 

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

2.4.11 Tank Foundations and Shells 

2.4.11.1 Summary of Technical Information in the Application 

In LRA Section 2.4.11, the applicant stated that the tank foundations and shells are reinforced 

concrete structures that provide structural support for the CST, RWT, RWT valve pit, and 

reactor makeup water tank (RMWT). The CST and RWT are seismic Category I structures and 

have concrete shells, built-up roofs, and stainless steel liners. The applicant stated that the 

RWT is safety-related and supplies the required volume of borated water for safety injection 

following a LOCA; therefore, the tank foundations and shells are within the scope of license 

renewal based on the criteria of 10 CFR 54.4(a)(1). The applicant stated that the tank 

foundations and shells shelter and protect nonsafety-related SSCs whose failure could prevent 

performance of a safety-related function; therefore, they are within the scope of license renewal 

based on the criterion of 10 CFR 54.4(a)(2). The applicant also stated that the CST, RWT, and 

RMWT foundations and shells provide structural support and protection for SSCs required for 

fire protection and SBO; therefore, they are within the scope of license renewal based on the 

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

LRA Table 2.4-11 identifies the components subject to an AMR for the tank foundations and 

shells by component type and intended function. 

2.4.11.2 Staff Evaluation and Conclusion 

The staff reviewed LRA Section 2.4.11; UFSAR Sections 3.5D, 3.8.4.1.7, 3.8.4.1.8 and 

Appendices 9B.2.20.3, 9B.2.20.5, and 9B.2.9.3; and applicable boundary drawings to determine 

if the applicant failed to identify any components within the scope of license renewal. In 

addition, the staff’s review determined if the applicant failed to identify any components subject 

to an AMR. The staff found no such omissions. On the basis of its review, the staff concludes 

the applicant has appropriately identified the tank foundations and shells structural components 

within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has 

adequately identified the structural components subject to an AMR in accordance with the 

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

2.4.12 Transformer Foundations and Electrical Structures 

2.4.12.1 Summary of Technical Information in the Application 

In LRA Section 2.4.12, the applicant stated that reinforced concrete pads, founded on granular 

backfill, support the transformer foundations and electrical structures. The applicant also stated 

that all of the transmission towers to the first breakers in the SRP 500 kV switchyard and the 

towers supporting the transmission lines to the ESF and startup transformers are steel towers 

with reinforced concrete drilled caisson foundations. Electrical cables from the transformers are 

installed in buried concrete duct banks, and manholes are provided along these duct banks for 
 Scoping and Screening Methodology 

 2-97 

cable installation and access. The applicant further stated that the concrete duct banks, and 

manholes provide structural support, shelter, and protection for the electrical cables. 

The applicant stated that the concrete duct banks and the manholes provide shelter and 

protection for SSCs required for SBO recovery and are within the scope of license renewal 

based on the criteria of 10 CFR 54.4(a)(3). Additionally, the applicant stated that the concrete 

fire barrier walls separating the ESF, main, normal, and auxiliary transformers provide spatial 

separation and fire barriers to meet the requirements for fire protection and are, therefore, within 

scope based on the criteria of 10 CFR 54.4(a)(3). 

LRA Table 2.4-12 identifies the components subject to an AMR for the transformer foundations 

and electrical structures by component type and intended function. 

2.4.12.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.12 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. 

During its review of the LRA Section 2.4.12, the staff identified areas in which additional 

information was necessary to complete the evaluation of the applicant’s scoping and screening 

results for the transformer foundations and electrical structures. In RAI 2.4.12-1, dated 

November 2, 2009, the staff requested that the applicant provide additional information to 

confirm that the electrical penetrations are to be included in the scope of license renewal and 

subject to an AMR or to justify their exclusion. 

In its response to the RAI, dated December 17, 2009, the applicant stated that there are no 

electrical penetrations within the scope of license renewal and subject to an AMR in LRA 

Section 2.4.12, “Transformer Foundations and Electrical Structures.” Electrical components that 

connect these structures with other buildings are routed through electrical penetrations that are 

evaluated with those buildings in their respective subsections in LRA Section 2.4. 

Based on its review, the staff finds the response to RAI 2.4.12-1 acceptable because the 

applicant clarified that the components are within the scope of license renewal and are 

evaluated in their respective subsections in LRA Section 2.4. Therefore, the staff’s concern 

described in RAI 2.4.12-1 is resolved. 

2.4.12.3 Conclusion 

The staff reviewed LRA Section 2.4.12, UFSAR Sections 2.5.4.8.1 and Appendix 9B.2.21, the 

RAI response, and applicable boundary drawings to determine if the applicant failed to identify 

any components within the scope of license renewal. In addition, the staff’s review determined 

if the applicant failed to identify any components subject to an AMR. The staff found no such 

omissions. On the basis of its review, the staff concludes the applicant has appropriately 

identified the transformer foundations and electrical structures structural components within the 

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately 

identified the structural components subject to an AMR in accordance with the requirements 

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

2.4.13 Yard Structures (In-Scope) 

2.4.13.1 Summary of Technical Information in the Application 

In LRA Section 2.4.13, the applicant stated that the yard structures (in-scope) consist of the 

condensate and essential pipe tunnels, CST pump house, and the diesel fuel oil tank vault. The 

yard structures are seismic Category I, reinforced concrete structures, which provide structural 

support and shelter and protection for safety-related components. The applicant also stated 

that the condensate and essential pipe tunnels, CST pump house, diesel fuel oil tank vault, and 

fire pump house provide spatial fire barriers and structural support for the fire suppression 
Scoping and Screening Methodology 

 2-98 

components. The applicant further stated that the essential pipe tunnels, condensate tunnel, 

and CST pump house provide shelter and protection for SSCs required for SBO recovery. 

The applicant stated that the condensate and essential pipe tunnels, the CST pump house, and 

the diesel fuel oil tank vault provide structural support and protection for safety-related 

components that they rely on to shutdown the reactor and maintain it in a safe shutdown 

condition. Therefore, these structures are within the scope of license renewal based on the 

criteria of 10 CFR 54.4(a)(1). The applicant also stated that these yard structures shelter and 

protect nonsafety-related SSCs whose failure could prevent performance of a safety-related 

function; therefore, they are within the scope of license renewal based on the criterion of 

10 CFR 54.4(a)(2). The applicant stated that these structures provide spatial fire barriers and 

structural support for fire suppression components and are, therefore, within the scope of 

license renewal based on the criteria of 10 CFR 54.4(a)(3). The LRA states that the essential 

pipe tunnel, the condensate tunnel, and the CST tank pump house provide shelter and 

protection for SSCs required for SBO recovery; therefore, these structures are also within the 

scope of license renewal based on the criteria of 10 CFR 54.4(a)(3). 

LRA Table 2.4-13 identifies the in-scope components subject to an AMR for the yard structures 

by component type and intended function. 

2.4.13.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.13 using the evaluation methodology described in 

SER Section 2.4 and the guidance in SRP-LR Section 2.4. 

During its review of the LRA Section 2.4.13, the staff identified areas in which additional 

information was necessary to complete the evaluation of the applicant’s scoping and screening 

results for the yard structures. In RAI 2.4.13-1, dated November 2, 2009, the staff requested 

that the applicant provide additional information to confirm the “duct banks and manholes” and 

“transmission towers” are to be included in the scope of license renewal and subject to an AMR 

or justify their exclusion. 

In its response to the RAI, dated December 17, 2009, the applicant stated that it evaluated “duct 

banks and manholes” and “transmission towers” in LRA Section 2.4.12, “Transformer 

Foundations and Electrical Structures,” and LRA Table 2.4-12. 

The applicant also stated that, to clarify the LRA, it added the following sentence at the end of 

the “Structure Description,” and just before the “Structure Intended Function,” in Section 2.4.13, 

“Yard Structures (In-scope)”: 

Duct banks and manholes and transmission towers are evaluated in 

Section 2.4.12, Transformer Foundations and Electrical Structures, and 

Table 2.4-12. 

Based on its review, the staff finds the response to RAI 2.4.13-1 acceptable. For clarification, 

the applicant added a sentence, “Duct banks and manholes and transmission towers are 

evaluated in Section 2.4.12, Transformer Foundations and Electrical Structures, and 

Table 2.4-12.” Therefore, the staff’s concern described in RAI 2.4.13-1 is resolved. 

2.4.13.3 Conclusion 

The staff reviewed LRA Section 2.4.13; UFSAR Appendix 9B and Tables 3.5-9, 9.5.2, and 

9B.3-1; the RAI response; and applicable boundary drawings to determine if the applicant failed 

to identify any components within the scope of license renewal. In addition, the staff’s review 

determined if the applicant failed to identify any components subject to an AMR. The staff found 

no such omissions. On the basis of its review, the staff concludes the applicant has 

appropriately identified yard structures structural components within the scope of license 

renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the 
 Scoping and Screening Methodology 

 2-99 

structural components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.4.14 Supports 

2.4.14.1 Summary of Technical Information in the Application 

In LRA Section 2.4.14, the applicant stated that the supports are within the scope of license 

renewal because they support and protect components within the scope of license renewal. 

Supports are integral parts of all systems, and many of these supports are not uniquely 

identified with component identification numbers. However, the applicant stated that support 

characteristics such as design, materials of construction, environments, and anticipated 

stressors are similar. Therefore, the applicant evaluated structural supports for mechanical and 

electrical components as commodities across system boundaries. 

The applicant’s commodity evaluation applies to structural supports for structures within the 

scope of license renewal. The applicant addressed the following structural supports for 

mechanical components in the LRA: supports for American Society of Mechanical Engineers 

(ASME) Class 1 piping and components; supports for ASME Class 2 and Class 3 piping and 

components; and supports for HVAC ducts, tube track, instrument tubing, instruments, and 

non-ASME piping and components. The applicant stated that the LRA addressed the following 

electrical components and supports: cable trays and supports, conduit and supports, and 

electrical panels and enclosures. The applicant further stated that the ASME Class 1 piping and 

component commodity group includes the supports for the following RCS components: reactor 

vessel, pressurizer, SG, and RCP. 

The applicant also stated that supports are safety-related components relied upon to remain 

functional during and following DBEs and are, therefore, within the scope of license renewal 

under the criteria of 10 CFR 54.4(a)(1). The failure of nonsafety-related SSCs in the supports 

could prevent the satisfactory accomplishment of a safety-related function and are, therefore, 

within the scope of license renewal under the criteria of 10 CFR 54.4(a)(2). In addition, the 

supports perform functions that support fire protection, PTS, and SBO and are, therefore, within 

the scope of license renewal under the criteria of 10 CFR 54.4(a)(3). 

LRA Table 2.4-14 identifies the components subject to an AMR for the supports by component 

type and intended function. 

2.4.14.2 Staff Evaluation and Conclusion 

The staff reviewed LRA Section 2.4.14, UFSAR Sections 3.8.3.1 and 5.4.14, and applicable 

boundary drawings to determine if the applicant failed to identify any components within the 

scope of license renewal. In addition, the staff’s review determined whether the applicant failed 

to identify any components subject to an AMR. The staff found no such omissions. On the 

basis of its review, the staff concludes the applicant has appropriately identified supports 

components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the 

applicant has adequately identified the structural components subject to an AMR in accordance 

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

2.4.15 Fire Barriers 

2.4.15.1 Summary of Technical Information in the Application 

The tables in LRA Section 2.4 show the function of “fire barriers” for one of the component types 

that are credited as part of the fire protection system. For example, LRA Tables 2.4-1 through 

2.4-9 and Table 2.4-13 list the fire barrier function for concrete block (masonry walls), concrete 

elements, fire barrier coatings and wraps, fire barrier doors, and fire barrier seals. Therefore, 

fire barrier elements are within the scope of license renewal and subject to an AMR. 
Scoping and Screening Methodology 

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LRA Table 2.1-1 identifies the intended function for the fire barriers and states that the rated fire 

barriers confine or retard a fire from spreading to or from adjacent areas of the plant. According 

to the LRA, fire barriers have an intended function under 10 CFR 50.54(a)(1) and 

10 CFR 50.54(a)(3). 

2.4.15.2 Staff Evaluation 

The staff reviewed the LRA Section 2.4 (fire barrier portion only), UFSAR, and license renewal 

drawings using the evaluation methodology described in the SER Section 2.4 and guidance in 

SRP-LR, Section 2.4. During its review, the staff evaluated the system functions described in 

the LRA and UFSAR to verify that the applicant had not omitted from the scope of license 

renewal any components with intended functions under 10 CFR 54.4(a). The staff then 

reviewed those components that the applicant identified as within the scope of license renewal 

to verify that the applicant had not omitted any passive or long-lived components subject to an 

AMR in accordance with 10 CFR 54.21(a)(1). 

The staff also reviewed the fire protection CLB documents listed in the Operating License, 

(license conditions 2.C(7), 2.C(6), and 2.F) and NUREG-0857, “Safety Evaluation Report 

related to the operation of Nuclear Generating Station Units 1, 2 and 3,” dated November 1981 

through Supplement 11. 

This review of the fire protection CLB documents included applicant commitments to 

10 CFR 50.48, “Fire protection” (i.e., approved fire protection program), as provided in the 

responses to Appendix A to BTP APCSB 9.5-1, “Guidelines for Fire Protection for Nuclear 

Power Plants,” and Appendix A to the BTP APS 9.5-1, documented in PVNGS Units 1, 2, and 3 

SERs and NUREG-0857, dated November 1981 through Supplement 11. 

During its review of LRA Section 2.4, the staff identified areas in which additional information 

was necessary to complete its review of the applicant’s scoping and screening results. The 

applicant responded to the staff’s RAIs as discussed below. 

In RAI 2.4-1, dated November 12, 2009, the staff asked why the applicant excluded several 

types of fire barrier assemblies and components from the scope of license renewal. These fire 

barrier components include the following: 

 Table 2.4-1, “Fire Barrier Concrete Block (masonry walls) and Fire Barrier Doors” 

 Table 2.4-3, “Fire Barrier Concrete Block (masonry walls) and Fire Barrier Coatings and 

Wraps” 

 Table 2.4-4, “Fire Barrier Concrete Elements” 

 Table 2.4-6, “Fire Barrier Concrete Block (masonry walls) and Fire Barrier Coatings and 

Wraps” 

 Table 2.4-7, “Fire Barrier Concrete Block (masonry walls), Fire Barrier Doors, and Fire 

Barrier Coatings and Wraps” 

 Table 2.4-8, “Fire Barrier Concrete Elements, Fire Barrier Concrete Block (masonry 

walls), Fire Barrier doors, Fire Barrier seals, and Fire Barrier Coatings and Wraps” 

 Table 2.4-9, “Fire Barrier Concrete Block (masonry walls) and Fire Barrier Coatings and 

Wraps” 

 Table 2.4-13, “Fire Barrier Coatings and Wraps” 

The staff asked that the applicant verify whether LRA Section 2.4 should include the fire barrier 

assembles and components listed above. If the applicant excluded these from the scope of 

license renewal, the staff asked that the applicant justify this exclusion. 
 Scoping and Screening Methodology 

 2-101 

In its response, dated December 23, 2009, the applicant provided the results of the scoping and 

screening process for the listed fire barrier assembles and components. In reviewing its 

response to RAI 2.4-1, the staff found that the applicant had addressed and resolved each item 

in the RAI. The applicant confirmed that none of the following assembles and components are 

credited for performing a fire barrier function: 

 Concrete blocks (masonry walls) and doors in the containment building (LRA 

Table 2.4-1) 

 Concrete blocks (masonry walls) and coatings or wraps in the diesel generator building 

(LRA Table 2.4-3) 

 Concrete elements in the turbine building (LRA Table 2.4-4) 

 Concrete blocks (masonry walls) and coatings or wraps in the radwaste building 

(LRA Table 2.4-6) 

 Concrete blocks (masonry walls) in the MSSS (LRA Table 2.4-7) 

 Concrete elements, concrete blocks (masonry walls), doors, seals, and coatings or 

wraps in the SBO generator structures (LRA Table 2.4-8) 

 Concrete blocks (masonry walls) and coatings or wraps in the fuel building 

(LRA Table 2.4-9) 

 Coatings or wraps in yard structures (LRA Table 2.4-13) 

However, the applicant credited fire barrier coatings and wraps for performing a fire barrier 

function in the MSSS, and it added fire barrier coatings and wraps to LRA Table 2.4-7, 

Section 3.5.2.1.7, and LRA Table 3.5.2-7. 

Based on its review, the staff finds the applicant’s response to RAI 2.4-1 acceptable, because it 

clarified that fire barrier assemblies and components in question are not required to perform a 

fire barrier function. The applicant noted that only fire barrier coatings and wraps in the MSSS 

are within the scope of license renewal and subject to an AMR. The staff’s concern is resolved. 

2.4.15.3 Conclusion 

The staff reviewed the LRA, UFSAR, RAI responses, and license renewal drawings to 

determine if the applicant failed to identify any fire protection systems and components within 

the scope of license renewal. In addition, the staff sought to determine if the applicant failed to 

identify any components subject to an AMR. On the basis of its review, the staff concludes that 

the applicant has adequately identified the fire barriers within the scope of license renewal, as 

required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1). 

2.5 Scoping and Screening Results: Electrical and Instrumentation and Control 

Systems

This section documents the staff’s review of the applicant’s scoping and screening results for 

electrical and I&C systems. Specifically, this section discusses electrical and I&C component 

commodity groups. 

In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive, 

long-lived SSCs within the scope of license renewal and subject to an AMR. To verify that the 

applicant properly implemented its methodology, the staff’s review focused on the 

implementation results. This focus 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. 
Scoping and Screening Methodology 

 2-102 

The staff’s evaluation of the information in the LRA was the same for all electrical and I&C 

systems. The objective was to determine whether the applicant has identified, in accordance 

with 10 CFR 54.4, components and supporting structures for electrical and I&C systems that 

appear to meet the license renewal scoping criteria. Similarly, the staff evaluated the 

applicant’s screening results to verify that all passive, long-lived components were subject to an 

AMR in accordance with 10 CFR 54.21(a)(1). 

In its scoping evaluation, the staff reviewed the applicable LRA sections, focusing on 

components that the applicant did not identify as within the scope of license renewal. The staff 

reviewed the UFSAR for each electrical and I&C system to determine whether the applicant has 

omitted from the scope of license renewal components with intended functions delineated under 

10 CFR 54.4(a). 

After its review of the scoping results, the staff evaluated the applicant’s screening results. For 

those SSCs with intended functions, the staff sought to determine whether the functions are 

performed with moving parts or a change in configuration or properties or the SSCs are subject 

to replacement after a qualified life or specified time period, as described in 10 CFR 54.21(a)(1). 

For those meeting neither of these criteria, the staff sought to confirm that these SSCs were 

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

2.5.1 Electrical and Instrumentation and Control Systems Component Groups 

2.5.1.1 Summary of Technical Information in the Application 

LRA Section 2.5 describes the electrical and I&C systems. The applicant’s scoping method 

includes all plant electrical and I&C components. Evaluation of electrical systems includes 

electrical and I&C components in mechanical systems. The applicant states that the plant-wide 

basis approach for the review of plant equipment eliminates the need to identify each unique 

component and its specific location and prevents improper exclusion of components from 

an AMR. 

For the electrical and I&C components identified as within the scope of license renewal, the 

applicant grouped them into component groups regardless of their system association. The 

applicant applied the screening criteria in 10 CFR 54.21(a)(1)(i) and 10 CFR 54.21(a)(1)(ii) to 

this list of component groups to identify those that perform an intended function without moving 

parts or without a change in configuration or properties and to remove the component groups 

that are subject to replacement based on a qualified life or specified time period. The following 

list identifies the component groups that the applicant determined to be subject to an AMR and 

their intended functions: 

 Connections (metallic parts)—electrical continuity 

 Connectors—electrical continuity 

 High-voltage insulators—insulation and structural support 

 Insulated cables and connections—electrical continuity and insulation 

 Metal enclosed bus and connections—electrical continuity 

 Bus bar and connections—electrical continuity 

 Bus enclosure—expansion, separation, and structural support 

 Bus insulation and insulators—insulation 

 Penetrations electrical—electrical continuity and insulation 

 Switchyard bus and connections—electrical continuity 
 Scoping and Screening Methodology 

 2-103 

 Terminal Blocks - electrical continuity 

 Transmission conductors and connections—electrical continuity 

 Electrical equipment subject to 10 CFR 50.49 EQ requirements (TLAA, see LRA 

Section 4) 

 Grounding conductors—ground metal structures and equipment 

 Cable tie wraps—installation aid and cable spacing 

2.5.1.2 Staff Evaluation 

The staff reviewed LRA Section 2.5, UFSAR Sections 7 and 8, and the license renewal 

boundary drawings using the evaluation methodology described in SER Section 2.5 and the 

guidance in SRP-LR Section 2.5, “Scoping and Screening Results: Electrical and 

Instrumentation and Controls Systems.” 

During its review, the staff evaluated the system functions described in the LRA and UFSAR 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 identified as within the scope of license renewal to verify that the 

applicant had not omitted any passive and long-lived components subject to an AMR in 

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

General Design Criterion 17 of 10 CFR Part 50, Appendix A, requires two physically 

independent circuits supply electric power from the transmission network to the onsite electric 

distribution system to minimize the likelihood of simultaneous failure. Additionally, there is 

guidance provided in SRP-LR Section 2.5.2.1.1. For purposes of the license renewal rule, the 

staff has determined that the following is true: 

The plant system portion of the offsite power system that is used to connect the 

plant to the offsite power source meeting the requirements of 10 CFR 54.4(a)(3). 

This path typically includes the switchyard circuit breakers that connect to the 

offsite system power transformers (startup transformers), the transformers 

themselves, the intervening overhead or underground circuits between circuit 

breaker and transformer and transformer and onsite electrical system, and the 

associated control circuits and structures. 

According to this guidance, ensuring that the appropriate offsite power system long-lived 

passive SSCs that are part of this circuit path are subject to an AMR will assure that the bases 

underlying the SBO requirements are maintained over the period of the extended operation. 

The applicant included the complete circuits between the onsite circuits and up to and including 

switchyard breakers (which includes the associated controls and structures) supplying the 

AE-NAN-X01, AE-NAN-X02, and AE-NAN-X03 startup transformers within the scope of license 

renewal. Switchyard breakers 925, 928, 945, 948, 995, and 998 are the scoping boundary for 

the primary and backup sources of offsite power. For PVNGS Unit 1, the primary offsite power 

source is from startup transformers AE-NAN-X03 and AE-NAN-X02, while the backup offsite 

power source is from startup transformer AE-NAN-X01. For PVNGS Unit 2, the primary offsite 

power source is from startup transformers AE-NAN-X01 and AE-NAN-X03, while the backup 

offsite power source is from startup transformer AE-NAN-X02. For PVNGS Unit 3, the primary 

offsite power source is from startup transformers AE-NAN-X01 and AE-NAN-X02, while the 

backup offsite power source is from startup transformer AE-NAN-X03. Consequently, the staff 

concludes that the scoping is consistent with NRC guidance. 

The staff noted that the applicant had not included cable tie-wraps in any component group. In 

the LRA, the applicant states that it did a review to determine if cable tie-wraps meet the 
Scoping and Screening Methodology 

 2-104 

scoping criteria of 10 CFR 54.4. The applicant states that it uses cable tie-wraps as an aid 

during cable installation, but it does not perform any license renewal functions, and seismic 

qualification of cable trays does not credit the use of electrical cable tie-wraps. Furthermore, the 

applicant considered the failure of plastic cable tie-wraps and concluded that such failure would 

not affect safety-related equipment or any design-basis event. The staff reviewed the UFSAR 

and found that cable tie-wraps are not credited in the design basis. Based on this review and 

the information provided in the LRA, the staff finds the applicant’s exclusion of cable tie-wraps 

from SSCs subject to an AMR acceptable. 

2.5.1.3 Conclusion 

The staff reviewed the LRA, UFSAR, and the license renewal boundary drawing to determine if 

the applicant failed to identify any SSCs within the scope of license renewal. The staff has 

found no such omissions. In addition, the staff’s review determined if the applicant failed to 

identify any components subject to an AMR. The staff found no such omissions. On the basis 

of its review, the staff concludes that the applicant has adequately identified the electrical and 

I&C systems components within the scope of license renewal, as required by 10 CFR 54.4(a), 

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

2.6 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 Results” and determines that the applicant’s scoping and screening 

methodology is consistent with 10 CFR 54.21(a)(1). Further, the applicant’s methodology is 

consistent with the staff’s positions on the treatment of safety-related and nonsafety-related 

SSCs within the scope of license renewal and on SCs subject to an AMR, and 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 concludes that the applicant has adequately identified those 

systems and components within the scope of license renewal, as required by 10 CFR 54.4(a), 

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

The staff concludes that there is reasonable assurance that the applicant will continue to 

conduct the activities authorized by the renewed licenses in accordance with the CLB, and any 

changes to the CLB, in order to comply with 10 CFR 54.21(a)(1), the Atomic Energy Act of 

1954, as amended, and NRC regulations. 
 

 3-1 

3.0 AGING MANAGEMENT REVIEW RESULTS 

This section of the safety evaluation report (SER) evaluates aging management programs 

(AMPs) and aging management reviews (AMRs) for Palo Verde Nuclear Generating Station, 

Units 1, 2, and 3 (PVNGS), by the U.S. Nuclear Regulatory Commission (NRC) staff (the staff). 

In Appendix B of its license renewal application (LRA), Arizona Public Service Company (APS) 

(the applicant) describes the 40 AMPs that it relies on to manage or monitor the aging of 

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

In LRA Section 3, the applicant provided the results of the AMRs for those SCs identified in LRA 

Section 2 as within the scope of license renewal and subject to an AMR. 

3.0 Applicant’s Use of the Generic Aging Lessons Learned Report

In preparing its LRA, the applicant credited NUREG-1801, Revision 1, “Generic Aging Lessons 

Learned (GALL) Report,” dated September 2005. The GALL Report contains the staff’s generic 

evaluation of the existing plant programs and documents the technical basis for determining 

where existing programs are adequate without modification and where existing programs should 

be augmented for the period of extended operation. The evaluation results, documented in the 

GALL Report, note that many of the existing programs are adequate to manage the aging 

effects for particular license renewal SCs. The GALL Report also contains recommendations on 

specific areas for which existing programs should be augmented for license renewal. An 

applicant may reference the GALL Report in its LRA to demonstrate that its programs 

correspond to those reviewed and approved in the report. 

The GALL Report provides a summary of staff-approved AMPs to manage or monitor the aging 

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

they will greatly reduce the time, effort, and resources for LRA review and improve the efficiency 

and effectiveness of the license renewal review process. The GALL Report also serves as a 

quick reference for applicants and staff reviewers to the AMPs and activities that the staff has 

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

The GALL Report lists the systems, structures, and components (SSCs); the SC materials; 

environments to which the SCs are exposed; the aging effects of the materials and 

environments; the AMPs credited with managing or monitoring the aging effects; and 

recommendations for further applicant evaluations of aging management for certain component 

types. 

To determine whether use of the GALL Report would improve the efficiency of the LRA review, 

the staff conducted a demonstration of the GALL Report process in order to model the format 

and content of safety evaluations based on it. The results of the demonstration project 

confirmed that the GALL Report process will improve the efficiency and effectiveness of the 

LRA review while maintaining the staff’s focus on public health and safety. NUREG-1800, 

Revision 1, “Standard Review Plan for Review of License Renewal Applications for Nuclear 

Power Plants” (SRP-LR), dated September 2005, was prepared based on both the GALL 

Report model and lessons learned from the demonstration project. 

The staff‘s review of the LRA was in accordance with Title 10, Part 54, of the Code of Federal 

Regulations (10 CFR Part 54), “Requirements for Renewal of Operating Licenses for Nuclear 

Power Plants,” as well as the guidance of the SRP-LR and the GALL Report. 

In addition to its review of the LRA, the staff conducted an onsite audit of AMPs during the week 

of December 7, 2009. The staff designed the onsite audit for maximum efficiency of the LRA 

review. The applicant can respond to questions and the staff can readily evaluate the 
Aging Management Review Results 

 3-2 

applicant’s responses. This process reduces the need for formal correspondence between the 

staff and the applicant, and the result is an improvement in review efficiency. 

3.0.1 Format of the License Renewal Application 

The applicant submitted an application that follows the standard LRA format agreed upon by the 

staff and the Nuclear Energy Institute (NEI) by letter dated April 7, 2003. This revised LRA 

format incorporated lessons learned from the staff’s reviews of the previous five LRAs, which 

used a format developed from information gained during a demonstration project conducted by 

the staff and NEI to evaluate the use of the GALL Report in the LRA review process. 

The organization of LRA Section 3 parallels that of SRP-LR Chapter 3. LRA Section 3 presents 

AMR results information in the following two table types: 

(1) Table 1s: 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 table type is the 

first in LRA Section 3 

(2) Table 2s: 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 table type is the second 

in LRA Section 3, and “y” indicates the system table number 

The content of the previous LRAs and of the PVNGS application is essentially the same. The 

intent of the revised format of the PVNGS LRA was to modify the tables in LRA Section 3 to 

provide additional information that would help in the staff’s review. In its Table 1s, the applicant 

summarized the portions of the application that it considered consistent with the GALL Report. 

In its Table 2s, the applicant noted the linkage between the scoping and screening results in 

LRA Section 2 and the AMRs in LRA Section 3. 

3.0.1.1 Overview of Table 1s 

Each Table 1 compares, in summary, how the facility aligns with the corresponding tables in the 

GALL Report. The tables are essentially the same as Tables 1–6 in the GALL Report, except 

that an “Item Number” column has replaced the “Type” column, and a “Discussion” column 

replaced by the “Discussion Item Number in the GALL” column. The “Item Number” column is a 

means for the staff reviewer to cross-reference Table 2s with Table 1s. In the “Discussion” 

column, the applicant provided clarifying 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 

 exceptions to GALL Report assumptions 

 discussion of how the line is consistent with the corresponding line item in the GALL 

Report when the consistency may not be obvious 

 discussion of how the item is different from the corresponding line item in the GALL 

Report (e.g., when an exception is taken to a GALL Report AMP) 

The format of each Table 1 allows the staff to align a specific row in the table with the 

corresponding GALL Report table row to easily check for consistency. 

3.0.1.2 Overview of Table 2s 

Each Table 2 provides the detailed results of the AMRs for components subject to an AMR, as 

noted in LRA Section 2. The LRA has a Table 2 for each of the systems or structures within a 
Aging Management Review Results 

 3-3 

specific system grouping (e.g., reactor coolant system (RCS), engineered safety features 

(ESFs), auxiliary systems, etc.). For example, the ESF group has tables that are specific to the 

containment spray system, containment isolation system, and emergency core cooling system 

(ECCS). Each Table 2 consists of the following nine columns: 

(1) Component Type – The first column lists LRA Section 2 component types subject to an 

AMR in alphabetical order. 

(2) Intended Function – The second column identifies the license renewal intended 

functions including abbreviations, where applicable, for the listed component types. 

Definitions and abbreviations of intended functions are in LRA Table 2.0-1. 

(3) Material – The third column lists the particular construction material(s) for the 

component type. 

(4) Environment – The fourth column lists the environments to which the component types 

are exposed. This column notes the internal and external service environments. A list 

of these environments is provided in LRA Tables 3.0-1, 3.0-2, and 3.0-3. 

(5) Aging Effect Requiring Management (AERM) – The fifth column lists the AERMs. As 

part of the AMR process, the applicant determined AERMs for each combination of 

material and environment. 

(6) Aging Management Programs – The sixth column lists the AMPs that the applicant 

uses to manage the identified aging effects. 

(7) NUREG-1801 Vol. 2 Item – The seventh column lists the GALL Report item(s) that are 

similar to the AMR results, as noted in the LRA. The applicant compared each 

combination of component type, material, environment, AERM, and AMP in LRA Table 2 

with the GALL Report items. If there are no corresponding items in the GALL Report, 

the applicant leaves the column blank. 

(8) Table 1 Item – The eighth column lists the corresponding summary item number from 

LRA Table 1. If the applicant notes AMR results consistent with the GALL Report in 

each LRA Table 2, the Table 1 line item summary number should be listed in LRA 

Table 2. If there is no corresponding item in the GALL Report, the applicant leaves 

column eight blank. 

(9) Notes – The ninth column lists the corresponding notes used to show how the 

information in each Table 2 aligns with the information in the GALL Report. An NEI 

working group developed the notes, which are identified by letters. SER Section 3.0.2.2 

describes the generic notes A–E, which indicate that AMR items are essentially 

consistent with the GALL Report. Each AMR section that provides the staff’s review of 

items that are not consistent with the GALL Report (3.x.2.3) contains an explanation of 

notes F–J. Any plant-specific notes identified by numbers provide additional information 

about the consistency of the line item with the GALL Report. 

3.0.2 Staff’s Review Process 

The staff conducted three types of evaluations of the AMRs and AMPs: 

(1) For items that the applicant stated were consistent with the GALL Report, the staff 

conducted either an audit or a technical review to determine consistency. 

(2) For items that the applicant stated were consistent with the GALL Report with 

exceptions, enhancements, or both, the staff conducted either an audit or a technical 

review of the item to determine consistency. In addition, the staff conducted either an 

audit or a technical review of the applicant’s technical justifications for the exceptions or 
Aging Management Review Results 

 3-4 

the adequacy of the enhancements. The SRP-LR states that an applicant may take one 

or more exceptions specific to the GALL Report AMP elements; however, any deviation 

from, or exception to, the GALL Report AMP should be described and justified. 

Therefore, the staff considers exceptions as being portions of the GALL Report AMP that 

the applicant does not intend to implement. In some cases, an applicant may choose an 

existing plant program that does not meet all the program elements defined in the GALL 

Report AMP. However, the applicant may make a commitment to augment the existing 

program to satisfy the GALL Report AMP before the period of extended operation. 

Therefore, the staff considers these augmentations or additions to be enhancements. 

Enhancements include, but are not limited to, activities needed to ensure consistency 

with the GALL Report recommendations. Enhancements may expand, but not reduce, 

the scope of an AMP. 

(3) For other items, the staff conducted a technical review to verify conformance with 

10 CFR 54.21(a)(3) requirements. 

Staff audits and technical reviews of the applicant’s AMPs and AMRs determine whether the 

aging effects on SCs can be adequately managed to maintain their intended function(s), 

consistent with the plant’s current licensing basis (CLB), for the period of extended operation, as 

required by 10 CFR Part 54. 

3.0.2.1 Review of Aging Management Programs 

For AMPs for which the applicant claimed consistency with the GALL Report AMPs, the staff 

conducted either an audit or a technical review to verify the claim. For each AMP with one or 

more deviations, the staff evaluated each deviation to determine whether the deviation was 

acceptable and whether the modified AMP would adequately manage the aging effect(s) for 

which it was credited. For AMPs not evaluated in the GALL Report, the staff performed a full 

review to determine their adequacy. The staff evaluated the AMPs against the following 

10 program elements defined in SRP-LR, Appendix A. 

(1) Scope of the Program – Scope of the program should include the specific SCs subject to 

an AMR for license renewal. 

(2) Preventive Actions – Preventive actions should prevent or mitigate aging degradation. 

(3) Parameters Monitored or Inspected – Parameters monitored or inspected should be 

linked to the degradation of the particular structure or component’s intended function(s). 

(4) Detection of Aging Effects – Detection of aging effects should occur before there is a 

loss of structure or component intended function(s). This includes aspects such as 

method or technique (i.e., visual, volumetric, surface inspection), frequency, sample 

size, data collection, and timing of new or one-time inspections to ensure the 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’s 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 corrective actions are completed and are effective. 
Aging Management Review Results 

 3-5 

(9) Administrative Controls – Administrative controls should provide for 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 adequately 

managed to maintain the SC intended function(s) during the period of extended 

operation. 

SER Section 3.0.3 documents details of the staff’s audit evaluation of program elements 1–6. 

The staff reviewed the applicant’s quality assurance (QA) program and documented its 

evaluations in SER Section 3.0.4. The staff’s evaluation of the QA program included 

assessment of the “corrective actions,” “confirmation process,” and “administrative controls” 

program elements (elements 7, 8, and 9). 

The staff also reviewed the information on the “operating experience” program element 

(element 10) for each program and documented its evaluation in SER Section 3.0.3. 

3.0.2.2 Review of Aging Management Review Results 

Each LRA Table 2 contains information concerning whether or not the AMRs noted by the 

applicant align with the GALL Report AMRs. For a given AMR in a Table 2, the staff reviewed 

the intended function, material, environment, AERM, and AMP combination for a particular 

system component type. Item numbers in column seven of the LRA, “NUREG-1801 Vol. 2 

Item,” correlate to an AMR combination as identified in the GALL Report. The staff also 

conducted onsite audits to verify these correlations. A blank in column seven indicates that the 

applicant was unable to identify an appropriate correlation in the GALL Report. The staff also 

conducted a technical review of combinations not consistent with the GALL Report. The next 

column, “Table 1 Item,” refers to a number indicating the correlating row in Table 1. 

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency with the report and for which the applicant does not recommend further evaluation, 

the staff’s audit and review determined whether the plant-specific components of these GALL 

Report component groups were bounded by the GALL Report evaluation. 

The applicant noted, for each AMR line item, how the information in the tables aligns with the 

information in the GALL Report. The staff audited those AMRs, with notes A–E showing how 

the AMR is consistent with the GALL Report. 

Note A indicates that the AMR line item is consistent with the GALL Report for component, 

material, environment, and aging effect. In addition, the AMP is consistent with the GALL 

Report AMP. The staff audited these line items to verify consistency with the GALL Report and 

validity of the AMR for the site-specific conditions. 

Note B indicates that the AMR line item is consistent with the GALL Report for component, 

material, environment, and aging effect. In addition, the AMP takes some exceptions to the 

GALL Report AMP. The staff audited these line items to verify consistency with the GALL 

Report, and verified that the exceptions to the GALL Report AMPs have been reviewed and 

accepted. The staff also determined whether the applicant’s AMP was consistent with the GALL 

Report AMP and whether the AMR was valid for the site-specific conditions. 

Note C indicates that the component for the AMR line item is consistent with, although different 

from, the GALL Report for material, environment, and aging effect. In addition, the AMP is 

consistent with the GALL Report AMP. This note shows that the applicant was unable to find a 

listing of some system components in the GALL Report; however, the applicant found in the 

GALL Report a different component with the same material, environment, aging effect, and AMP 

as the component under review. The staff audited these line items to verify consistency with the 
Aging Management Review Results 

 3-6 

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 indicates that the component for the AMR line item is consistent with, although different 

from, the GALL Report for material, environment, and aging effect. In addition, the AMP takes 

some exceptions to the GALL Report AMP. 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 and whether the noted exceptions to 

the GALL Report AMPs have been reviewed and accepted. The staff also determined whether 

the applicant’s AMP was consistent with the GALL Report AMP and whether the AMR was valid 

for the site-specific conditions. 

Note E indicates that the AMR line item is consistent with the GALL Report for material, 

environment, and aging effect, but credits a different AMP. The staff audited these line items to 

verify consistency with the GALL Report. The staff also determined whether the credited AMP 

would manage the aging effect consistently with the GALL Report AMP and whether the AMR 

was valid for the site-specific conditions. 

3.0.2.3 Updated Final Safety Analysis Report Supplement 

The staff also reviewed the Updated Final Safety Analysis Report (UFSAR) supplement, which 

summarizes the applicant’s programs and activities for managing aging effects for the period of 

extended operation, as required by 10 CFR 54.21(d). 

3.0.2.4 Documents Reviewed 

In its review, the staff used the LRA, including supplements and amendments, the SRP-LR, and 

the GALL Report. During the onsite audit, the staff examined documentation to verify the 

applicant’s justifications that the activities and programs will adequately manage the effects of 

aging on the 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. The staff’s Audit Report can be found in a letter to the applicant dated 

April 7, 2010. 

3.0.3 Aging Management Programs 

SER Table 3.0-1 presents the AMPs credited by the applicant and described in LRA 

Appendix B. The table also identifies which GALL Report AMPs that the applicant claims are 

consistent with its analyses, a comparison to the Gall Report AMP, and the section of this SER 

that documents the staff’s evaluation of the program. 

Table 3.0-1. Aging Management Programs 

Applicant Aging 

Management Program 

LRA 

Sections 

New or 

Existing 

Program 

Applicant 

Comparison to 

the GALL Report

GALL Report Aging 

Management Programs 

SER 

Section 

American Society of 

Mechanical Engineers 

(ASME) Section XI Inservice Inspections (ISIs), 

Subsections IWB, IWC, and 

IWD Program 

A1.1 

B2.1.1 

Existing Consistent XI.M1, “ASME Section XI 

Inservice Inspection, 

Subsections IWB, IWC, and 

IWD” 

3.0.3.1.1

Water Chemistry Program A1.2 

B2.1.2 

Existing Consistent with 

enhancementa XI.M2, “Water Chemistry” 3.0.3.2.1

Reactor Head Closure 

Studs Program 

A1.3 

B2.1.3 

Existing Consistent XI.M3, “Reactor Head 

Closure Studs” 

3.0.3.1.2
Aging Management Review Results 

 3-7 

Applicant Aging 

Management Program 

LRA 

Sections 

New or 

Existing 

Program 

Applicant 

Comparison to 

the GALL Report

GALL Report Aging 

Management Programs 

SER 

Section 

Boric Acid Corrosion A1.4 

B2.1.4 

Existing Consistent XI.M10, “Boric Acid 

Corrosion” 

3.0.3.1.3

Nickel-Alloy Penetration 

Nozzles Welded to the 

Upper RV Closure Heads of 

Pressurized Water Reactors 

(PWRs) 

A1.5 

B2.1.5 

Existing Consistent XI.M11A, “Nickel-Alloy 

Penetration Nozzles Welded 

to the Upper Reactor Vessel 

Closure Heads of 

Pressurized Water Reactors” 

3.0.3.1.4

Flow-Accelerated Corrosion 

(FAC) Program 

A1.6 

B2.1.6 

Existing Consistent with 

exceptions 

XI.M17, “Flow-Accelerated 

Corrosion” 

3.0.3.2.2

Bolting Integrity Program A1.7 

B2.1.7 

Existing Consistent with 

exceptions 

XI.M18, “Bolting Integrity” 3.0.3.2.3

Steam Generator (SG) Tube 

Integrity Program 

A1.8 

B2.1.8 

Existing Consistent XI.M19, “Steam Generator 

Tube Integrity” 

3.0.3.1.5

Open-Cycle Cooling Water 

System Program 

A1.9 

B2.1.9 

Existing Consistent with 

enhancements 

XI.M20, “Open-Cycle 

Cooling Water System” 

3.0.3.2.4

Closed-Cycle Cooling Water 

System Program 

A1.10 

B2.1.10 

Existing Consistent with 

enhancements 

and exceptions 

XI.M21, “Closed-Cycle 

Cooling Water System” 

3.0.3.2.5

Inspection of Overhead 

Heavy Load and Light Load 

(Related to Refueling) 

Handling Systems Program 

A1.11 

B2.1.11 

Existing Consistent with 

enhancement 

XI.M23, “Inspection of 

Overhead Heavy Load and 

Light Load (Related to 

Refueling) Handling 

Systems” 

3.0.3.2.6

Fire Protection Program A1.12 

B2.1.12 

Existing Consistent with 

enhancements 

and exceptions 

XI.M26, “Fire Protection” 3.0.3.2.7

Fire Water System Program A1.13 

B2.1.13 

Existing Consistent with 

enhancements 

and exceptions 

XI.M27, “Fire Water System” 3.0.3.2.8

Fuel Oil Chemistry Program A1.14 

B2.1.14 

Existing Consistent with 

enhancements 

and exceptions 

XI.M30, Fuel Oil Chemistry 3.0.3.2.9

RV Surveillance Program A1.15 

B2.1.15 

Existing Consistent with 

enhancements 

XI.M31, “Reactor Vessel 

Surveillance” 

3.0.3.2.10

One-Time Inspection 

Program 

A1.16 

B2.1.16 

New Consistent XI.M32, “One-Time 

Inspection” 

3.0.3.1.6

Selective Leaching of 

Materials Program 

A1.17 

B2.1.17 

New Consistent with 

exceptions 

XI.M33, “Selective Leaching 

of Materials” 

3.0.3.2.11

Buried Piping and Tanks 

Inspection Program 

A1.18 

B2.1.18 

New Consistent with 

exceptions 

XI.M34, “Buried Piping and 

Tanks Inspection” 

3.0.3.2.12

One-Time Inspection of 

ASME Code Class 1 SmallBore Piping 

A1.19 

B2.1.19 

Existing Consistent with 

exceptions 

XI.M35, “One-Time 

Inspection of ASME Code 

Class 1 Small-Bore Piping” 

3.0.3.2.13

External Surfaces 

Monitoring Program 

A1.20 

B2.1.20 

New Consistent with 

exception 

XI.M36, “External Surfaces 

Monitoring Program” 

3.0.3.2.14
Aging Management Review Results 

 3-8 

Applicant Aging 

Management Program 

LRA 

Sections 

New or 

Existing 

Program 

Applicant 

Comparison to 

the GALL Report

GALL Report Aging 

Management Programs 

SER 

Section 

Reactor Coolant System 

Supplement 

A1.21 

B2.1.21 

Not 

applicable

Not applicable XI.M11A, “ Nickel-Alloy 

Penetration Nozzles Welded 

to the Upper Reactor Vessel 

Closure Heads of 

Pressurized Water Reactors” 

and XI.M16 “PWR Vessel 

Internals” 

3.0.3.1.7

Inspection of Internal 

Surfaces in Miscellaneous 

Piping and Ducting 

Components Program 

A1.22 

B2.1.22 

New Consistent with 

exceptions 

XI.M38, “Inspection of 

Internal Surfaces in 

Miscellaneous Piping and 

Ducting Components” 

3.0.3.2.15

Lubricating Oil Analysis 

Program 

A1.23 

B2.1.23 

Existing Consistent with 

exceptions 

XI.M39, “Lubricating Oil 

Analysis” 

3.0.3.2.16

Electrical Cables and 

Connections Not Subject to 

10 CFR 50.49 

Environmental Qualification 

(EQ) Requirements 

Program 

A1.24 

B2.1.24 

New Consistent XI.E1, “Electrical Cables and 

Connections Not Subject to 

10 CFR 50.49 Environmental 

Qualification Requirements” 

3.0.3.1.8

Electrical Cables and 

Connections Not Subject to 

10 CFR 50.49 

Environmental Qualification 

Requirements Used in 

Instrumentation Circuits 

Program 

A1.25 

B2.1.25 

Existing Consistent with 

enhancements 

XI.E2, “Electrical Cables and 

Connections Not Subject to 

10 CFR 50.49 Environmental 

Qualification Requirements 

Used in Instrumentation 

Circuits” 

3.0.3.2.17

Inaccessible Medium 

Voltage Cables Not Subject 

to 10 CFR 50.49 

Environmental Qualification 

Requirements Program 

A1.26 

B2.1.26 

New Consistent XI.E3, “Inaccessible Medium 

Voltage Cables Not Subject 

to 10 CFR 50.49 

Environmental Qualification 

Requirements” 

3.0.3.1.9

ASME Section XI, 

Subsection IWE Program 

A1.27 

B2.1.27 

Existing Consistent with 

exceptions 

XI.S1, “ASME Section XI, 

Subsection IWE” 

3.0.3.2.18

ASME Section XI, 

Subsection IWL Program 

A1.28 

B2.1.28 

Existing Consistent XI.S2, “ASME Section XI, 

Subsection IWL” 

3.0.3.1.10

ASME Section XI, 

Subsection IWF Program 

A1.29 

B2.1.29 

Existing Consistent XI.S3, “ASME Section XI, 

Subsection IWF” 

3.0.3.1.11

10 CFR Part 50 Appendix J 

Program 

A1.30 

B2.1.30 

Existing Consistent XI.S4, “10 CFR 50, 

Appendix J” 

3.0.3.1.12

Masonry Wall Program A1.31 

B2.1.31 

Existing Consistent with 

enhancement 

X.S5, “Masonry Wall 

Program” 

3.0.3.2.19

Structures Monitoring 

Program 

A1.32 

B2.1.32 

Existing Consistent with 

enhancement 

XI.S6, “Structures Monitoring 

Program” 

3.0.3.2.20

RG 1.127, Inspection of 

Water-Control Structures 

Associated with Nuclear 

Power Plants 

A1.33 

B2.1.33 

Existing Consistent with

enhancement 

XI.S7, “RG 1.127, Inspection 

of Water-Control Structures 

Associated with Nuclear 

Power Plants” 

3.0.3.2.21

Nickel-Alloy Aging 

Management Program 

A1.34 

B2.1.34 

Existing Plant Specific Not Applicable 3.0.3.3.1
Aging Management Review Results 

 3-9 

Applicant Aging 

Management Program 

LRA 

Sections 

New or 

Existing 

Program 

Applicant 

Comparison to 

the GALL Report

GALL Report Aging 

Management Programs 

SER 

Section 

Electrical Cable 

Connections Not Subject to 

10 CFR 50.49 

Environmental Qualification 

Requirements Program 

A1.35 

B2.1.35 

New Consistent XI.E6, “Electrical Cable 

connections Not Subject to 

10 CFR 50.49 Environmental 

Qualification Requirements” 

3.0.3.1.13

Metal Enclosed Bus 

Program 

A1.36 

B2.1.36 

New Consistent XI.E4, “Metal Enclosed Bus” 3.0.3.1.14

Fuse Holders Program A1.37 

B2.1.37 

New Consistent XI.E5, “Fuse Holders” 3.0.3.1.15

Metal Fatigue of Reactor 

Coolant Pressure Boundary 

(RCPB) Program 

A2.1 

B3.1 

Existing Consistent with 

enhancements 

X.M1, “Metal Fatigue of 

Reactor Coolant Pressure 

Boundary” 

3.0.3.2.22

Environmental Qualification 

(EQ) of Electric 

Components Program 

A2.2 

B3.2 

Existing Consistent X.E1, “Environmental 

Qualification (EQ) of Electric 

Components” 

3.0.3.1.16

Concrete Containment 

Tendon Prestress Program 

A2.3 

B3.3 

Existing Consistent with 

enhancements 

X.S1, “Concrete 

Containment Tendon 

Prestress” 

3.0.3.2.23

a

 The enhancement was implemented during staff review, and the AMP is now consistent. 

3.0.3.1 Aging Management Programs Consistent with the Generic Aging Lessons 

Learned Report 

In LRA Appendix B, the applicant identified the following AMPs as consistent with the GALL 

Report: 

 ASME Section XI ISI, Subsections IWB, IWC, and IWD Program 

 Reactor Head Closure Studs Program 

 Boric Acid Corrosion Program 

 Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel (RV) Closure 

heads of Pressurized Water Reactors Program 

 Steam Generator Tube Integrity Program 

 One-Time Inspection Program 

 Reactor Coolant System Supplement 

 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Program 

 Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Program 

 ASME Section XI, Subsection IWL Program 

 ASME Section XI, Subsection IWF Program 

 10 CFR Part 50, Appendix J Program 
Aging Management Review Results 

 3-10 

 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Program 

 Metal Enclosed Bus Program 

 Fuse Holders Program 

 Environmental Qualification (EQ) of Electrical Components Program 

3.0.3.1.1 American Society of Mechanical Engineers Section XI In-Service Inspection, 

Subsections IWB, IWC, and IWD Program 

Summary of Technical Information in the Application. LRA Section B2.1.1 describes the 

existing ASME Section XI ISI, Subsections IWB, IWC, and IWD Program as consistent with the 

GALL Report AMP XI.M1, “ASME Section XI Inservice Inspection, Subsections IWB, IWC, and 

IWD.” The applicant stated that the ASME Section XI ISI, Subsections IWB, IWC, and IWD 

Program manages cracking, loss of fracture toughness, and loss of material in Class 1, 2, and 3 

piping and components within the scope of license renewal. The applicant stated that the 

program includes periodic visual, surface, and volumetric examinations and leakage tests of 

Class 1, 2, and 3 pressure-retaining components, including welds, pump casings, valve bodies, 

integral attachments, and pressure-retaining bolting, as identified in ASME Code, Section XI, 

Tables IWB-2500-1, IWC-2500-1, and IWD-2500-1. 

The applicant stated that Units 1, 2, and 3 are in their third 10-year ISI intervals. In 

conformance with 10 CFR 50.55a(g)(4)(ii), the applicant updates its program at the end of each 

successive 120-month period to comply with the requirements of the latest edition of the code 

(in effect, twelve months before the start of the inspection interval). The applicant further stated 

that the current ASME Code Section XI ISI Program is consistent with ASME Code Section XI, 

2001 edition–2003 addenda. In addition, during the period of extended operation, the applicant 

will use the latest ASME Code edition at that time, consistent with provisions of 10 CFR 50.55a. 

The applicant stated that the program provides measures for monitoring to detect aging effects 

before a loss of intended function and provides measures for repair and replacement of 

components in which aging effects are detected. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. 

The staff noted that the applicant’s current, third-interval ASME Section XI ISI, Subsections 

IWB, IWC, and IWD Program does not use risk-informed ISI methodology. The staff also noted 

that the applicant’s program includes CLB requirements under 10 CFR 50.55a that require code 

cases N-722 and N-729-1 be used to provide additional examinations. These examinations are 

for pressurized water reactors (PWR) pressure retaining welds in Class 1 components 

fabricated with Alloy 600/82/182 materials (code case N-722), and alternative examination 

requirements for PWR RV upper heads with nozzles having pressure-retaining partialpenetration welds (code case N-729-1). The staff also confirmed that all components required 

by the ASME Code to be examined in each preceding 10-year ISI interval, have been 

examined. The staff finds these features of the applicant’s program to be acceptable because 

they are consistent with the applicant’s CLB and with the GALL Report’s recommendations. 

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of the GALL Report AMP XI.M1. As discussed in the Audit Report, the staff confirmed 

that these elements are consistent with the corresponding elements of the GALL Report AMP 

XI.M1. Based on its audit, the staff finds that elements one through six of the applicant’s ASME 

Section XI ISI, Subsections IWB, IWC, and IWD Program are consistent with the corresponding 

program elements of the GALL Report AMP XI.M1 and, therefore, acceptable. 
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Operating Experience. LRA Section B2.1.1 summarizes operating experience related to the 

ASME Section XI ISI, Subsections IWB, IWC, and IWD Program. The applicant stated that 

review of its plant-specific operating experience for its program has not revealed any program 

adequacy issues or implementation issues with the ASME Section XI ISI, Subsections IWB, 

IWC, and IWD Program. The applicant stated that it evaluates industry operating experience for 

relevancy to its ASME Section XI ISI, Subsections IWB, IWC, and IWD Program and that it 

takes and documents appropriate actions. The applicant stated that, based on these results, 

the ASME Section XI ISI, Subsections IWB, IWC, and IWD Program is effective in monitoring 

ASME Class 1, 2, and 3 components and detecting aging effects before any loss of intended 

function. 

The applicant stated that its review of the Second 10-Year ISI Interval Summary Reports for 

Units 1, 2, and 3 found that there were no code repairs or code replacements required for 

continued service of ASME Code Section XI, IWB, IWC, and IWD components during the 

10-year period. The applicant further stated that the summary reports did not identify any 

implementation issues with the ASME Section XI ISI, Subsections IWB, IWC, and IWD Program 

for ASME Code Section XI, IWB, IWC, and IWD components. 

The applicant stated that it updates the ASME Section XI ISI, Subsections IWB, IWC, and IWD 

Program to account for industry operating experience, and annual updates of ASME Code 

Section XI allow the applicant to update the code to reflect industry operating experience. The 

applicant also stated that the requirement to update the ASME Section XI ISI, Subsections IWB, 

IWC, and IWD Program, to reference more recent editions of ASME Code Section XI, at the end 

of each 10-year inspection interval ensures that the program reflects enhancements due to 

operating experience that have been incorporated into ASME Code Section XI. 

The staff reviewed operating experience information, in the application and during the audit, to 

determine whether the applicant reviewed the applicable aging effects and industry and 

plant-specific operating experience. As discussed in the Audit Report, the staff conducted an 

independent search of the plant operating experience information to determine if the applicant 

adequately incorporated and evaluated operating experience related to this program. The staff 

found that the applicant adequately identified and incorporated industry and applicable 

plant-specific operating experience. 

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program. The staff confirmed that the “operating 

experience” program element satisfies the criterion of SRP-LR Section A.1.2.3.10 and, 

therefore, the staff finds it acceptable. 

UFSAR Supplement. LRA Section A1.1 provides the UFSAR supplement for the ASME 

Section XI ISI, Subsections IWB, IWC, and IWD Program. The staff reviewed this UFSAR 

supplement’s description of the program and notes that it conforms to the recommended 

description for this type of program as described in SRP-LR Table 3.1-2. The staff also notes 

that the applicant committed (Commitment No. 3) to the ongoing implementation of the existing 

ASME Section XI ISI, Subsections IWB, IWC, and IWD Program to manage the aging of 

applicable components during the period of extended operation. The staff determines that the 

information in the UFSAR supplement is an adequate summary description of the program, as 

required by 10 CFR 54.21(d). 

Conclusion. On the basis of its review of the applicant’s ASME Section XI ISI, Subsections 

IWB, IWC, and IWD Program, the staff finds all program elements consistent with the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). In addition, the staff 
Aging Management Review Results 

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reviewed the UFSAR supplement for this AMP, and concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d). 

3.0.3.1.2 Reactor Head Closure Studs Program 

Summary of Technical Information in the Application. LRA Section B2.1.3 describes the 

existing Reactor Head Closure Studs Program as consistent with the GALL Report AMP XI.M3, 

“Reactor Head Closure Studs.” The applicant stated that the Reactor Head Closure Studs 

Program conducts ASME Code Section XI inspections of RV flange stud hole threads and of 

reactor head closure studs, nuts, and washers to manage the aging effects of cracking and loss 

of materials in these components. The applicant also stated that its program follows the 

preventive measures described in NRC Regulatory Guide (RG) 1.65, “Materials and Inspections 

for Reactor Closure Studs,” and that it uses a lubricant on RV flange stud hole threads, reactor 

head closure stud and nut threads, and washer faces after reactor head closure stud, nut, and 

washer cleaning and examination. 

The applicant stated that it detects potential cracking or loss of material in RV flange stud hole 

threads and in reactor head closure studs, nuts, and washers through visual or volumetric 

examinations, in accordance with ASME Code Section XI requirements. The applicant stated 

that these examinations are conducted during refueling outages, after the studs are removed 

from the vessel flange holes. The applicant stated that during flood-up of the reactor cavity, in 

support of refueling activities, the RV flange holes are plugged with water tight plugs to assure 

that the holes, studs, nuts, and washers are protected from borated water. 

The applicant stated that its program currently implements the requirements of ASME Code 

Section XI, Subsection IWB, 2001 edition through the 2003 addenda and that its program is 

updated during each successive 120-month inspection interval to comply with the requirements 

of the latest ASME Code Section XI edition in accordance with the provisions of 10 CFR 50.55a. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. 

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of the GALL Report AMP. As discussed in the Audit Report, the staff confirmed that 

each element of the applicant’s program is consistent with the corresponding element of the 

GALL Report AMP Reactor Head Closure Studs, with the exception of the “preventive actions” 

and “detection of aging effects” program elements. For these elements, the staff determined the 

need for additional clarification, which resulted in the issuance of requests for additional 

information (RAIs). 

In the GALL Report AMP Reactor Head Closure Studs, the “preventive actions” program 

element states that preventive measures include the use of acceptable surface treatments and 

stable lubricants and that implementation of this measure can reduce the potential for stress 

corrosion cracking (SCC) or intergranular stress corrosion cracking (IGSCC). In its review of 

the applicant’s “preventive actions” program element, the staff noted that the applicant uses the 

thread lubricant Lubrikol L1G6M5, which contains 1-percent molybdenum disulphide on the 

reactor head bolt closure studs. The staff further noted that, although it is not explicitly 

referenced in the GALL Report AMP, NUREG-1339, “Resolution of Generic Safety Issue 29: 

Bolting Degradation or Failure in Nuclear Power Plants,” includes specific recommendations 

against the use of thread lubricants containing molybdenum disulfide. 

By letter dated December 29, 2010, the staff issued RAI B2.1.7-3 requesting the applicant to 

explain how it will manage the aging effects of concern in NUREG-1339, related to use of a 

thread lubricant containing molybdenum disulfide, to ensure that the preventive actions 
Aging Management Review Results 

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described in the GALL Report AMP Reactor Head Closure Studs are implemented during the 

period of extended operation. 

In its response, dated March 24, 2010, the applicant stated that it follows the preventive 

measures in RG 1.65 to prevent aging effects due to corrosion or hydrogen embrittlement. The 

applicant stated that its RV closure studs are not metal-plated and that it currently uses “Super 

Molly 402-40 or equivalent (e.g., Lubrikol L1G6M5)” as lubricant on RV flange stud hole threads, 

reactor head closure stud and nut threads, and washer faces after reactor head closure stud, 

nut and washer cleaning and examination are complete. The applicant further stated that 

administrative controls limit the use of Super Molly 402-40 to only these applications and that, 

while Super Molly 402-40 is compatible with the RV flange, stud, nut, and washer materials, it is 

in the process of a phased withdrawal of lubricants containing molybdenum disulfide associated 

with these applications from the site. In a conference call (January 11, 2011), the applicant 

confirmed that this would be completed before the period of extended operation. The applicant 

further stated that it has had minimal issues with galling of reactor head closure studs and that it 

has not identified any cases of SCC or IGSCC with its RV studs, nuts, flange stud holes, or 

washers. 

Based on the its review, the staff finds the applicant’s response to RAI B2.1.7-03 acceptable 

because the applicant has administrative controls in place to limit the use of Super 

Molly 402-40 or other lubricants containing molybdenum disulfide, and the applicant is in the 

process of a phased withdrawal of lubricants containing molybdenum disulfide from the site. 

The applicant resolved the staff’s concern, described in RAI B2.1.7-03. 

In the GALL Report AMP Reactor Head Closure Studs, the “detection of aging effects” program 

element states that Examination Category B-G-1, for pressure-retaining bolting greater than 

2-inch diameter in the RV, specifies surface and volumetric examination of studs when removed 

from the RV. In its review of the applicant’s “detection of aging effects” program element, the 

staff noted that the applicant performs volumetric (not volumetric and surface) examination of 

reactor head closure studs when removed from the RV flange. 

By letter dated December 29, 2009, the staff issued RAI B2.1.3-01 requesting the applicant to 

explain why implementation of only volumetric examinations, rather than volumetric and surface 

examinations, for removed closure studs is not identified as an exception to recommendations 

in the GALL Report. Additionally, the staff asked the applicant to justify how the use of only 

volumetric inspections for these components will provide adequate detection of aging effects 

during the period of extended operation. 

In its response, dated February 19, 2010, the applicant stated that it determined that no 

exception to the GALL Report AMP Reactor Head Closure Studs, “detection of aging effects” 

program element was necessary because the volumetric examination of reactor head closure 

studs, when removed, meets the requirements of ASME Code Section XI, 2001 edition, 

including the 2002 and 2003 addenda. The applicant further stated that it appears that the 

phrase “surface and volumetric examination of studs when removed” should have been 

changed to “surface or volumetric examination of studs when removed” when the ASME code 

version cited in the GALL Report was changed. 

The staff confirmed that ASME Code Section XI, 2001 edition, including 2002 and 2003 

addenda, Examination Category B-G-1 for pressure retaining bolting greater than 2-inches 

diameter in RVs no longer includes a specific examination requirement for reactor head closure 

studs “when removed.” In the 2001 code edition, the requirement for item B6.30 (“closure 

studs, when removed”) was changed to specify either volumetric or surface examination; and in 

the 2002 addenda, item B6.30 was deleted entirely, which resulted in volumetric examination 

being normally specified, with surface examination permitted to be substituted for volumetric 

examination when studs are removed. The staff further confirmed that there are no statements 
Aging Management Review Results 

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in the GALL Report indicating that additional surface examination is recommended for license 

renewal, and there are no additional requirements in the 10 CFR 50.55a endorsements of 

ASME Code Section XI, 2001 edition, with 2002 and 2003 addenda, to indicate that 

augmentation of the Examination Category B-G-1 specifications is required. 

Based on its review, the staff finds the applicant’s response to RAI B2.1.3-01 acceptable 

because (1) the applicant’s volumetric examination of reactor head closure studs is consistent 

with specifications if ASME Code Section XI, 2001 edition, including the 2002 and 2003 

addenda, which is referenced in the GALL Report, (2) neither the GALL Report nor 10 CFR 

50.55a specify augmentation of the ASME Code Section XI, Examination Category B-G-1 

requirements, and (3) either surface or volumetric examinations are capable of detecting 

cracking in reactor head closure studs prior to the aging mechanism affecting the CLB function 

of the studs. The applicant, therefore, resolved the staff’s concern described in RAI B2.1.3-01. 

Based on its audit and review of the applicant’s responses to RAIs B2.1.7-03 and B2.1.3-01, the 

staff finds that elements one through six of the applicant’s Reactor Head Closure Studs 

Program are consistent with the corresponding program elements of the GALL Report AMP 

XI.M3 and, therefore, acceptable. 

Operating Experience. LRA Section B2.1.3 summarizes operating experience related to the 

Reactor Head Closure Studs Program. The applicant stated that its review of its plant-specific 

operating experience has not revealed any implementation issues with the Reactor Head 

Closure Studs Program and that it has not identified any instances of cracking, due to SCC or 

IGSCC, with RV studs, nuts, flange stud holes, or washers. 

The applicant stated that review of its Refueling Outage ISI Reports for the second 10-year ISI 

interval found there were no repair or replacement items associated with the RV closure studs, 

nuts, washers or flange thread holes. The applicant also stated that it updated its ISI Program, 

which is the basis for its Reactor Head Closure Studs Program, to account for industry operating 

experience. Annual updates of ASME Code Section XI allow the applicant to update the code 

to reflect industry operating experience. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicant reviewed the applicable aging effects and industry and 

plant-specific operating experience. As discussed in the Audit Report, the staff conducted an 

independent search of the plant operating experience information to determine if the applicant 

adequately incorporated and evaluated operating experience related to this program. The staff 

found that the applicant adequately identified and incorporated industry and applicable 

plant-specific operating experience. 

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program. The staff confirmed that the “operating 

experience” program element satisfies the criterion of SRP-LR Section A.1.2.3.10 and, 

therefore, the staff finds it acceptable. 

UFSAR Supplement. LRA Section A1.3 provides the UFSAR supplement for the Reactor Head 

Closure Stud Program. The staff reviewed this UFSAR supplement description of the program 

and notes that it conforms to the recommended description for this type of program as 

described in SRP-LR Table 3.1-2. The staff also notes that the applicant committed 

(Commitment No. 5) to the ongoing implementation of the existing Reactor Head Closure Studs 

Program to manage the aging of applicable components during the period of extended 

operation. The staff determines that the information in the UFSAR supplement is an adequate 

summary description of the program, as required by 10 CFR 54.21(d). 
Aging Management Review Results 

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Conclusion. On the basis of its review of the applicant’s Reactor Head Closure Studs Program, 

the staff finds all program elements consistent with the GALL Report. The staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP, and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

3.0.3.1.3 Boric Acid Corrosion Program 

Summary of Technical Information in the Application. LRA Section B2.1.4 describes the 

existing Boric Acid Corrosion Program as consistent with the GALL Report AMP XI.M10, “Boric 

Acid Corrosion.” The applicant stated that this program manages loss of material in 

components with materials susceptible to boric acid corrosion. The applicant also stated that 

the program includes provisions to identify leakage, inspect and examine for evidence of 

leakage, evaluate leakage, and initiate corrective actions. The program also includes the 

tracking and trending of boric acid leakage from plant components. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. 

The staff compared elements one through six of the applicant’s program to the corresponding 

element of the GALL Report AMP Boric Acid Corrosion. As discussed in the Audit Report, the 

staff confirmed that these elements are consistent with the corresponding elements of the GALL 

Report AMP Boric Acid Corrosion. Based on its audit, the staff finds that elements one through 

six of the applicant’s Boric Acid Corrosion Program are consistent with the corresponding 

program elements of the GALL Report AMP Boric Acid Corrosion and, therefore, acceptable. 

Operating Experience. LRA Section B2.1.4 summarizes operating experience related to the 

Boric Acid Corrosion Program. The applicant stated that, in response to recent NRC generic 

communications, it revised the RCS pressure boundary integrity walkdowns to include periodic 

visual inspection of the RCS for indications of leakage. The applicant also stated that there 

were several instances where it made containment entries to investigate increased RCS 

leakage in which it detected boric acid leakage through the visual observation of active leaks or 

residual deposits. The applicant stated that these cases illustrate that the program is effective 

in identifying boric acid corrosion before the loss of component intended function. 

The staff reviewed operating experience information, in the application and during the audit, to 

determine whether the applicant reviewed applicable aging effects and industry and plantspecific operating experience. In addition to the information provided in the LRA, the staff 

reviewed the relevant operating experience recorded in onsite records, including condition 

reports, disposition requests, and corrective maintenance work orders. The following two 

examples of site-specific operating experience also demonstrate the effectiveness of the 

program: 

(1) Based on a visual inspection, the applicant found a check valve with boric acid crystals, 

indicating that leakage had occurred followed by evaporation and the subsequent 

appearance of crystals. Following this observation, the applicant cleaned the area and 

conducting a surveillance, which confirmed the presence of a small leak at the 

suspected location. The applicant issued a work order for valve seal replacement. The 

applicant attributed the leaking valve seal to access difficulty, which led to the application 

of unsatisfactory torque on the associated fixture during the prior valve maintenance 

cycle. 
Aging Management Review Results 

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(2) Inspection reports include cases where the applicant observed small, recurring leaks on 

valves in the boric acid piping system. In these cases, the applicant generated 

appropriate work orders for repairs and replacements, as indicated by the 

circumstances. In addition, the applicant conducted engineering evaluations to 

determine that the correct components were used for the associated pressures and boric 

acid environments. 

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, 

therefore, the staff finds it acceptable. 

UFSAR Supplement. LRA Section A1.4 provides the UFSAR supplement for the Boric Acid 

Corrosion Program. The staff reviewed the UFSAR supplement description of the program and 

notes that it conforms to the recommended description for this type of program, as described in 

SRP-LR Tables 3.1-2, 3.2-2, 3.3-2, 3.4-2, 3.5-2, and 3.6-2. The staff also notes that the 

applicant committed (Commitment No. 6) to the ongoing implementation of the existing Boric 

Acid Corrosion Program to manage the aging of applicable components during the period of 

extended operation. The staff determines that the information in the UFSAR supplement is an 

adequate summary description of the program, as required by 10 CFR 54.21(d). 

Conclusion. On the basis of its review of the applicant’s Boric Acid Corrosion program, the staff 

finds all program elements consistent with the GALL Report. The staff concludes that the 

applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

3.0.3.1.4 Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure 

Heads of Pressurized Water Reactors 

Summary of Technical Information in the Application. LRA Section B2.1.5 describes the 

existing Nickel-Alloy Penetration Nozzles Welded to the Upper RV Closure Heads of PWR 

Program (Nickel-Alloy Head Penetration Program) as consistent with the GALL Report AMP 

XI.M11A, “Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure 

Heads of Pressurized Water Reactors.” The applicant stated that the program manages 

cracking, due to primary water stress corrosion cracking (PWSCC), and loss of material, due to 

boric acid wastage in nickel-alloy pressure vessel head penetration nozzles. The applicant 

stated that the program includes the RV closure head, the upper vessel head penetration 

nozzles, and associated welds. The applicant also stated that it mitigated cracking through the 

control of water chemistry. The applicant further stated that it managed the aging effects of 

cracking and loss of material through a combination of visual and non-visual inspection 

techniques, as described in ASME Code Case N-729-1, as modified by 

10 CFR 50.55a(g)(6)(ii)(D)(2)–(6). 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. 

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of the GALL Report AMP. In making this comparison, the staff noted that, in its 

original submission, the applicant proposed this AMP to be consistent with the GALL Report 

AMP with one enhancement. The proposed enhancement was to add the inspection 
Aging Management Review Results 

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requirements described in ASME Code Case N-729-1 as modified by 

10 CFR 50.55a(g)(6)(ii)(D)(2)–(6). The staff also noted that in Supplement 1 to the LRA, dated 

April 10, 2009, the inspection requirements described in the code case were incorporated into 

the AMP, thereby eliminating the need for enhancement. The staff further noted that the 

governing document discussed in the GALL Report AMP is NRC Order EA-03-009 or any 

subsequent NRC requirements that may be established to supersede the requirements of Order 

EA-03-009. The staff finally noted that the governing document in the LRA AMP is Code Case 

N-729-1 (the Code Case resulted from the incorporation of the inspection requirements of Order 

EA-03-009 into 10 CFR 50.55a and ASME Code Section XI). The staff finds the incorporation 

of the originally proposed enhancement into the AMP and the use of Code Case N-729-1 

acceptable because 10 CFR 50.55a(g)(6)(ii)(D)(1) states that NRC Order EA-03-009 is 

withdrawn in favor of ASME Code Case N-729-1, as modified by 

10 CFR 50.55a(g)(6)(ii)(D)(2)-(6). The staff finds that elements one through six of the 

applicant’s Nickel-Alloy Head Penetration Program are consistent with the corresponding 

program elements of the GALL Report AMP XI.M11A and, therefore, are acceptable. 

Operating Experience. LRA Section B2.1.5 summarizes operating experience related to the 

Nickel-Alloy Head Penetration Program. The applicant stated that it has conducted all 

inspections as required by NRC order EA-03-009 or Code Case N-729-1. For Units 1 and 3, the 

applicant reported that it observed no evidence of cracking or metal wastage. For Unit 2, the 

applicant observed indications on the vent line on one occasion and removed these indications 

by machining. The applicant subsequently applied a weld overlay over this area. The applicant 

also stated that the head for Unit 2 was replaced in the fall of 2009, Unit 1 head was replaced in 

spring of 2010, and the head for Unit 3 is scheduled for replacement in the fall of 2010. Based 

on the use of different alloys for the penetration nozzles in the replacement heads, the staff 

considers operating experience accumulated using the old heads to be of little value for 

predicting the performance of the new heads. 

The staff reviewed all available industry and plant specific operating experience to determine if 

the applicant incorporated this experience in the AMP. If not, the staff determined if the failure 

of the applicant to incorporate this experience in the AMP would adversely affect the ability of 

the applicant to adequately manage the aging of the components under consideration, through 

the use of the AMP. The staff found that the applicant adequately identified and incorporated 

industry and applicable plant-specific operating experience. 

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, 

therefore, the staff finds it acceptable. 

UFSAR Supplement. LRA Section A1.5 provides the UFSAR supplement for the Nickel-Alloy 

Head Penetration Program. The staff reviewed this UFSAR supplement description of the 

program and notes that it contains the critical aspects of the recommended description for this 

type of program as described in SRP-LR Table 3.1-2. The staff also notes that the applicant 

committed (Commitment No. 7) to the ongoing implementation of the existing Nickel-Alloy Head 

Penetration Program to manage the aging of applicable components during the period of 

extended operation. The staff determines that the information in the UFSAR supplement is an 

adequate summary description of the program, as required by 10 CFR 54.21(d). 

Conclusion. On the basis of its review of the applicant’s Nickel-Alloy Head Penetration 

Program, the staff finds all program elements consistent with the GALL Report. The staff 

concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 
Aging Management Review Results 

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period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR supplement for this AMP and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d). 

3.0.3.1.5 Steam Generator Tube Integrity Program 

Summary of Technical Information in the Application. LRA Section B2.1.8 describes the 

existing SG Tube Integrity Program as consistent with the GALL Report AMP XI.M19, “Steam 

Generator Tube Integrity.” The applicant stated that the SG Tube Integrity Program includes 

measures to prevent, inspect, and assess degradation; to assess structural and leakage 

integrity; to maintain primary and secondary chemistry controls; and to conduct required 

maintenance and repair activities necessary to manage aging mechanisms. The applicant 

further stated that the SG Tube Integrity Program is consistent with NEI 97-06, “Steam 

Generator Program Guidelines,” and with the requirements of the technical specifications (TS), 

which encompass and exceed the requirements of RG 1.121, “Bases for Plugging Degraded 

Steam Generator Tubes.” 

The applicant stated that each unit has two identical recirculating SGs, designed by Combustion 

Engineering, Inc. (CE), which are considered a modified CE System 80 design. The original 

SGs were replaced in Units 1, 2, and 3 during the fall of 2005, 2003, and 2007, respectively. 

Each replacement SG has 12,580 Alloy 690 thermally-treated tubes. The tubes are 

hydraulically expanded into the tubesheet for the entire tubesheet thickness. The tube support 

system is similar to the original design and, like the original design, is fabricated from type 409 

ferritic stainless steel. In addition to the tubing material change, the U-bend region in the first 

17 rows were stress relieved after bending, to minimize the potential for SCC. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. 

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of the GALL Report AMP, “Steam Generator Tube Integrity.” As discussed in the 

Audit Report, the staff confirmed that these elements are consistent with the corresponding 

elements of the GALL Report AMP, “Steam Generator Tube Integrity.” Based on its audit, the 

staff finds that elements one through six of the applicant’s SG Tube Integrity AMP are consistent 

with the corresponding program elements of the GALL Report AMP, “Steam Generator Tube 

Integrity” and, therefore, are acceptable. 

Operating Experience. LRA Section B2.1.8 summarizes operating experience related to the SG 

Tube Integrity program. The applicant stated that wear is the only active damage mechanism in 

the SGs, specifically, wear as the result of tubing interaction with the tube supports. Most of the 

wear indications observed were in the region around the stay cylinder and at either the diagonal 

supports or vertical support 3. The applicant also provided the following operational experience: 

Due to certain historically observed wear phenomenon, PVNGS has employed 

conservative administrative plugging criteria related to support wear 

mechanisms. For example, support wear indications are removed for wear rate 

greater than or equal to 35% for a normal operating cycle if no previous wear is 

identified. This plugging criterion is designed to ensure that the structural and 

accident leakage performance criteria specified in the PVNGS Technical 

Specifications are not exceeded in the subsequent operating cycle. It was 

expected, based on RSG [replacement steam generators] redesign, that the 

conditions necessary to generate high wear rates in the Batwing Stay Cylinder 

(BWSC) and Cold Leg Corner (CLC) regions were eliminated. While this was 

clearly the case for CLC wear, the RSG inspection results during the initial 

inspection in Unit 2 (U2R12) indicated that the RSGs continued to exhibit similar 
Aging Management Review Results 

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wear conditions within the BWSC region. As a result of these findings, a decision 

was made prior to Unit 1 and Unit 3 RSG installation to plug and stake all of the 

“frontline” BWSC tubes. The subsequent inspections during U2R13, U1R13, 

U2R14, U1R14, U3R14, and U2R15 have indicated that the BWSC wear issue 

exists in the RSGs of all three PVNGS units. 

On February 19, 2004, Unit 2 was operating at full power when radiation 

monitors displayed indications of a low level primary to secondary leak. Shortly 

thereafter the leak rate was calculated to be 11.8 gallons per day, even though 

grab samples indicated 3 gallons per day, and the decision was made to shut the 

unit down to find and repair the leak. 

After cooling the plant down and performing tests, one RSG tube was found to be 

leaking and was plugged. Further analysis showed that the cause of the leak 

was from a puncture received from a wood screw that was used in the 

construction of the shipping crates for the tubes when the RSGs were being 

manufactured. The tubes were placed in the crate and the crate assembled 

around them. One screw that was used near the outer diameter of the top of the 

tube bend protruded through the wood and began to puncture the tube material. 

The screw did not completely penetrate the tube and the unit was operated from 

its post-outage startup to this date when the tube finally began leaking. 

Contamination to the secondary plant was minimal and the unit entered Mode 1 

on March 9, 2004. Corrective actions put in place after the event prevented 

recurrence in the Unit 1 and 3 RSGs. 

The staff reviewed operating experience information in the application and during the audit to 

determine if the applicant reviewed aging effects and industry and plant-specific operating 

experience. The staff conducted an independent search of the plant operating experience 

information to determine if the applicant had adequately incorporated and evaluated operating 

experience related to this program. The staff found that the applicant had adequately identified 

and incorporated industry and applicable plant-specific operating experience. 

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, 

therefore, the staff finds it acceptable. 

UFSAR Supplement. LRA Section A1.8 provides the UFSAR supplement for the SG Tube 

Integrity Program. The staff reviewed this UFSAR supplement description of the program and 

notes that it conforms to the recommended description for this type of program, as described in 

SRP-LR Table 3.1-2. The staff also notes that the applicant committed (Commitment No. 10) to 

the ongoing implementation of the existing SG Tube Integrity Program to manage the aging of 

applicable components during the period of extended operation. 

The staff finds that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d). 

Conclusion. On the basis of its review of the applicant’s SG Tube Integrity Program, the staff 

finds all program elements consistent with the GALL Report. The staff concludes that the 

applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP, and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 
Aging Management Review Results 

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3.0.3.1.6 One-Time Inspection Program 

Summary of Technical Information in the Application. LRA Section B2.1.16 describes the 

One-Time Inspection Program as a new program, consistent with the GALL Report AMP 

XI.M32, “One-Time Inspection.” The applicant stated that its program performs one-time 

inspections of plant piping and components to verify the effectiveness of the Water Chemistry, 

Fuel Oil Chemistry, and Lubricating Oil Analysis Programs. The applicant also stated that the 

aging effects evaluated by the One-Time Inspection Program are loss of material, cracking, and 

reduction of heat transfer. The applicant further stated that the One-Time Inspection Program 

includes the identification and statistical sampling of the piping and component population for 

the selected material and environment combinations, as well as the inspection of the selected 

components per ASME Code Sections V or XI, as applicable. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. 

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of the GALL Report, “One-Time Inspection AMP.” As discussed in the Audit Report, 

the staff confirmed that each element of the applicant’s program is consistent with the 

corresponding element of the GALL Report AMP, with the exception of the “detection of aging 

effects” program element. For this element, the staff determined the need for additional 

clarification, which resulted in the issuance of an RAI, discussed below. 

During the audit, the applicant stated that it would perform surface examination techniques to 

detect cracking in addition to the enhanced visual and volumetric inspection techniques 

recommended by the GALL Report AMP, “One-Time Inspection.” However, it was not clear to 

the staff how the applicant would use surface examinations to detect cracking. By letter dated 

December 29, 2009, the staff issued RAI B2.1.16-2 requesting that the applicant clarify if the 

surface examination techniques used to detect cracking will replace the enhanced visual or 

volumetric inspections recommended by the GALL Report or if the surface inspections will 

supplement the enhanced visual or volumetric inspections. The staff also asked that the 

applicant clarify if it will perform the surface examinations on wetted surfaces. 

In its response, dated February 19, 2010, the applicant stated that depending on each 

component’s environment and accessibility, a proper non-destructive examination (NDE) 

technique selected from the One-Time Inspection Program procedure will be used to identify 

aging effects in piping and components, including those that are exposed to water, lube oil, and 

fuel oil environments. The applicant also stated that the NDE techniques discussed in the 

One-Time Inspection Program are consistent with ASME Code NDE techniques. The staff finds 

the applicant’s response to RAI B2.1.16-2 acceptable because the program will perform NDE 

techniques that are capable of detecting loss of material or cracking, are appropriate for the 

given material and environment combinations, and are consistent with industry standards. The 

applicant’s response resolved the staff’s concern, as described in RAI B2.1.16-2. 

Based on its audit and review of the applicant’s response to RAI B2.1.16-2, the staff finds that 

elements one through six of the applicant’s One-Time Inspection Program are consistent with 

the corresponding program elements of the GALL Report AMP, “One-Time Inspection” and, 

therefore, are acceptable. 

Operating Experience. LRA Section B2.1.16 summarizes the operating history related to the 

One-Time Inspection Program. The applicant stated that it will perform one-time inspections 

during the 10-year period before the period of extended operation to identify possible aging 

effects. Since this is a new program, there is no plant-specific operating experience to review. 

However, the applicant also stated that ASME Code Section XI ISI inspection techniques have 

proven effective in detecting aging effects before the loss of intended function. In addition, a 
Aging Management Review Results 

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review of plant-specific operating experience associated with the ISI Program has not revealed 

any ISI Program adequacy issues. 

The staff reviewed the operating experience information, in the application and during the audit, 

to determine if the applicant reviewed applicable aging effects and industry and plant-specific 

operating experience associated with the ISI Program. As discussed in the Audit Report, the 

staff conducted an independent search of the plant operating experience information to 

determine if the applicant had adequately incorporated and evaluated the operating history 

related to its program. During its review, the staff noted the applicant’s operating experience 

review may not have been comprehensive and determined the need for additional clarification, 

which resulted in the issuance of the following RAI. 

The applicant stated in the LRA that the plant-specific operating experience associated with the 

ISI Program had not revealed any inadequacies or implementation issues. The staff noted that, 

although there is no plant specific operating experience associated with the One-Time 

Inspection Program application, any operating experience resulting from maintenance activities 

of systems and components that will be within the scope of the ISI Program should be included 

in the review. By letter dated December 29, 2009, the staff issued RAI B2.1.16-1 requesting 

that the applicant provide a summary of operating experience resulting from observations of 

loss of material, cracking, and loss of heat transfer identified during maintenance as well as the 

associated corrective action activities taken. 

In its response, dated February 19, 2010, the applicant stated that an examination of 

plant-specific aging effect related operating experience from 1996 through October 2009 

identified 16,000 maintenance and corrective action entries. The applicant also stated that 

these entries discussed, “...mechanical joint leakage, out of specification chemistry, bearing 

wear products, presence of water in oil, manufacturing defects, and construction flaws,” and that 

the items were more closely related to the Water Chemistry, Fuel Oil Chemistry, and Lubricating 

Oil Analysis Programs than the One-Time Inspection Program. The applicant also stated that it 

did not find any operating experience related to loss of material, cracking, and loss of heat 

transfer for components that the One-Time Inspection Program will manage. The staff finds the 

plant-specific operating experience associated with the applicant’s One-Time Inspection 

Program is bounded by the GALL Report and, therefore, is acceptable. The applicant resolved 

the staff’s concern, as described in RAI B2.1.16-1. 

Based on its audit, review of the application, and review of the applicant’s response to 

RAI B2.1.16-1, the staff finds that operating experience related to the applicant’s program 

demonstrates that the applicant can adequately manage the detrimental effects of aging on 

SSCs within the scope of the program, and that implementation of the program has resulted in 

the applicant taking corrective actions. The staff confirmed that the “operating experience” 

program element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, therefore, is 

acceptable. 

UFSAR Supplement. LRA Section A1.16 provides the UFSAR supplement for the One-Time 

Inspection Program. The staff reviewed this UFSAR supplement description of the program and 

notes that it conforms to the recommended description for this type of program, as described in 

SRP-LR Tables 3.1-2, 3.2-2, 3.3-2 and 3.4-2. The staff also notes that the applicant committed 

(Commitment No. 18) to implement the new One-time Inspection Program before entering the 

period of extended operation to manage the aging of applicable components and to inspect fuel 

oil tank bottoms (Commitment No. 16) for thickness with a one-time ultrasonic or pulsed eddy 

current examination. The staff determines that the information in the UFSAR supplement is an 

adequate summary description of the program, as required by 10 CFR 54.21(d). 

Conclusion. On the basis of its audit and review of the applicant’s One Time Inspection 

Program, the staff determines that those program elements for which the applicant claimed 
Aging Management Review Results 

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consistency with the GALL Report are consistent. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP, 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

3.0.3.1.7 Reactor Coolant System Supplement 

Summary of Technical Information in the Application. In LRA Section B2.1.21, the applicant 

described its RCS Supplement Program, stating that, in accordance with the SRP-LR, 

Section 3.1, “Aging Management of Reactor Vessel, Internals, and Coolant System,” this 

program supplements the AMPs for the RCS components with the following additional 

requirements. 

 For Reactor Coolant System Nickel-Alloy Pressure Boundary Components. The 

applicant will implement applicable, (1) NRC orders, bulletins and generic letters 

associated with nickel alloys, (2) staff-accepted industry guidelines, (3) participate in the 

industry initiatives, such as owners group programs and the Electric Power Research 

Institute (EPRI) Materials Reliability Program, to manage the aging effects associated 

with nickel alloys, (4) upon completion of these programs, but not less than 24 months 

before entering the period of extended operation, the applicant will submit an inspection 

plan for RCS nickel-alloy pressure boundary components to the NRC for review and 

approval. 

 For Reactor Vessel Internals. The applicant will, (1) participate in industry programs for 

investigating and managing aging effects on reactor internals, (2) evaluate and 

implement the results of the industry programs as applicable to the reactor internals, and 

(3) upon completion of these programs, but not less than 24 months before entering the 

period of extended operation, the applicant will submit an inspection plan for reactor 

internals to the NRC for review and approval. 

Staff Evaluation. The staff reviewed the applicant’s proposed RCS Supplement Program to 

confirm whether this AMP is consistent with the GALL Report. For RCS nickel-alloy pressure 

boundary components, the GALL Report AMP XI.M11A, “Nickel-Alloy Nozzles and 

Penetrations,” states that, “[g]uidance for the aging management of other nickel-alloy nozzles 

and penetrations is provided in the AMR line items of Chapter IV, as appropriate.” The staff 

noted that the GALL Report Table IV.A2 recommends specific AMPs for the management of 

postulated aging effects that may occur in the nickel-alloy control rod drive mechanism 

penetration pressure housings (IV.A2-11), core support pads and guide lugs (IV.A2-12), and 

bottom head penetration instrument tubes (IV.A2-19) covered by the following LRA Sections: 

 Section 3.1.2.2.13, “Cracking due to Primary Water Stress Corrosion Cracking 

(PWSCC)” 

 Section 3.1.2.2.16, “Cracking due to Stress Corrosion Cracking and Primary Water 

Stress Corrosion Cracking” 

The GALL Report does not recommend any further evaluation if the applicant commitment, 

specified under the Table IV.A2, column heading “Aging Management Program (AMP),” for 

these components (or line items) is confirmed. The applicant must meet the following 

commitment, as required in SRP-LR Sections 3.1.2.2.13 and 3.1.2.2.16: 

Comply with applicable NRC Orders and provide a commitment in the FSAR 

supplement to submit a plant-specific AMP to implement applicable (1) Bulletins 

and Generic Letters and (2) staff-accepted industry guidelines. 
Aging Management Review Results 

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Similarly, for reactor pressure vessel (RPV) internals, the GALL Report AMP XI.M16, “Reactor 

Vessel Internals,” states that, “[g]uidance for the aging management of PWR Vessel Internals is 

provided in the AMR line items of Chapter IV, as appropriate.” The following LRA sections 

cover the management of postulated aging effects that may occur for PWRs: 

 Section 3.1.2.2.6, “Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement 

and Void Swelling” 

 Section 3.1.2.2.9, “Loss of Preload Due to Stress Relaxation” 

 Section 3.1.2.2.12, “Cracking Due to Stress Corrosion Cracking and Irradiation-Assisted 

Stress Corrosion Cracking (IASCC)” 

 Section 3.1.2.2.15, “Changes in Dimensions Due to Void Swelling” 

 Section 3.1.2.2.17, “Cracking Due to Stress Corrosion Cracking, Primary Water Stress 

Corrosion Cracking, and Irradiation-Assisted Stress Corrosion Cracking (IASCC)” 

The GALL Report does not recommend any further evaluation if the applicant commitment, 

specified under the Table IV.B3 column heading “Aging Management Program (AMP),” for 

these RPV internals (or line items) is confirmed. The applicant must meet the following 

commitment, as required in SRP-LR Sections 3.1.2.2.6, 3.1.2.2.9, 3.1.2.2.12, 3.1.2.2.15, 

and 3.1.2.2.17: 

No further aging management review is necessary if the applicant provides a 

commitment in the FSAR supplement to (1) participate in the industry programs 

for investigating and managing aging effects on reactor internals; (2) evaluate 

and implement the results of the industry programs as applicable to the reactor 

internals; and (3) upon completion of these programs, but not less than 

24 months before entering the period of extended operation, submit an 

inspection plan for reactor internals to the NRC for review and approval. 

By comparing the contents of the RCS Supplement Program with Commitment No. 23 in LRA 

Appendix A as well as with the commitments specified in the SRP-LR and GALL Report 

Tables IV.A2 and IV.B3, the staff concludes that the RCS Supplement Program is equivalent to 

Commitment No. 23, which exceeds the SRP-LR required commitment for certain RCS 

nickel-alloy components. Essentially, the RCS Supplement Program is the same as the 

SRP-LR required commitment for certain RPV internals. Hence, the staff considers the 

applicant’s RCS Supplement Program as a means of fulfilling Commitment No. 23, designed to 

meet a key aging management guideline provided in SRP-LR Sections 3.1.2.2.13 and 

3.1.2.2.16 for certain RCS nickel-alloy components and SRP-LR Sections 3.1.2.2.6, 3.1.2.2.9, 

3.1.2.2.12, 3.1.2.2.15, and 3.1.2.2.17 for certain RPV internals. Therefore, the staff determines 

that the 10 program elements for a typical GALL Report AMP do not apply to the applicant’s 

RCS Supplement Program. 

For the RCS nickel-alloy components, in addition to the RCS Supplement Program (or 

equivalently, implementation of Commitment No. 23), the staff verified that LRA Sections 

3.1.2.2.13 and 3.1.2.2.16 also require the ASME Code Section XI ISI (IWB, IWC, and IWD) 

Program and Water Chemistry Program to mitigate the specific aging mechanisms. For RPV 

internals, in addition to the RCS Supplement Program, the staff verified that LRA Sections 

3.1.2.2.12 and 3.1.2.2.17 also require control of water chemistry to mitigate the specific aging 

mechanisms. Staff evaluation of the ASME Code Section XI ISI Program and the Water 

Chemistry Program can be found in SER Sections 3.0.3.1.1 and 3.0.3.2.1. 

The staff noted that the lists of components for the RPV internals, in LRA Table 3.1.2-1 under 

the aging effects of LRA Sections 3.1.2.2.6, 3.1.2.2.9, 3.1.2.2.12, and 3.1.2.2.15, do not seem to 

be consistent with the lists of components in GALL Report Table IV.B3, for which the RCS 
Aging Management Review Results 

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Supplement Program is credited for part or all of the aging management. These seeming 

inconsistencies are largely due to the plant-specific features of the RPV internals, which consist 

of components not identical to those listed in GALL Report Table IV.B3. Sections 3.1.2.2.6, 

3.1.2.2.9, 3.1.2.2.12, and 3.1.2.2.15 of this SER contain the staff’s resolution of the RAIs related 

to these inconsistencies. 

Based on the staff’s review above and the staff’s resolution of RAIs related to inconsistency of 

component listing between the LRA and the GALL Report, the staff concludes that the RCS 

Supplement Program is equivalent to Commitment No. 23. Commitment No. 23 is designed to 

meet the SRP-LR and GALL Report Tables IV.A2 and IV.B3 requirements for RCS nickel-alloy 

components and the RPV internals under the aging mechanisms identified earlier. Hence, 

working with appropriate AMP(s), as specified in GALL Report Tables IV.A2 and IV.B3, the RCS 

Supplement Program is acceptable for management of aging effects listed above for the RCS 

nickel-alloy components and the RPV internals. 

UFSAR Supplement. LRA Section A1.21 provides the UFSAR supplement for the Reactor 

Coolant System Supplement. The staff reviewed this UFSAR supplement description of the 

program and notes that it conforms to the recommendations described in SRP-LR Table 3.1-2. 

The staff also notes that the applicant committed (Commitment No. 23) to implement the 

Reactor Coolant System Supplement before entering the period of extended operation. The 

staff determines that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d). 

Conclusion. On the basis of its review of the applicant's RCS Supplement Program, the staff 

determines that this AMP is a program designed to fulfill Commitment 23. This AMP is 

consistent with the GALL Report because GALL Report Tables IV.A2 and IV.B3 provide 

guidance for the management of the relevant RCS nickel-alloy pressure boundary components 

and RPV internals, which require the commitments as stated in Commitment No. 23. The staff 

concludes that, combined with other specific AMPs, the applicant has demonstrated that the 

effects of aging for certain RCS nickel-alloy components and the RPV internals 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 concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d). 

3.0.3.1.8 Electrical Cables and Connections Not Subject to the Environmental Qualification 

Requirements Program Under Title 10, Part 50.49 of the Code of Federal 

Regulations 

Summary of Technical Information in the Application. LRA Section B2.1.24 describes the new 

Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Program as 

consistent with the GALL Report AMP XI.E1 “Electrical Cables and Connections Not Subject to 

10 CFR 50.49 EQ Requirements.” The applicant stated that the Electrical Cables and 

Connections Program manages embrittlement, melting, cracking, swelling, surface 

contamination, or discoloration to ensure that electrical cables, connections and terminal blocks, 

not subject to the EQ requirements of 10 CFR 50.49 and within the scope of license renewal, 

are capable of performing their intended functions. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. 

The staff compared elements 1 through 6 of the applicant’s program to the corresponding 

elements of the GALL Report AMP, “Electrical Cables and Connections Not Subject to 

10 CFR 50.49 EQ Requirements Program.” As discussed in the Audit Report, the staff 

confirmed that each element of the applicant’s program is consistent with the corresponding 
Aging Management Review Results 

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element of the GALL Report AMP, with the exception of the “scope of program” element. In 

order to verify whether the “scope of program” element is consistent with the corresponding 

element of the GALL Report AMP, the staff issued RAI B2.1.24-1 to the applicant in a letter 

dated December 29, 2009. This RAI requested the applicant to explain why electrical 

containment penetrations were not included in the scope of the program. 

In its response, dated February 19, 2010, the applicant stated that LRA Table 3.6.2-1 shows the 

penetrations electrical line being managed using the AMP Electrical Cables and Connections 

Not Subject to 10 CFR 50.49 EQ Requirements. The applicant also stated that the Electrical 

Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements AMP was revised to 

clarify that the non-EQ electrical containment penetrations are included in the program. The 

applicant revised the LRA AMP section to include the following clarification, “[c]onnection 

insulation material includes termination kits and tape used to insulate splices that are normally 

located within junction boxes, terminal blocks located within terminal boxes, and non-EQ 

electrical containment penetrations.” 

The staff finds the applicant’s response acceptable because the applicant included non-EQ 

electrical containment penetrations in the scope of Electrical Cables and Connections Not 

Subject to 10 CFR 50.49 EQ Requirement AMP. Including electrical containment penetrations 

makes the applicant’s AMP consistent with the recommendations in the GALL Report AMP. 

The staff’s concern in RAI B2.1.24-1 is resolved. 

Based on its audit, review of the application, and review of the applicant’s response to 

RAI B2.1.24-1, the staff finds that elements one through six of the applicant’s Electrical Cables 

and Connections Not Subject to 10 CFR 50.49 EQ Requirements Program are consistent with 

the corresponding program elements of the GALL Report AMP and, therefore, are acceptable. 

Operating Experience. The staff also reviewed the “operating experience” program element 

described in LRA Section B2.1.24. The applicant stated that the Electrical Cables and 

Connections Not Subject to 10 CFR 50.49 EQ Requirements Program is a new program; 

therefore, there is no plant-specific operating experience. The applicant stated, however, that it 

reviewed the plant operating history and found three minor cases of cable aging due to adverse 

environments. It found a lighting power cable with degraded insulation, and it replaced the 

cable. In the second case, it found conduits were run too close to a steam line, and it relocated 

the conduits and mega-ohm tested the cables. No cable degradation was found. In the third 

case, the applicant found water leaking from a pull box. It abandoned the cable and sealed the 

conduit. The applicant further stated that it will evaluate industry and plant-specific operating 

experience in the development and implementation of this program. 

The staff conducted an independent search of the applicant’s condition report database for 

operating experience relevant to the Electrical Cables and Connections Not Subject to 

10 CFR 50.49 EQ Requirements Program. The staff verified that the operating experience 

described in the applicant’s basis document adequately addresses the operating history relative 

to this AMP. 

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, 

therefore, is acceptable. 

UFSAR Supplement Review. LRA Section A1.24 provides the UFSAR supplement for the 

Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Program. 

The staff reviewed this UFSAR supplement description of the program and notes that it 

conforms to the recommended description for this type of program, as described in SRP-LR 
Aging Management Review Results 

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Table 3.6-2. The staff also notes that the applicant committed (Commitment No. 26) to 

implement the Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ 

Requirements Program before entering the period of extended operation. The staff determines 

that the information in the UFSAR supplement is an adequate summary description of the 

program, as required by 10 CFR 54.21(d). 

Conclusion. On the basis of its audit and review of the applicant’s Electrical Cables and 

Connections Not Subject to 10 CFR 50.49 EQ Requirements Program, the staff finds that all 

program elements are consistent with the GALL Report. The staff concludes that the applicant 

has demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP, 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

3.0.3.1.9 Inaccessible Medium Voltage Cables Not Subject to the Environmental Qualification 

Requirements Program Under Title 10, Part 50.49 of the Code of Federal 

Regulations 

Summary of Technical Information in the Application. LRA Section B2.1.26 describes the 

Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 EQ Requirements Program 

as a new program that is consistent with the GALL Report 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 manages localized damage and breakdown of insulation. This damage 

and breakdown leads to electrical failure in inaccessible medium voltage cables that are 

exposed to adverse localized environments caused by significant moisture and significant 

voltage. Therefore, the program is designed to ensure that inaccessible medium voltage cables 

not subject to the EQ requirements of 10 CFR 50.49 and within the scope of license renewal, 

are capable of performing their intended function. 

The applicant also stated that it will inspect all cable manholes that contain in-scope, non-EQ 

inaccessible medium voltage cables for water collection and remove the collected water as 

required. The applicant further stated that it will perform this inspection and water removal 

based on actual plant experience, but at least every two years. In addition, the applicant stated 

that it will test all in-scope, non-EQ inaccessible medium voltage cables routed through 

manholes to provide an indication of conductor insulation condition. The applicant stated that it 

will perform testing at least once every 10 years, and the first test will be completed before the 

period of extended operation. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. 

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of the GALL Report AMP Inaccessible Medium Voltage Cables Not Subject To 

10 CFR 50.49 EQ Requirements. As discussed in the Audit Report, the staff confirmed that 

these elements are consistent with the corresponding elements of the GALL Report AMP. 

Based on its audit, the staff finds that elements one through six of the applicant’s Inaccessible 

Medium Voltage Cables Not Subject to 10 CFR 50.49 EQ Requirements Program are consistent 

with the corresponding program elements of the GALL Report AMP and, therefore, are 

acceptable. 

Operating Experience. LRA Section B2.1.26 summarizes operating experience related to the 

Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 EQ Requirements Program. 

Since this is a new program, there is no plant-specific operating experience. However, the 
Aging Management Review Results 

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applicant stated that a review of relevant operating history records did not reveal any failure of 

inaccessible medium voltage cables. The applicant stated that it has experienced cases where 

medium voltage cable splices have been subjected to water intrusion resulting in low megger 

readings. During manhole walkdowns in 2009, the applicant identified one manhole containing 

water that submerged the cables and a subsequent inspection of connected manholes found 

additional water. The applicant also stated that a review of manhole walkdowns, including 

connected manholes, revealed recurring instances of water intrusion. 

A review of the PVNGS response to GL 2007-01, “Inaccessible or Underground Power Cable 

Failures That Disable Accident Mitigation Systems or Causes Plant Transients,” stated that, for 

inaccessible or underground cables within the scope of 10 CFR 50.56 (the Maintenance Rule), 

no in-service power cable failures were found, but two power cable dielectric strength failures 

were identified. The applicant reworked the cables identified. A subsequent design change 

from motor-operated valves to manual-actuation valves changed the cables’ classification to 

“spare.” The applicant attributed the cable failure to water intrusion. The applicant’s response 

to GL 2007-01 also indicated that PVNGS has experienced degraded cable splices on power 

cables installed in manholes. The applicant repaired the identified splices, per its corrective 

action program. The applicant attributed these failures to water intrusion. 

In response to these findings, the applicant stated that it is evaluating changes to its existing 

manhole inspection, de-watering program, and preventive maintenance basis documents to 

improve program effectiveness. The applicant further, in LRA B2.1.26, that it will evaluate 

industry and plant-specific operating experience in the development and implementation of this 

program. 

The staff reviewed relevant operating history, in the application and during the audit, to 

determine if the applicant reviewed the applicable aging effects and industry operating 

experience and plant-specific operating history documents. As discussed in the Audit Report, 

the staff conducted an independent search of the plant operating history information to 

determine if the applicant had adequately incorporated and evaluated operating history related 

to this program. The staff also confirmed that the applicant addressed inaccessible medium 

voltage cable operating experience identified after issuance of the GALL Report. 

During its review, the staff identified operating experience that warranted additional information 

to ensure the program would be effective in adequately managing aging effects during the 

period of extended operation. This resulted in the issuance of an RAI. By letter dated 

December 29, 2009, the staff issued RAI B2.1.26-1. This RAI requested the applicant to explain 

how PVNGS meets the GALL Report AMP, “Inaccessible Medium Voltage Cables Not Subject 

To 10 CFR 50.49 EQ Requirements” program element, “scope of program,” applicability based 

on plant operating experience that shows that inaccessible medium voltage cables are exposed 

to significant moisture for more than a few days. In addition, the staff requested that the 

applicant describe how it will use plant operating experience and condition reports 

documentation to develop the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 

50.49 EQ Requirements Program to minimize the potential for inaccessible medium voltage 

cable to be exposed to significant moisture (e.g., inspection frequency determination based on 

periodic and event -driven significant moisture exposure and appropriate corrective action). 

The applicant responded by letters, dated February 19, 2010, and May 21, 2010, and stated 

that the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 EQ Requirements 

program element for “scope of program” states, “[t]he scope of this program includes all 

in-scope inaccessible medium voltage cables not subject to the EQ requirements of 10 CFR 

50.49 that are exposed to significant moisture (lasts more than a few days) simultaneously with 

significant voltage (energized greater than 25 percent of the time).” The applicant also stated 

that this is consistent with the GALL Report AMP program element for “scope of program.” The 
Aging Management Review Results 

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applicant revised LRA Sections A1.26 and B2.1.26 to reflect this response as consistent with 

GALL Report AMP definitions of significant voltage and moisture and inspection frequency. 

The applicant also stated that plant operating experience was used in the development of the 

inspection frequency for the AMP Inaccessible Medium Voltage Cables Not Subject to 

10 CFR 50.49 EQ Requirements Program. The LRA AMP element for “preventive action” states 

the following: 

Inspection for water collection within the cable manholes is being performed 

based on plant experience with water accumulation. The inspection frequencies 

will be established to be at least once every 2 years for all manholes within the 

scope of license renewal. If any of the manholes are found to contain water, the 

manholes are pumped dry, the source of the water is investigated, and the 

inspection frequency will be increased based on past experience. 

The applicant further stated that it changed the manhole inspection frequency from a maximum 

five-year interval to two years maximum. The applicant also stated that the preventive 

maintenance program groups manholes into three frequencies of inspections based on their 

history of water intrusion: two weeks, six months, and two years. The two-week preventive 

maintenance task requires inspection of manholes if it has rained 0.3 inches or more within a 

24-hour period since the last time the preventive maintenance was performed. The applicant 

also inspects manholes, grouped into this preventive maintenance task, on a six-month 

frequency to ensure they are always inspected, even during dry periods. The applicant stated 

that under the preventive maintenance program, a manhole will not be moved to the two-year 

reduced frequency inspection interval until it has been found dry for two years. The applicant 

revised LRA Sections A1.26 and B2.1.26 to reflect this response, including operatingexperience based inspection schedules. 

With the information provided by the applicant’s RAI response, the staff finds the Inaccessible 

Medium Voltage Cables Not Subject to 10 CFR 50.49 EQ Requirements Program acceptable 

because the applicant revised LRA Sections A.1.26 and B2.1.26 to be consistent with the 

guidance of the GALL Report AMP such that there is reasonable assurance that it will 

adequately manage inaccessible medium voltage cable exposure to significant moisture during 

the period of extended operation. The staff’s concern described in RAI B2.1.26-1 is resolved. 

The application of AMP XI.E3 to inaccessible medium voltage power cables was based on the 

operating experience available at the time Revision 1 of the GALL Report was developed. 

However, recently -identified industry operating experience indicates that the presence of water 

or moisture can be a contributing factor in inaccessible power cables failures at lower service 

voltages (480V to 2kV). Applicable operating experience was identified in licensee responses to 

Generic Letter (GL) 2007-01, “Inaccessible or Underground Power Cable Failures that Disable 

Accident Mitigation Systems or Cause Plant Transients,” which included failures of power cable 

operating at service voltages of less than 2kV where water was considered a contributing factor. 

The staff has concluded, based on recently -identified industry operating experience concerning 

the failure of inaccessible low voltage power cables (400v to 2kV) in the presence of significant 

moisture, that these cables should be addressed in an AMP. The staff notes that the applicant’s 

AMP does not address these inaccessible low voltage power cables. 

By letter dated September 27, 2010, the staff issued RAI B2.1.26-3 requesting the applicant to: 

1. Provide a summary of the evaluation of recently-identified industry operating experience 

and any plant-specific operating experience concerning inaccessible low voltage power cable 

failures within the scope of license renewal (not subject to 10 CFR 50.49 environmental 

qualification requirements), and how this operating experience applies to the need for additional 

aging management activities at PVNGS. 
Aging Management Review Results 

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2. Discuss how PVNGS will manage the effects of aging on inaccessible low voltage power 

cables within the scope of license renewal and subject to aging management review; with 

consideration of recently-identified industry operating experience and any plant-specific 

operating experience. The discussion should include the AMP description, program elements 

(i.e., scope of program, parameters monitored or inspected, detection of aging effects, and 

corrective actions), and UFSAR summary description to demonstrate reasonable assurance that 

the intended functions of inaccessible low voltage power cables subject to adverse localized 

environments will be maintained consistent with the CLB through the period of extended 

operation. 

3. Evaluate whether the Inaccessible Medium Voltage Program test and inspection 

frequencies, including event-driven inspections, incorporate recent industry and plant-specific 

operating experience for both inaccessible low and medium voltage cables. Discuss how the 

Inaccessible Medium Voltage Program will ensure that future industry and plant-specific 

operating experience will be incorporated into the program. 

The applicant responded by letter dated October 13, 2010, and stated that a review of PVNGS 

operating experience identified two low voltage power cable testing failures reported in 

response to GL 2007-01. The applicant also stated that the two low voltage cables did not meet 

the acceptance criteria for insulation resistance tests and the failures were attributed to water 

intrusion. The applicant further stated that the two low voltage cables have been abandoned. 

These failures are previously discussed in more detail in the GL 2007-01 discussion above. 

The applicant finally stated that no subsequent low voltage power cable failures have been 

identified. The applicant also stated that a review of industry operating experience is part of the 

PVNGS corrective action program. 

As stated above, the applicant's AMP requires an event-driven inspection program and a 2-year 

periodic inspection frequency as part of the Inaccessible Medium Voltage Cables Not Subject to 

10 CFR 50.49 EQ Requirements Program. The applicant stated that the LRA has been revised 

to increase the periodic inspection to at least annually. The applicant also stated that based on 

PVNGS and industry operating experience, the LRA has been revised to increase the periodic 

cable testing to at least once every 6 years. The applicant further stated that the “energized 

greater than 25%” significant voltage criterion was removed such that all in-scope inaccessible 

power cables whether de-energized or energized will be tested. In addition, based on 

plant-specific and industry operating experience, the applicant also revised the LRA to add low 

voltage (480V and above) non-EQ inaccessible power cables and associated manholes into the 

scope of the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 EQ 

Requirements Program. 

Based on the applicant’s responses to RAIs B2.1.26-1 and B2.1.26-3, the staff finds that the 

applicant has appropriately expanded the program scope to include inaccessible low voltage 

power cables (480V to 2kv) and clarified that no inaccessible power cable was excluded based 

on the “significant voltage” criterion. Further, the staff finds that cable insulation testing is 

appropriate because it considers plant-specific and industry operating experience, and the 

actual frequency of testing is based on safety significance and testing history. This approach is 

consistent with the discussion of operating experience in the SRP-LR Section A.1.2.3.10, which 

states that applicants should consider plant-specific and applicable industry operating 

experience for its AMPs. Finally, the staff finds that the applicant’s inspection frequency for 

cable manholes containing inaccessible in-scope power cables is appropriate since it considers 

applicable industry and plant-specific operating experience including cable manhole water 

accumulation. 

The actual periodic frequency of inspection will be established based on inspection results. 

Collected water in manholes is removed to ensure cables are not submerged and inspections 

are performed based on event-driven occurrences such as rain. Given that plant-specific 
Aging Management Review Results 

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operating experience has shown water accumulation in cable manholes within the scope of this 

AMP, an inspection frequency determined through inspection results and additional inspections 

based on event-driven occurrences is acceptable because the applicant’s existing inspections 

will continue to inform the program's inspection frequencies (i.e., to provide feedback for 

changes of the inspection periodicity as appropriate). 

Based on its audit and review of the application, and review of the applicant’s response to 

RAI B2.1.26-1 and B2.1.26-3, the staff finds that operating experience related to the applicant’s 

program demonstrates that it can adequately manage the detrimental effects of aging on SSCs 

within the scope of the program, and that implementation of the program has resulted in the 

applicant taking corrective actions. The staff confirmed that the “operating experience” program 

element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, therefore, is acceptable. 

UFSAR Supplement. LRA Section A1.26 provides the UFSAR supplement for the Inaccessible 

Medium Voltage Cables Not Subject to 10 CFR 50.49 EQ Requirements Program. The staff 

reviewed this UFSAR supplement description of the program against the recommended 

description for this type of program, as described in SRP-LR Table 3.6-2. The staff found that it 

required additional information for its review as discussed below. 

By letter dated December 29, 2009, the staff issued RAI B2.1.26-2 to request that the applicant 

justify why the LRA Appendix A, Section A1.26, “Inaccessible Medium Voltage Cables Not 

Subject To 10 CFR 50.49 Environmental Qualification Requirements” summary description does 

not include definitions of significant moisture, significant voltage, and minimum electrical 

manhole inspection frequencies, consistent with SRP-LR Table 3.6-2. The applicant responded 

by letter dated February 19, 2010, and stated that it has revised LRA Sections A1.26 and 

B2.1.26 to include the definitions of significant moisture, voltage, and inspection frequency. 

With the information provided by the applicant’s RAI response, the staff finds the UFSAR 

supplement acceptable because the applicant revised LRA Section A1.26 to include definitions 

of significant moisture, significant voltage, and inspection frequency to be consistent with the 

guidance of SRP-LR Table 3.6-2. The staff’s concern described in RAI B2.1.26-2 is resolved. 

In addition, as part of its response to RAI B2.1.26-3, the applicant revised LRA Section A1.26 to 

add low voltage power cable (480V or greater) to the scope of its Inaccessible Medium Voltage 

Cables Not Subject to 10 CFR 50.49 EQ Requirements Program. The applicant also clarified 

that no inaccessible power cables were excluded from the program due to the “significant 

voltage” criterion. UFSAR Section A1.26 was further revised by the applicant to include revised 

cable test and manhole inspection frequencies of 6 years and 1 year, respectively. The 

applicant also revised Commitment No. 28 to reflect the changes in inspection and test 

frequencies and increase the scope of the program to include inaccessible power cables of 

480V and above. With the resolution of RAIs B2.1.26-2 and B2.1.26-3, the staff determines that 

the applicant’s UFSAR supplement provides an adequate summary description consistent with 

guidance of SRP-LR Table 3.6. 

Based on the information provided by the RAI responses, the staff finds the UFSAR supplement 

acceptable because the applicant revised LRA Section A1.26 to include definitions of significant 

moisture, significant voltage, inspection and test frequencies, and increased program scope to 

be consistent with the guidance of SRP-LR Table 3.6-2. 

The staff also notes that the applicant committed (Commitment No. 28) to implement the new 

Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 EQ Requirements Program 

before entering the period of extended operation to manage the aging of applicable 

components. 

The staff determines that the information in the UFSAR supplement, as amended, is an 

adequate summary description of the program, as required by 10 CFR 54.21(d). 
Aging Management Review Results 

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Conclusion. On the basis of its review of the applicant’s Inaccessible Medium Voltage Cables 

Not Subject to 10 CFR 50.49 EQ Requirements Program and RAI responses, the staff finds all 

program elements consistent with the GALL Report. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement and RAI 

response for this AMP, and concludes that it provides an adequate summary description of the 

program, as required by 10 CFR 54.21(d). 

3.0.3.1.10 American Society of Mechanical Engineers Section XI, Subsection IWL Program 

Summary of Technical Information in the Application. LRA Section B2.1.28 describes the 

existing ASME Section XI, IWL Program as consistent with the GALL Report AMP XI.S2, 

“ASME Section XI, Subsection IWL.” The LRA states that the program manages cracking, loss 

of material, and increase in porosity and permeability of the concrete containment building and 

post-tensioned system. Included in this inspection program are the concrete containment 

structure (includes all accessible areas of the concrete dome, cylinder walls, and buttresses) 

and the post-tensioning system (includes tendons, end anchorages, and concrete surfaces 

around the end anchorages). The applicant visually examines concrete surface areas for 

indications of distress or deterioration. It measures tendon prestress forces by lift-off and 

examines tendon wires for corrosion or mechanical damage. 

For the inspection interval from August 1, 2001–July 31, 2011, the applicant performs IWL ISIs 

in accordance with the 1992 Edition of ASME Section XI (with 1992 Addendum), Subsection 

IWL, supplemented with the applicable requirements of 10 CFR 50.55a(b)(2) and additional 

commitments. The applicant stated that the IWL ISI Program is consistent with the 2001 edition 

of ASME Section XI, Subsection IWL, including the 2002 and 2003 Addenda. In conformance 

with 10 CFR 50.55a(g)(4)(ii), the applicant updates the IWL ISI Program during each 

successive 120-month inspection interval to comply with the requirements of the latest edition of 

the Code, specified twelve months before the start of the inspection interval, as required by 

10 CFR 50.55a(g)(4)(ii). 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. 

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of the GALL Report AMP, “ASME Section XI, Subsection IWL.” As discussed in the 

Audit Report, the staff confirmed that each element of the applicant’s program is consistent with 

the corresponding elements of the GALL Report AMP except for the “detection of aging effects” 

element. In order to obtain the information necessary to verify if the “detection of aging effects” 

element is consistent with the corresponding elements of the GALL Report AMP, the staff 

issued RAI B2.1.28-2 in a letter dated December 29, 2009. This RAI requested the applicant to 

provide justification for increasing the frequency of concrete surface examination to 10 years, 

plus or minus one year. The GALL AMP ASME Section XI, Subsection IWL Program, “detection 

of aging effects” element and ASME Section IWL-2410 require that the inspections of concrete 

surfaces be performed at one, three, and five years following the structural integrity test. 

Thereafter, the applicant performs inspections at five-year intervals. 

In its response to RAI B2.1.28-2, by letter dated February 19, 2010, the applicant stated that the 

frequency of inspection for the ASME Section XI, Subsection IWL AMP is consistent with ASME 

Section XI Subsection IWL paragraph IWL-2421, “Sites with Multiple Plants.” This paragraph 

allows inspection intervals of every ten years to be staggered, so that the applicant inspects at 

least one unit every five years. Therefore, the existing program is consistent with ASME 

Section XI Subsection IWL and GALL, and no exception is required. 
Aging Management Review Results 

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The staff found the applicant’s response to B2.1.28-2, concerning the inspection of concrete 

surfaces, not acceptable because IWL-2421 only allows the increase in inspection frequency to 

10 years for examinations required by IWL-2524 and IWL-2525, which are requirements for 

examination of tendon anchorage areas and corrosion protection medium and free water in the 

post-tensioning system, respectively. IWL-2410 describes the requirements for concrete 

surface examinations. Therefore, the staff issued a follow-up RAI B2.1.28, in a letter dated 

April 28, 2010, asking the applicant to provide additional information on this issue. 

In its response to RAI B2.1.28-3, in a letter dated May 21, 2010, the applicant stated that during 

the current inspection interval of 10 years, Relief Request (RR)-L3—approved by the NRC in a 

letter to APS dated October 6, 2000—allows a frequency of 10 years for performing Section XI, 

Subsection IWL inspections of the concrete containment exterior surfaces. Subsequent 

intervals will be in accordance with the requirements of ASME Section XI, Subsection IWL 

(five-year frequency), supplemented with the applicable requirements of 10 CFR 50.55a, unless 

an RR is approved to alter these frequencies. The staff finds the applicant’s response to RAI 

B2.1.28-3 acceptable because it bases the containment concrete surface examination 

frequency during the current 10-year interval on NRC approved RR-L3. In addition, after the 

current 10-year interval, the applicant will perform containment exterior surface examination at a 

frequency of five years, as required by IWL-2410. The staff’s concern as described in RAI 

B2.1.28-3 is resolved. 

Operating Experience. LRA Section B2.1.28 summarizes operating experience related to the 

ASME Section XI ISI, IWL Program. The applicant stated that the ASME Section XI, Subsection 

IWL Program inspects the post-tensioned concrete containment in accordance with 10 CFR 

50.55a(b)(2)(viii). When observed degradation could indicate the presence of degradation in 

inaccessible areas, or when the conditions described in 10 CFR 50.55a(b)(2)(viii)(C or D) are 

detected, the ISI Program Engineer is notified, and the ISI Summary Report includes the 

conditions. The applicant further stated that its review of operating experience has identified 

only two instances where observed degradation was significant enough to warrant inclusion in a 

Summary Report. The grease spots identified in these cases are located on the containment 

exterior concrete surface. An engineering evaluation determined that these are cosmetic 

conditions and that there are no detrimental affects to the structure. 

The staff reviewed operating experience information, in the application and during the audit, to 

determine whether the applicant reviewed the applicable aging effects and industry and 

plant-specific operating experience. As discussed in the Audit Report, the staff conducted an 

independent search of the plant operating experience information to determine whether the 

applicant had adequately incorporated and evaluated operating experience related to this 

program. 

The LRA Section B2.1.28 states that the applicant has reviewed the information documented in 

Information Notice (IN) 99-10 concerning degrading of prestress tendon systems in prestressed 

concrete containments for applicability. The LRA further states that the existing tendon integrity 

surveillance procedures are based on the guidance of RG 1.35. The applicant monitors and 

evaluates degradation and conditions, discussed in IN 99-10, PVNGS tendon integrity 

surveillance procedures. A trend of degradation, described in IN 99-10, has not occurred. 

The operating experience section of the LRA Section B2.1.28 states that tendon integrity 

surveillance procedures are based on the guidance of RG 1.35. This statement is not 

consistent with GALL Report, AMP XI-S2, “ASME Section XI, Subsection IWL Program,” 

element 10 (operating experience), which states that implementation of ASME Section XI, 

Subsection IWL, in accordance with 10 CFR 50.55a, is a necessary element of aging 

management for concrete containments through the period of extended operation. Therefore, in 

a letter dated December 29, 2009, the staff issued RAI B2.1.28-1 asking the applicant to explain 

why tendon integrity surveillance procedures conform to RG 1.35 instead of 10 CFR 50.55a. 
Aging Management Review Results 

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In response to the RAI B2.1.28-1, in a letter dated February 19, 2010, the applicant stated that 

LRA Section B2.1.28 addresses the ASME Section XI, Subsection IWL inspections performed in 

accordance with 10 CFR 50.55a. LRA Section B3.3 addresses the Concrete Containment 

Tendon Prestress Program, which manages the loss of tendon prestress and is consistent with 

RG 1.35.1, Proposed Revision 0. The applicant revised LRA Section B2.1.28 to delete the last 

paragraph in the operating experience discussion and replace it with the statement, “[f]or 

discussion of IN 99-10, see Appendix B3.3, Concrete Containment Tendon Prestress.” 

The staff finds the applicant’s response to RAI B2.1.28-1 acceptable because it removed the 

reference to RG 1.35 from LRA Section B2.1.28. In addition, the program description section of 

the LRA ASME Section XI, Subsection IWL Program makes reference to the appropriate 

sections of 10 CFR 50.55a that provide regulations on the scope and frequency of inspections 

for concrete containments. LRA Section B3.3, “Concrete Containment Tendon Prestress 

Program,” addresses the issues reported in IN 99-10, including comparing the regression 

analysis trend lines of the individual lift-off values of prestressing tendons with minimum 

required value (MRV) and predicted lower limit (PLL) for each tendon group. The staff’s 

concerns, identified in RAI B2.1.28-1, are resolved. 

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, 

therefore, is acceptable. 

UFSAR Supplement. LRA Section A1.28 provides the UFSAR supplement for the ASME 

Section XI, Subsection IWL Program. The staff reviewed this UFSAR supplement description of 

the program and notes that it conforms to the recommended description for this type of 

program, as described in SRP-LR Table 3.5-2. The staff also notes that the applicant 

committed (Commitment No. 30) to the ongoing implementation of the existing ASME 

Section XI, Subsection IWL Program to manage the aging of concrete containment and 

post-tensioning system during the period of extended operation. The staff determines that the 

information in the UFSAR supplement is an adequate summary description of the program, as 

required by 10 CFR 54.21(d). 

Conclusion. On the basis of its review of the applicant’s ASME Section XI, Subsection IWL 

Program, the staff finds all program elements consistent with the GALL Report. The staff 

concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR supplement for this AMP, and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d). 

3.0.3.1.11 American Society of Mechanical Engineers Section XI, Subsection IWF Program 

Summary of Technical Information in the Application. LRA Section B2.1.29 describes the 

existing ASME Section XI, IWF Program as consistent with the GALL Report AMP XI.S3, 

“ASME Section XI, Subsection IWF.” The applicant stated that the program provides a 

systematic method for periodic NDE, visual examination, and testing of SSCs to ensure the 

integrity of component pressure boundaries and supports. The applicant stated that the ASME 

Section XI, Subsection IWF program manages loss of material, cracking, and loss of 

mechanical function that could result in loss of intended function for Class 1, 2, and 3 

component supports. There are no ASME Section XI, Subsection IWF, Class MC supports. In 

conformance with 10 CFR 50.55a(g)(4)(ii), the ISI Program is updated during each successive 
Aging Management Review Results 

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120-month inspection interval to comply with the requirements of the latest edition of the ASME 

Code specified by 10 CFR 50.55a(g)(4)(ii). 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. 

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of the GALL Report AMP ASME Section XI, Subsection IWF. As discussed in the 

Audit Report, the staff confirmed that these elements are consistent with the corresponding 

elements of the GALL Report AMP. Based on its audit, the staff finds that elements one 

through six of the applicant’s ASME Section XI ISI, IWF Program are consistent with the 

corresponding program elements of the GALL Report AMP and are, therefore, acceptable. 

Operating Experience. Program element 10, “operating experience” of the LRA ASME 

Section XI, Subsection IWF Program summarizes operating experience related to the ASME 

Section XI ISI, IWF Program. The applicant stated that the plant-specific operating experience 

for the ISI Program has not revealed any implementation issues with the ASME Section XI, 

Subsection IWF Program. The applicant updates the ASME Section XI, Subsection IWF 

Program to account for industry operating experience and periodically revises the program to 

reflect operating experience. The requirement to update the ASME Section XI, Subsection IWF 

Program to reference more recent editions of ASME Section XI at the end of each inspection 

interval ensures that the program reflects enhancements, due to operating experience, that 

have been incorporated into ASME Section XI Code. The applicant further stated that an 

evaluation of the results of the latest ISI examinations indicated that the integrity of the IWF 

support systems has been maintained. The applicant corrected all discrepancies or determined 

"use-as-is" in accordance with work control practices and ASME Section XI Code. 

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicant reviewed the applicable aging effects and industry and plant-specific 

operating experience. As discussed in the Audit Report, the staff conducted an independent 

search of the plant operating experience information to determine whether the applicant had 

adequately incorporated and evaluated operating experience related to this program. 

During the audit, the staff noted that the license renewal aging management industry operating 

experience report for the ASME Section XI, Subsection IWF Program states that the 

degradation identified in IN 2009-04 for constant (spring) supports is not age-related. However, 

the staff noted that the IN discusses possible age-related degradation of mechanical constant 

supports that may adversely affect the analyzed stresses of connected piping systems. To 

address this concern, the staff issued RAI B2.1.29-1 in a letter dated December 29, 2009. In 

this RAI, the staff requested the applicant to explain the basis of the statement made in its basis 

document that the constant supports degradation, identified in IN 2009-04, is not age-related. 

In response to the RAI B2.1.29-1, dated February 19, 2010, the applicant stated that the results 

of the evaluation to date indicate that the degradation of the constant spring supports, as 

identified in IN 2009-04, was not age-related. The apparent cause was a design issue involving 

the configuration of the supporting structural members. Therefore, the AMP does not require 

changes. The applicant further stated that when the ASME Section XI, Subsection IWF 

inspection identified the degradation addressed by IN 2009-04, the scope of inspections was 

expanded in accordance with the requirements of ASME Section XI, Subsection IWF. No other 

constant spring supports were found to have the same condition. It was determined that the 

extent of condition was limited to four supports in each unit—one constant on each main steam 

line in each of the three units. The applicant plans to take corrective actions after the root cause 

evaluation is completed in accordance with the Corrective Action Program. 
Aging Management Review Results 

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The staff finds the applicant’s response to RAI B2.1.29-1 concerning IN 2009-04 acceptable 

because the preliminary results of the root cause evaluation indicate that degradation of the four 

constant steam line supports is not age-related. Apparently, the degradation is due to improper 

design and support selection. Other constant supports of similar design installed in the plant did 

not experience degradation. In addition, the applicant plans to take corrective actions after the 

root cause evaluation is completed. The staff’s concern in RAI B2.1.29-1 is resolved. 

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, 

therefore, is acceptable. 

UFSAR Supplement. LRA Section A1.29 provides the UFSAR supplement for the ASME 

Section XI, Subsection IWF Program. The staff reviewed this UFSAR supplement description of 

the program and notes that it conforms to the recommended description for this type of 

program, as described in SRP-LR Table 3.5-2. The staff also notes that the applicant 

committed (Commitment No. 31) to the ongoing implementation of the existing ASME 

Section XI, Subsection IWF Program to manage aging of applicable component supports during 

the period of extended operation. The staff determines that the information in the UFSAR 

supplement is an adequate summary description of the program, as required by 10 CFR 

54.21(d). 

Conclusion. On the basis of its review of the applicant’s ASME Section XI, Subsection IWF 

Program, the staff finds all program elements consistent with the GALL Report. The staff 

concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR supplement for this AMP, and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d). 

3.0.3.1.12 Title 10 of the Code of Federal Regulations, Part 50, Appendix J Program 

Summary of Technical Information in the Application. LRA Section B2.1.30 describes the 

existing 10 CFR Part 50, Appendix J Program as consistent with the GALL Report AMP XI.S4, 

“10 CFR Part 50, Appendix J.” The LRA further states that the program assures that leakage, 

through the primary containment and systems and components penetrating containment, does 

not exceed allowable leakage rate limits in the TS. The applicant further states that the program 

does not prevent degradation but, instead, provides measures for monitoring to detect 

degradation before a loss of intended function. The applicant is implementing Option B of the 

program, which allows the testing intervals to be performance-based. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. 

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of the GALL Report AMP, “10 CFR Part 50, Appendix J.” As discussed in the Audit 

Report, the staff confirmed that these elements are consistent with the corresponding elements 

of the GALL Report AMP. Based on its audit, the staff finds that elements one through six of the 

applicant’s 10 CFR Part 50, Appendix J Program are consistent with the corresponding program 

elements of the GALL Report AMP, “10 CFR Part 50, Appendix J” and are, therefore, 

acceptable. 
Aging Management Review Results 

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Operating Experience. LRA Section B2.1.30 summarizes operating experience related to the 

10 CFR Part 50, Appendix J Program. The applicant provided the results of the most recent 

Type A, Integrated Leak Rate Tests for all three units. All three units successfully passed the 

last Type A tests. The applicant discussed leakage through a containment isolation valve 

during the Type A test, which led to hardware modifications, procedural changes, and 

preventative maintenance tasks. The applicant further explained that since it has carried out 

these corrective actions, it has not identified any further problems for this or similar valves. The 

applicant also stated that it noted Type B and C test failures due to debris, corrosion products, 

and general degradation of valve seating surfaces, which have been corrected by cleaning or 

adjusting the connecting components. 

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicant reviewed the applicable aging effects and industry and plant-specific 

operating experience. As discussed in the Audit Report, the staff conducted an independent 

search of the plant operating experience information to determine if the applicant had 

adequately incorporated and evaluated operating experience related to this program. The staff 

found that the applicant had adequately identified and incorporated industry and applicable 

plant-specific operating experience. 

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10 and is, 

therefore, acceptable. 

UFSAR Supplement. LRA Section A1.30 provides the UFSAR supplement for the 10 CFR 

Part 50, Appendix J Program. The staff reviewed this UFSAR supplement description of the 

program and notes that it conforms to the recommended description for this type of program, as 

described in SRP-LR Table 3.5-2. The staff also notes that the applicant committed 

(Commitment No. 32) to the ongoing implementation of the existing 10 CFR Part 50, Appendix J 

Program to manage the aging of applicable components during the period of extended 

operation. The staff determines that the information in the UFSAR supplement is an adequate 

summary description of the program, as required by 10 CFR 54.21(d). 

Conclusion. On the basis of its review of the applicant’s 10 CFR Part 50, Appendix J Program, 

the staff finds all program elements consistent with the GALL Report. The staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP, and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

3.0.3.1.13 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Program 

Summary of Technical Information in the Application. LRA Section B2.1.35 describes the new 

Electrical Cable Connections Not Subject to 10 CFR 50.49 EQ Requirements Program that, 

when implemented, will be consistent with license renewal interim staff guidance, 

LR-ISG-2007-02, Changes to Generic Aging Lessons Learned (GALL) Report Aging 

Management Program (AMP) XI.E6, “Electrical Cable Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements.” This program will also be consistent with the GALL 

Report AMP XI.E6, “Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements.” The applicant stated that this AMP manages the effects of 

loosening of bolted connections due to thermal cycling, ohmic heating, electrical transients, 
Aging Management Review Results 

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vibration, chemical contamination, corrosion, and oxidation to ensure that electrical cable 

connections, not subject to the EQ requirements of 10 CFR 50.49 and within the scope of 

license renewal, are capable of performing their intended function. The applicant also stated 

that it performs infrared thermography testing on non-EQ electrical cable connections 

associated with active and passive components within the scope of license renewal. The 

applicant further stated that it will test a representative sample of external connections at least 

once before the period of extended operation using infrared thermography to confirm that there 

are no AERM. The applicant stated that selection of the sample to be tested is based on 

application (medium and low voltage), circuit loading, and environment. The applicant also 

stated that it documents the technical basis for the sample selection. Finally, the applicant 

stated that the one-time testing of a sample of non-EQ electrical cable connectors is 

representative of other non-EQ electrical cable connectors with similar application, circuit 

loading conditions, and environments that are bounded by the testing. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. 

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of the GALL Report AMP, “Electrical Cable Connections Not Subject to 10 CFR 50.49 

EQ Requirements.” As discussed in the Audit Report, the staff confirmed that each element of 

the applicant’s program is consistent with the corresponding element of the GALL Report AMP, 

with the exception of elements “scope of program,” “parameters monitored or inspected,” and 

“detection of aging effects.” The staff’s concern and resolution are discussed below. 

During the audit, the staff determined that the LRA AMP and the associated UFSAR 

Supplement (LRA Appendix A, Section A1.35) were not consistent with the GALL Report AMP, 

“Electrical Cable Connections Not Subject to 10 CFR 50.49 EQ Requirements.” However, the 

LRA AMP and UFSAR Supplement were consistent with the program description and program 

elements of the (at that time) proposed LR-ISG-2007-02 issued for public comment, by letter 

dated August 29, 2007. During the audit, the staff determined that it needed clarification, and 

the staff considered issuing an RAI on the subject. Subsequent to the audit, a notice of 

availability of the final LR-ISG-2007-02 was published in the Federal Register on 

December 23, 2009. The staff, therefore, re-evaluated the LRA AMP and UFSAR Supplement 

based on the changes to the aging management recommendations provided by ISG 2007-02. 

Based on its audit and re-evaluation, the staff finds that elements one through six of the 

applicant’s program are consistent with the corresponding elements of the GALL Report AMP, 

as modified by LR-ISG-2007-02; therefore, the staff’s concern is resolved. 

Operating Experience. LRA Section B2.1.35 summarizes operating experience related to the 

Electrical Cable Connections Not Subject to 10 CFR 50.49 EQ Requirements Program. The 

applicant stated that it routinely performs infrared thermography on electrical components and 

connections. The applicant also stated that a review of plant operating experience identified 

scans where electrical cable connections showed thermal anomalies. The applicant further 

stated that it cleaned and re-tightened these connections. The applicant also stated that these 

thermal anomalies did not cause any loss of equipment intended function. The applicant 

concluded that there is sufficient confidence that the implementation of the Electrical Cable 

Connections Not Subject to 10 CFR 50.49 EQ Requirements Program will provide confirmation 

that supports industry operating experience in that electrical connections have not experienced 

a high degree of failures. 

The staff reviewed relevant operating experience information, in the application and during the 

audit, to determine whether the applicant reviewed the applicable aging effects and industry and 

plant-specific operating experience. As discussed in the Audit Report, the staff conducted 

walkdowns, interviewed the applicant’s staff, and reviewed onsite documentation provided by 
Aging Management Review Results 

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the applicant. The staff also conducted an independent search of the applicant’s operating 

experience information to determine whether the applicant had adequately incorporated and 

evaluated operating experience related to this program. The staff found that the applicant had 

adequately identified and incorporated industry and applicable plant-specific operating 

experience. 

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10 and is, 

therefore, acceptable. 

UFSAR Supplement. LRA Section A1.35 provides the UFSAR supplement for the Electrical 

Cable Connections Not Subject to 10 CFR 50.49 EQ Requirements Program. The staff 

reviewed this UFSAR supplement description of the program and notes that it conforms to the 

recommended description for this type of program as described in SRP-LR Table 3.6-2 and as 

modified by the applicant’s implementation of LR-ISG-2007-02. The staff also noted that the 

applicant committed (Commitment No. 37) to implement the new Electrical Cable Connections 

Not Subject to 10 CFR 50.49 EQ Requirements Program before entering the period of extended 

operation to manage the aging of applicable components. The staff determines that the 

information in the UFSAR supplement, as amended, is an adequate summary description of the 

program, as required by 10 CFR 54.21(d). 

Conclusion. On the basis of its review of the applicant’s Electrical Cable Connections Not 

Subject to 10 CFR 50.49 EQ Requirements Program, the staff finds all program elements 

consistent with the GALL Report and ISG 2007-02. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP, 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

3.0.3.1.14 Metal Enclosed Bus Program 

Summary of Technical Information in the Application. LRA Section B2.1.36 describes the new 

Metal Enclosed Bus (MEB) Program as consistent with the GALL Report AMP XI.E4, “Metal 

Enclosed Bus.” The applicant stated that the MEB Program manages the effects of loose 

connections, embrittlement, cracking, melting, swelling or discoloration of insulation, loss of 

material of bus enclosure assemblies, hardening of boots and gaskets, and cracking of internal 

bus supports to ensure that MEBs within the scope of license renewal are capable of performing 

their intended function. The applicant also stated that MEBs within the scope of this program 

are the buses used during recovery from station blackout (SBO). The applicant further stated 

that it will inspect a sample of the MEB accessible bolted connections will for evidence of 

overheating. It will perform contact resistance testing on a sample of accessible splice plates to 

check for loose connections. It will inspect each bus section for cracks, corrosion, foreign 

debris, excessive dust buildup, and evidence of water intrusion. The applicant will inspect the 

bus insulation for signs of embrittlement, cracking, melting, swelling, or discoloration, which may 

indicate overheating or aging degradation. It will inspect the internal bus supports for structural 

integrity and signs of cracks, and it will inspect the bus enclosure assemblies for loss of material 

due to corrosion and hardening of boots and gaskets. The applicant further stated that it will 

complete the MEB program before the period of extended operation and once every 10 years 

thereafter. 
Aging Management Review Results 

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Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. 

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of the GALL Report AMP, “Metal Enclosed Bus.” As discussed in the Audit Report, 

the staff confirmed that each element of the applicant’s program is consistent with the 

corresponding element of the GALL Report AMP, with the exception of “acceptance criteria” 

discussed below. For this area, the staff determined the need for additional clarification, which 

resulted in the issuance of an RAI. 

The GALL Report uses XI.S6, “Structures Monitoring Program,” for inspection of the exterior of 

MEBs and accessible gaskets and sealant associated with the exterior of MEBs. In the GALL 

Report, “Structures Monitoring Program,” under “acceptance criteria,” it states that, for each 

structure/aging effect combination, the acceptance criteria are selected to ensure that the need 

for corrective actions will be identified before loss of intended functions. The staff reviewed the 

applicant’s plant basis document and noted that, under the “acceptance criteria” element, the 

applicant did not specify the acceptance criteria for inspecting the exterior of MEBs, including 

gasket and sealants. In a letter dated December 29, 2009, the staff issued RAI B2.1.36-1, 

which asked the applicant to provide acceptance criteria for inspecting the exterior of MEBs. In 

response to the staff’s request, the applicant submitted a letter dated February 19, 2010, and 

stated that the acceptance criteria of the LRA MEB AMP has been revised to include 

acceptance criteria for inspecting the exterior of MEBs. The following paragraph has been 

added: 

Visual inspection is the primary method for detecting external corrosion and 

material aging degradation. The exterior of MEBs will be inspected for general 

corrosion. No unacceptable indication of corrosion will be allowed to exist. For 

boots and gaskets discoloration, checkering, and cracking are indications of 

hardening. Physical manipulation during the visual inspection can also be used 

to verify the absence of hardening or cracking. No unacceptable indications of 

cracking will be allowed to exist. The program depends on the judgment and 

experience of the inspector to assess material condition. All unacceptable 

indications as a result of the inspection will be entered into the corrective action 

process. 

The staff finds the applicant’s response acceptable because the applicant revised element six of 

the MEB Program to include acceptable criteria for inspecting the exterior of MEBs. The staff’s 

concern in RAI B2.1.36-1 is resolved. 

Based on its audit and review, the staff finds that elements one through six of the applicant’s 

MEB Program are consistent with the corresponding program elements of the GALL Report 

AMPs and are, therefore, acceptable. 

Operating Experience. LRA Section B2.1.36 summarizes operating experience related to the 

MEB Program. The applicant stated that the MEB Program is a new program; therefore, 

plant-specific operating experience to verify the effectiveness of the program is not available. 

The applicant stated, however, that industry experience has shown that failures have occurred 

on MEBs caused by cracked insulation and moisture or debris buildup internal to the bus. The 

applicant also stated that operating experience has shown that bus connections exposed to 

appreciable ohmic heating during operation may experience loosening due to repeated cycling 

of connected loads. IN 2000-14 “Non Vital Bus Fault Leads to Fire and Loss of Offsite Power” 

and IN 89-64 “Electrical Bus Bar Failures” are examples of non-segregated bus duct failures. 

The applicant stated that a review of relevant plant-specific operating experience has 

determined that there have been no problems resulting in the loss of intended function of the 
Aging Management Review Results 

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MEBs. Sections of the MEBs are inspected every other outage, and thermography is performed 

on the bus at the transformer connections once every six months. The inspection results for the 

MEBs during the last 10 years have revealed that only one splice plate required rework and 

repairs to cracked Noryl sleeving. The applicant also stated that it will evaluate industry and 

plant-specific operating experience in the development and implementation of this program. 

The staff reviewed relevant operating history information, in the application and during the audit, 

to determine if the applicant reviewed the applicable aging effects and industry and 

plant-specific operating experience. As discussed in the Audit Report, the staff conducted an 

independent search of the plant operating experience information to determine whether the 

applicant had adequately incorporated and evaluated operating experience relevant to this 

program. The staff found that the applicant had adequately identified and incorporated industry 

and applicable plant-specific operating experience. 

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10 and is, 

therefore, acceptable. 

UFSAR Supplement. LRA Section A1.36 provides the UFSAR supplement for the MEB 

Program, as amended. The staff reviewed this UFSAR supplement description of the program 

and notes that it conforms to the recommended description for this type of program, as 

described in SRP-LR Table 3.6-2. The staff also notes that the applicant committed 

(Commitment No. 38) to implement the new MEB Program before entering the period of 

extended operation to manage the aging of applicable components. The staff determines that 

the information in the UFSAR supplement is an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

Conclusion. On the basis of its review of the applicant’s MEB Program, the staff finds all 

program elements consistent with the GALL Report. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP, 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

3.0.3.1.15 Fuse Holders Program 

Summary of Technical Information in the Application. LRA Section B2.1.37 describes the new 

Fuse Holders Program as consistent with the GALL Report AMP XI.E5, “Fuse Holders.” The 

applicant stated that the Fuse Holders Program manages thermal fatigue, mechanical fatigue, 

vibration, chemical contamination, and corrosion of the metallic portions of the fuse holders to 

ensure that fuse holders within the scope of license renewal are capable of performing their 

intended function. The applicant also stated that it will test fuse holders that perform a license 

renewal function located outside of active devices for deterioration of the metallic clamps by 

using thermography. The applicant stated that it will perform fuse holder testing at least once 

every 10 years, with the first test completed before the period of extended operation. The 

applicant further stated that it will base the acceptance criteria on temperature rise above the 

reference temperature. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. The staff compared elements one 

through six of the applicant’s program to the corresponding elements of the GALL Report AMP. 

As discussed in the Audit Report, the staff confirmed that these elements are consistent with the 
Aging Management Review Results 

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corresponding elements of the GALL Report AMP, “Fuse Holders.” Based on its audit and 

review of the application, the staff finds that elements one through six of the applicant’s Fuse 

Holders Program are consistent with the corresponding program elements of the GALL Report 

AMP and are, therefore, acceptable. 

Operating Experience. LRA Section B2.1.37 summarizes operating experience related to the 

Fuse Holders Program. The applicant stated that the Fuse Holders Program is a new program; 

therefore, plant-specific operating experience to verify the effectiveness of the program is not 

available. The applicant stated, however, that industry operating experience forms the basis for 

this program and is included in the operating experience element of the corresponding GALL 

Report AMP description. The relative operating experience shows that loosening of fuse 

holders and corrosion of fuse clips are aging mechanisms that, if left unmanaged, can lead to a 

loss of electrical continuity function. The applicant stated that, as additional industry and 

applicable plant-specific operating experience become available, it will evaluate the operating 

experience and appropriately incorporate it into the program. The applicant concluded that 

implementation of the Fuse Holders Program provides reasonable assurance that aging effects 

will be managed such that 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 staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicant reviewed the applicable aging effects and industry and plant-specific 

operating history. As discussed in the Audit Report, the staff conducted an independent search 

of the plant operating experience information to determine if the applicant had adequately 

incorporated and evaluated operating experience related to this program. In addition, the staff 

confirmed that the applicant addressed operating experience identified after issuance of the 

GALL Report. The staff found that the applicant had adequately identified and incorporated 

industry and applicable plant-specific operating experience. 

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program. The staff finds that the applicant’s program 

will appropriately address operating experience related to Fuse Holders and will adequately 

manage the detrimental effects of aging on SSCs within the scope of the program. The staff 

confirmed that the “operating experience” program element satisfies the criterion in SRP-LR 

Section A.1.2.3.10 and is, therefore, acceptable. 

UFSAR Supplement. LRA Section A1.37 provides the UFSAR supplement for the Fuse Holders 

Program. The staff reviewed this UFSAR supplement description of the program and notes that 

it conforms to the recommended description for this type of program as described in SRP-LR 

Table 3.6-2. The staff also notes that the applicant committed (Commitment No. 50) to 

implement the new Fuse Holders Program prior to entering the period of extended operation to 

manage the aging of applicable components. The staff determines that the information in the 

UFSAR supplement is an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

Conclusion. On the basis of its review of the applicant’s Fuse Holders Program, the staff finds 

all program elements consistent with the GALL Report. The staff concludes that the applicant 

has demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP, 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 
Aging Management Review Results 

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3.0.3.1.16 Environmental Qualification of Electrical Components Program 

Summary of Technical Information in the Application. LRA Section B3.2 describes the existing 

EQ of Electrical Components Program as consistent with the GALL Report AMP X.E1, 

“Environmental Qualification (EQ) of Electric Components.” The applicant stated that the EQ 

Program manages the effects of component thermal, radiation, and cyclic aging effects using 

10 CFR 50.49(f) methods. The applicant also states that electrical equipment within the scope 

of the EQ Program is environmentally qualified, in accordance with NUREG-0588, “Interim Staff 

Position on Equipment Qualification of Safety-Related Electrical Equipment,” Category 1 

requirements, as supplemented by 10 CFR 50.49. The applicant further stated that, as required 

by 10 CFR 50.49, EQ components not qualified for the current license term are to be 

refurbished or replaced or have their qualification extended before reaching the aging limits 

established in the evaluation. The applicant also stated that it considers aging evaluations for 

EQ components that specify a qualification of at least 40 years to be time-limited aging analysis 

(TLAAs) for license renewal. SER Section 4.4 provides the staff’s review of these TLAAs. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. The staff compared elements one 

through six of the applicant’s program to the corresponding elements of the GALL Report AMP. 

As discussed in the Audit Report, the staff confirmed that these elements are consistent with the 

corresponding elements of the GALL Report AMP. Based on its audit, the staff finds the that 

elements one through six of the applicant’s EQ of Electrical Components Program are 

consistent with the corresponding program elements of the GALL Report AMP, “EQ of Electrical 

Components” and are, therefore, acceptable. 

Operating Experience. LRA Section B3.2 summarizes operating experience related to the EQ 

of Electrical Components Program. The applicant stated in LRA Section B3.2 that the EQ 

Program complies with 10 CFR 50.49. The applicant also stated that the program includes 

consideration of operating experience and NRC correspondence. Specifically, the applicant 

stated that it evaluates operating experience; system, equipment or component related 

information, as reported through NRC bulletins, notices, circulars, GLs; and Part 21 Notifications 

for applicability to the EQ Program under the Regulatory Interaction and Correspondence 

Control Procedure. The applicant further stated that, when it identifies an emerging industry 

aging issue that affects the qualification of an EQ component, it evaluates the affected 

component and takes appropriate corrective actions. 

During the audit, the staff asked that the applicant provide the results of recent industry or 

applicant EQ self-assessments. The applicant referenced two EQ Program self-assessments, 

dated 2007 and 2008, and an EQ of electrical equipment benchmarking report, also dated 2008. 

The 2007 self-assessment concluded that the EQ Program complied with the requirements of 

10 CFR 50.49. The report noted some improvements, but also some declining trends, since a 

1999 EQ assessment. The report identified recommendations for improvement in EQ training 

for interfacing personnel, procedural interfaces, work backlog, and tracking methods. The 2007 

self-assessment also recommended improvements for file documentation. The 2008 

benchmarking concluded that there were no conditions adverse to quality and no areas of 

improvement with “high” significance. The benchmark did identify one area of improvement as 

“medium,” and it classified 47 areas as “low” significance. The assessment noted each area of 

improvement and proposed recommendations, as appropriate. The applicant generated 

condition reports to address the benchmark findings. 

The 2008 self-assessment concluded that the EQ Program generally met 10 CFR 50.49 

requirements, noting that certain aspects of the program were not consistent with industry 

guidance or procedures. The report noted a lack of specific training, examples of incomplete 

evaluations and procedure use, and limited industry participation by the program engineers. 
Aging Management Review Results 

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Again, the applicant noted areas of improvement and generated condition reports to address the 

self-assessment findings and recommendations. During the audit, the applicant provided the 

disposition of the recommended and corrective actions identified by the self-assessment and 

benchmarking reports. The applicant has completed the majority of the self-assessment and 

benchmarking recommended and corrective actions, with the remaining actions scheduled for 

completion by July 31, 2010. 

The staff reviewed the operating experience information, in the application and during the audit, 

to determine if the applicant reviewed the applicable aging effects and industry and plantspecific operating experience. The staff interviewed the applicant’s technical staff to confirm 

that plant-specific operating experience did not reveal any degradation not bounded by industry 

experience. The operating experience identified in the applicant’s basis documents 

demonstrated that it identified and dispositioned corrective actions to ensure EQ Program 

effectiveness. The staff confirmed that the applicant addressed operating experience identified 

after issuance of the GALL Report. 

Based on its audit and review of the LRA, the staff finds that operating experience related to the 

applicant’s program demonstrates that it can adequately manage the detrimental effects of 

aging on SSCs within the scope of the program, and that implementation of this program has 

resulted in the applicant taking corrective actions. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10 and is, 

therefore, acceptable. 

UFSAR Supplement. LRA Appendix A, Section A2.2 provides the UFSAR supplement for the 

LRA Section B3.2, EQ of Electrical Components Program. The staff reviewed the UFSAR 

supplement description of the program against the recommended description for this type of 

program, as described in SRP-LR Tables 4.4-1 and 4.4-2, and noted that it did not include 

reanalysis attributes consistent with the description of the AMP in LRA Section B3.2 or the 

TLAA in LRA Section 4.4. The GALL Report, “EQ of Electrical Components Program” states 

that reanalysis of an aging evaluation is normally performed to extend the qualification by 

reducing excess conservatism incorporated in the prior evaluation. Important attributes of a 

reanalysis include analytical methods, data collection and reduction methods, underlying 

assumptions, acceptance criteria, and corrective actions (if acceptance criteria are not met). 

By letter dated December 29, 2009, the staff issued RAI 4.4-1 to request that the applicant 

provide justification for not including reanalysis attributes in accordance with 10 CFR 

54.21(c)(1)(iii) in the UFSAR supplement. The applicant responded by letter dated 

February 19, 2010, and stated LRA Sections A2.2 and A3.3 have been revised to include the 

following: 

Reanalysis of aging evaluations to extend the qualifications of components is 

performed on a routine basis as part of the EQ program. Important attributes for 

the reanalysis of aging evaluations include analytical methods, data collection 

and reduction methods, underlying assumptions, acceptance criteria and 

corrective actions (if acceptance criteria are not met). 

With the information provided by the applicant’s RAI response, the staff finds the UFSAR 

supplement acceptable because the applicant revised LRA Sections A2.2 and A3.3 UFSAR 

supplement descriptions to be consistent with the guidance of SRP-LR Table 4.4.2. The staff’s 

concern described in RAI 4.4-1 is resolved. 

The staff also noted that the applicant committed (Commitment No. 40) to re-evaluate existing 

EQ evaluations before the period of extended operation. The staff noted that the applicant’s 

commitment is inconsistent with the license renewal commitments for existing programs in that 

the existing EQ Program is considered an AMP but is not included in the applicant’s 

commitment. The applicant’s commitment requires that existing EQ evaluations be re-evaluated 
Aging Management Review Results 

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before the period of extended operation but not as an ongoing program, consistent with the 

applicant’s Table A4-1 for existing programs. 

By letter dated December 29, 2009, the staff issued RAI 3.2-1 to request that the applicant 

provide justification for not referencing the existing EQ Program or noting that it is to be 

implemented on an ongoing basis. The applicant responded by letter dated February 19, 2010, 

and stated that it revised LRA Table A4-1, Commitment No. 40, to credit the EQ Program for 

license renewal. The applicant also stated that maintaining qualification through the period of 

extended operation requires that it re-evaluate existing EQ evaluations before the period of 

extended operation. With the information provided by the applicant’s RAI response, the staff 

finds the UFSAR supplement commitment acceptable because the applicant revised 

Table A4-1, “License Renewal Commitments” to be consistent with the guidance of SRP-LR 

Table 4.4.2. The staff’s concern described in RAI 4.4-1 is resolved. 

The staff determines that the information in the UFSAR supplement, as amended, is an 

adequate summary description of the program, as required by 10 CFR 54.21(d). 

Conclusion. On the basis of its review of the applicant’s EQ of Electrical Components Program, 

the staff finds all program elements consistent with the GALL Report. The staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP, and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

3.0.3.2 Aging Management Programs Consistent with the Generic Aging Lessons 

Learned Report, with Exceptions or Enhancements 

In LRA Appendix B, the applicant stated that the following AMPs are, or will be, consistent with 

the GALL Report, with exceptions or enhancements: 

 Water Chemistry Program 

 Flow-Accelerated Corrosion Program 

 Bolting Integrity Program 

 Open-Cycle Cooling Water System Program 

 Closed-Cycle Cooling Water System Program 

 Inspection of Overhead Heavy Load and Light Load Handling Systems Program 

 Fire Protection Program 

 Fire Water System Program 

 Fuel Oil Chemistry Program 

 RV Surveillance Program 

 Selective Leaching of Materials Program 

 Buried Piping and Tanks Inspection Program 

 One-Time Inspection of ASME Code Class 1 Small-Bore Piping Program 

 External Surfaces Monitoring Program 

 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program 
Aging Management Review Results 

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 Lubricating Oil Analysis Program 

 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Used in Instrumentation Circuits Program 

 ASME Section XI, Subsection IWE Program 

 Masonry Wall Program 

 Structures Monitoring Program 

 RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear Power 

Plants Program” 

 Metal Fatigue of Reactor Coolant Pressure Boundary Program 

 Concrete Containment Tendon Prestress Program 

For AMPs that the applicant claimed are consistent with the GALL Report, with exception(s) or 

enhancement(s), the staff performed an audit and review to confirm that those attributes or 

features of the program, for which the applicant claimed consistency with the GALL Report, 

were indeed consistent. The staff also reviewed the exception(s) or enhancement(s) to the 

GALL Report to determine if they were acceptable and adequate. The following sections 

document the results of the staff’s audits and reviews. 

3.0.3.2.1 Water Chemistry Program 

Summary of Technical Information in the Application. LRA Section B2.1.2 describes the 

existing Water Chemistry Program as consistent, with an enhancement, with the GALL Report 

AMP XI.M2, “Water Chemistry.” The applicant stated that the program manages cracking, 

denting, loss of material, reduction of heat transfer, and wall thinning in primary and secondary 

water systems. The applicant also stated that the program manages hardening and loss of 

strength; however, by letter dated February 19, 2010, the applicant amended its LRA to delete 

these aging effects from the scope of the Water Chemistry Program because they are not 

included in the GALL Report. In the LRA, the applicant also stated that the scope of the primary 

Water Chemistry Control Program includes the RCS and related auxiliary systems containing 

treated borated water and that the scope of the secondary Water Chemistry Control Program is 

the SG secondary side and the secondary cycle systems. The applicant also stated that the 

methods used to manage water chemistry rely on limiting the concentration of chemistry species 

known to cause corrosion as well as adding chemical species known to inhibit degradation by 

their influence on pH and dissolved oxygen levels. The applicant further stated that in low-flow 

areas or stagnant portions of the systems, where chemical sampling may not be as effective in 

determining local environmental conditions, it will use a one-time inspection of a representative 

group of components to verify the effectiveness of the Water Chemistry Program. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. 

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of the GALL Report, “Water Chemistry Program.” As discussed in the Audit Report, 

the staff confirmed that each element of the applicant’s program is consistent with the 

corresponding element of the GALL Report AMP, with the exception of the “monitoring and 

trending” program element. The “monitoring and trending” program element of the GALL 

Report, “Water Chemistry Program” recommends the use of increased sampling to verify the 

effectiveness of corrective actions whenever corrective actions are taken to address an 

abnormal chemistry condition. However, during the audit, the staff found that the applicant’s 

Water Chemistry Program does not indicate that an increased sampling frequency or other 
Aging Management Review Results 

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measures will be taken when an abnormal chemistry condition occurs. For this element, the 

staff determined the need for additional clarification, which resulted in the issuance of an RAI. 

By letter dated December 29, 2009, the staff issued RAI B2.1.2-1 requesting that the applicant 

provide information on its evaluation of the effectiveness of corrective actions when an 

abnormal chemistry condition occurs. In its response, dated February 19, 2010, the applicant 

stated that it revised its program implementing procedure to add guidance on increasing the 

sampling rate due to an abnormal chemistry condition. The staff finds the applicant’s response 

acceptable because the change to the implementing procedure makes the applicant’s Water 

Chemistry Program consistent with the recommendations in the GALL Report, “Water Chemistry 

Program.” The staff’s concern described in RAI B2.1.2-1 is resolved. 

The staff also reviewed the portions of the “scope of program” and “preventive actions” program 

elements associated with the enhancement to determine if the program will be adequate to 

manage the aging effects for which it is credited. The following section describes the staff’s 

evaluation of this enhancement. 

Enhancement. LRA Section B2.1.2 identifies an enhancement to the “scope of program” and 

“preventive actions” program elements. The applicant stated that it will enhance plant 

procedures to address sampling of effluents from new secondary system cation resins for 

purgeable and non-purgeable organic carbon. However, by letter dated February 19, 2010, the 

applicant amended the LRA to remove this enhancement and to remove the commitment to 

revise the plant procedures. In its letter, the applicant stated that it does not test for purgeable 

and non-purgeable organic carbon from the effluent of new resins used in the secondary system 

because an alternate analysis accomplishes the same result. The applicant also stated that it 

has incorporated this alternative analysis into the plant procedure containing the specifications 

for bulk chemistry. The staff finds removal of the enhancement acceptable because the 

applicant revised its procedures to include the alternate method of testing the cation resin 

effluent, and the applicant’s preventive actions are consistent with the GALL Report’s 

recommendations. The applicant samples water chemistry in accordance with the guidance 

provided in the Electric Power Research Institute (EPRI) water chemistry guidelines. 

Based on its audit and review of the applicant’s response to RAI B2.1.2-1, the staff finds that 

elements one through six of the applicant’s Water Chemistry Program are consistent with the 

corresponding program elements of the GALL Report, “Water Chemistry Program” and are, 

therefore, acceptable. 

Operating Experience. LRA Section B2.1.2 summarizes operating experience related to the 

Water Chemistry Program. The applicant stated that the program is consistent with the EPRI 

water chemistry guidelines and, therefore, benefits from the operating experience captured in 

these guidelines. Concerning primary water chemistry control, the applicant also stated that all 

three units experienced high fluoride concentrations. These high fluoride concentrations 

occurred following several refueling outages, and the applicant determined them to be the result 

of degradation of an eddy current probe conduit that has since been repaired. There have been 

no subsequent discernable releases of fluoride. Regarding secondary water chemistry control, 

the applicant stated that condenser tube plugs were installed in incorrect locations, which led to 

the ingress of chloride, sodium, and sulfate. The applicant took corrective actions to include the 

creation of official tube sheet maps and implementation of administrative controls on installation 

and verification of tube plugs. 

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicant reviewed the applicable aging effects and industry and plant-specific 

operating experience. As discussed in the Audit Report, the staff conducted an independent 

search of the plant operating experience information to determine if the applicant had 

adequately incorporated and evaluated operating experience related to this program. The staff 
Aging Management Review Results 

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found that the applicant had adequately identified and incorporated industry and applicable 

plant-specific operating experience. 

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10 and is, 

therefore, acceptable. 

UFSAR Supplement. LRA Section A1.2, as amended, provides the UFSAR supplement for the 

Water Chemistry Program. By letter dated February 19, 2010, the applicant amended this 

supplement to remove hardening and loss of strength as aging effects managed by the Water 

Chemistry Program. The staff reviewed this UFSAR supplement description of the program, as 

amended, and notes that it conforms to the recommended description for this type of program 

as described in SRP-LR Tables 3.1-2, 3.2-2, 3.3-2, 3.4-2, and 3.5-2. The staff also notes that 

the applicant committed (Commitment No. 4) to the ongoing implementation of the existing 

Water Chemistry Program to manage the aging of applicable components during the period of 

extended operation. The staff determines that the information in the UFSAR supplement, as 

amended, is an adequate summary description of the program, as required by 10 CFR 54.21(d). 

Conclusion. On the basis of its audit and review of the applicant’s Water Chemistry Program, 

the staff determines that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent. The staff concludes that the applicant has demonstrated 

that the effects of aging will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP, and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

3.0.3.2.2 Flow-Accelerated Corrosion Program 

Summary of Technical Information in the Application. LRA Section B2.1.6 describes the 

existing Flow-Accelerated Corrosion (FAC) Program as consistent, with an exception, to the 

GALL Report AMP XI.M17, “Flow-Accelerated Corrosion.” The applicant stated that the FAC 

Program manages wall thinning due to FAC on the internal surfaces of carbon or low alloy steel 

piping, elbows, reducers, expanders, and valve bodies that contain both single-phase and 

two-phase high energy fluids. The applicant further stated that the program uses the EPRI 

computer program CHECKWORKS, along with the implementing guidelines contained in 

Nuclear Safety Analysis Center (NSAC) 202L-R3, “Recommendations for an Effective Flow 

Accelerated Corrosion Program” (NSAC-202L-R3). 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. The staff compared elements one 

through six of the applicant’s program to the corresponding elements of the GALL Report, 

“Flow-Accelerated Corrosion Program.” The staff confirmed that these elements are consistent 

with the corresponding elements of the GALL Report AMP, with an exception to the “scope of 

program” and “detection of aging effects” program elements. 

Exception. LRA Section B2.1.6 states that there is an exception to the “scope of program” and 

“detection of aging effects” program elements. The GALL Report AMP states that in the “scope 

of program” and “detection of aging effects” program elements, the FAC Program relies on 

implementation of EPRI guidelines in NSAC-202L-R2; however, the guidelines provided in the 

PVNGS governing procedure were based on the recommendations in EPRI Guideline 

NSAC-202L-R3. The applicant stated that the new revision of the EPRI guidelines incorporate 
Aging Management Review Results 

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lessons learned and improvements to detection, modeling, and mitigation technologies that 

became available since the publication of NSAC-202L-R2. The staff previously reviewed 

NSAC-202L-R3 (NUREG-1929, “Safety Evaluation Report Related to the License Renewal of 

Beaver Valley Power Station, Units 1 and 2”) and determined that it is equivalent to 

NSAC-202L-R2. In addition, NSAC-202L-R3 allows the use of the averaged band method, 

which is another method for determining the wear of piping components from ultrasonic testing 

(UT) inspection. The staff notes that EPRI documents are created using industry experience 

over several years and finds that the averaged band method provides another method to 

determine the wear of piping components from UT inspections. The staff finds this method to 

be more accurate, thereby resulting in better prediction of remaining life as well as less rework. 

The staff finds the use of EPRI NSAC-202L-R3 acceptable because it will continue to allow the 

applicant to manage wall thinning due to FAC on the internal surfaces of carbon and low alloy 

steel piping and components that contain both single-phase and two-phase high-energy fluids. 

Based on its review, the staff finds that elements one through six of the applicant’s FAC 

Program, with an acceptable exception, are consistent with the corresponding program 

elements of the GALL Report AMP and are, therefore, acceptable. 

Operating Experience. LRA Section B2.1.6 summarizes operating experience related to the 

FAC Program. The applicant stated that their review of work orders from 1996–2009 revealed 

no reported FAC-related leak or rupture from components within the scope of license renewal. 

FAC Program inspections identified wall thinning on most of the work orders, and there were 

cases where the allowable wall thickness was reached and more rigorous stress analyses were 

performed to justify continued service and postpone replacement. The applicant also provided 

the following operational experience: 

For previous refueling outages from R10 through R14 of all three units, 66 to 

166 locations of large-bore systems were originally selected for inspection before 

the outage. The scope was expanded if necessary based on UT findings. An 

inspection location included the subject component (such as an elbow) and its 

adjacent area (such as upstream and downstream piping). For small-bore 

systems, 16 to 52 inspections were selected before the outage. The scope was 

also expanded if necessary based on UT findings. The replacements for each 

outage are scheduled on proactive basis, determined by the projected remaining 

service life based on FAC analyses and by programmatic strategy based on 

industry experience and cost comparison to further inspections. The selections 

of FAC-resistance materials are stainless steel, chrome-moly alloy, or carbon 

steel with trace chromium content > 0.1%. Baseline inspections were performed 

for selected replacement locations of chrome-moly alloy and carbon steel with 

trace chromium content > 0.1%. 

Further review of operating experience by the staff identified a through-wall leak in stainless 

steel piping downstream of a valve in the high-pressure safety injection (HPSI) recirculation line 

to the refueling water tank. The apparent cause evaluation for this issue, completed in 

January 2007, stated that the failure was due to erosion by damaging cavitation, which occurs 

when the system is aligned to perform surveillance testing and to fill the safety injection tanks. 

The apparent cause also identified several corrective actions in the FAC Program to prevent 

recurrence. These initial corrective actions included examining additional components in other 

systems that were identified as susceptible to cavitation erosion, revising the program to inspect 

portions of all three unit’s HPSI recirculation piping every 18 months in order to assess 

degradation rates, and reviewing the current program for identification of erosion damage in 

carbon steel systems due to cavitation. 

The applicant ultimately resolved this issue by implementing a periodic replacement program for 

the affected sections of the HPSI system for all three units at approximately 7.5-year intervals. 
Aging Management Review Results 

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This action removed the associated HPSI components from the scope of license renewal, in 

accordance with 10 CFR 54.21(a)(1)(ii), since they were no longer considered long-lived 

components. In addition, the extent of condition analysis addressed stainless piping and 

components in systems associated with heat removal and implied that the FAC Program would 

address the cavitation erosion issue in carbon steel piping systems. The staff noted, however, 

that the FAC Program’s computer program, CHECWORKS, specifically excludes cavitation 

erosion in its evaluations. 

The staff held conference calls with the applicant on June 17, July 8, and August 27, 2010, to 

discuss the above concern regarding the resolution of the extent of condition of the cavitation 

erosion issue. This issue was previously identified as Confirmatory Item 3.0.3.2.2-1, in the 

staff’s "Safety Evaluation Report With Open Items Related to the License Renewal of the 

PVNGS." 

In its response dated July 30, as supplemented on September 3, 2010, the applicant stated that 

its extent of condition evaluation identified 26 components and associated piping segments that 

were potentially susceptible to cavitation in each unit. The applicant also stated that, of the 

locations inspected to date by ultrasonic testing, only the HPSI recirculation piping discussed 

above exhibited cavitation erosion. The applicant also added Commitment No. 59 to LRA 

Table A4-1, stating that it would complete the inspections of other potentially-susceptible piping 

locations by June 30, 2012, and would incorporate any remaining components found to exhibit 

flow-related degradation into a comparable periodic replacement plan. The applicant further 

stated that a review of stainless steel and carbon steel in-scope components and piping in 

infrequently-operated systems did not identify any other locations potentially susceptible to 

cavitation erosion. This review was initially excluded from the extent of condition evaluation. In 

addition, the applicant provided the bases for determining the replacement interval for the HPSI 

recirculation piping segments. 

The staff finds the applicant’s responses acceptable because the extent of condition reviews 

now account for both stainless steel and carbon steel piping for infrequently-operated, in-scope 

systems, and the applicant committed to complete inspections for other locations susceptible to 

cavitation erosion. Based on the above, the staff finds that past corrective actions have resulted 

in appropriate enhancements and, therefore, the concern described in RAI B2.1.6-1 is resolved, 

and Confirmatory Item 3.0.3.2.2-1 is closed. 

The staff reviewed operating experience information in the application to determine if the 

applicant reviewed the applicable aging effects and industry and plant-specific operating 

experience. The staff conducted an independent search of the plant operating experience 

information to determine if the applicant had adequately incorporated and evaluated operating 

experience related to this program. The staff found that the applicant had adequately identified 

and incorporated industry and applicable plant-specific operating experience. 

Based on its review of the application, and review of the applicant's responses to RAI B2.1.6-1, 

the staff finds that operating experience related to the applicant’s program demonstrates that it 

can adequately manage the detrimental effects of aging on SSCs within the scope of the 

program and that implementation of the program has resulted in the applicant taking corrective 

actions. The staff confirmed that the “operating experience” program element satisfies the 

criterion in SRP-LR Section A.1.2.3.10 and is, therefore, acceptable. 

UFSAR Supplement. LRA Section A1.6 provides the UFSAR supplement for the FAC Program. 

The staff reviewed this UFSAR supplement description of the program and notes that the 

applicant amended Section A1.6, by letter dated June 21, 2010, to include the following 

statement, “[t]he program relies on implementation of the EPRI guidelines of NSAC-202L, 

Recommendations for an Effective Flow Accelerated Corrosion Program.” As amended, the 

UFSAR supplement description of the program conforms to the recommended description for 
Aging Management Review Results 

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this type of program as described in SRP-LR Tables 3.3-2 and 3.4-2. The staff also notes that 

the applicant committed (Commitment No. 8) to the ongoing implementation of the existing FAC 

Program to manage the aging of applicable components with implementation of the 

enhancement before entering the period of extended operation. The staff finds that the 

information in the UFSAR supplement is an adequate summary description of the program, as 

required by 10 CFR 54.21(d). 

Conclusion. On the basis of its audit and review of the applicant’s FAC Program, the staff finds 

that those program elements for which the applicant claimed consistency with the GALL Report 

are consistent. In addition, the staff reviewed the exception and justification and finds that the 

AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. 

The staff concludes that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the UFSAR supplement for this AMP, and concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d). 

3.0.3.2.3 Bolting Integrity Program 

Summary of Technical Information in the Application. LRA Section B2.1.7 describes the 

existing Bolting Integrity Program as consistent, with exceptions, with the GALL Report AMP 

XI.M18, “Bolting Integrity.” The applicant stated that the Bolting Integrity Program manages 

cracking, loss of material, and loss of preload for pressure retaining bolting and ASME 

component support bolting. The applicant also stated that the program includes preload control, 

selection of bolting material, use of lubricants and sealants consistent with EPRI good bolting 

practices, and periodic inspections for indication of aging effects. The applicant further stated 

that three other AMPs supplement the Bolting Integrity Program for managing loss of preload, 

cracking, and loss of material. These three AMPs are: (1) ASME Section XI ISI, Subsections 

IWB, IWC and IWD Program, discussed in LRA Section B2.1.1; (2) ASME Section XI, 

Subsection IWF Program, discussed in LRA Section B2.1.29; and (3) External Surfaces 

Monitoring Program, discussed in LRA Section B2.1.20. 

In addition, the applicant stated that the general practices established in the Bolting Integrity 

Program are consistent with EPRI NP-5067, “Good Bolting Practices,” Volumes 1 and 2, and 

the recommendations in NUREG-1339, “Resolution of Generic Safety Issue 29: Bolting 

Degradation or failure in Nuclear Power Plants.” The applicant also stated that its bolting 

integrity procedures incorporate action items from NUREG-1339; EPRI NP-5769, “Degradation 

and Failure of Bolting in Nuclear Power Plants;” and EPRI TR-104213, “Bolted Joint 

Maintenance and Application Guide.” 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. 

The staff reviewed the applicant’s design guide for bolted joints, as documented in the Audit 

Report, and noted explicit references to NUREG-1339, EPRI NP-5769, and EPRI NP-5067. 

The staff also noted that NUREG-1339, EPRI NP-5769, and EPRI TR-104213, but not EPRI 

NP-5067, are explicitly referenced in the GALL Report AMP, “Bolting Integrity.” The staff further 

noted that the basis section of EPRI TR-104213 describes NP-5067 as a guidance document 

that nuclear power plant personnel have frequently used to develop and improve the plant's 

bolting program. In addition to the other guidance documents, the staff finds the applicant’s use 

of NP-5067 acceptable because TR-104213 endorses NP-5067 as an appropriate guidance 

document for the development of plant bolting programs. Therefore, the staff does not consider 

use of NP-5067 to be an exception to the GALL Report AMP. 
Aging Management Review Results 

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The staff compared elements one through six of the applicant’s program to the corresponding 

elements of the GALL Report AMP, “Bolting Integrity.” As discussed in the Audit Report, the 

staff confirmed that each element of the applicant’s program is consistent with the 

corresponding elements of the GALL Report AMP, with the exception of the “scope of program,” 

“preventive actions,” “parameters monitored or inspected,” “detection of aging effects,” and 

“acceptance criteria” program elements. For these elements, the staff determined the need for 

additional clarification, which resulted in the issuance of the RAIs discussed below. 

The staff noted that in the GALL Report AMP, “Bolting Integrity,” the “scope of program,” 

“parameters monitored or inspected,” “detection of aging effects,” and “acceptance criteria” 

program elements all include recommendations to manage the aging of structural bolting and 

indicate that structural bolting is within the scope of this program. The staff also noted that 

structural bolting is not within the scope of the applicant’s Bolting Integrity Program, and the 

applicant used other AMPs to manage aging of structural bolting. 

By letter dated December 29, 2009, the staff issued RAI B2.1.7-01. This RAI asked the 

applicant to explain why the applicant's use of AMPs different from the Bolting Integrity Program 

was not identified as an exception to the GALL Report, and to identify which AMPs manage 

aging of structural bolting. The staff also asked that the applicant provide justification that the 

credited AMPs are adequate to manage aging effects during the period of extended operation. 

In its response, dated February 19, 2010, the applicant stated that the “detection of aging 

effects” program element of the GALL Report AMP XI.M18 indicates that structural bolts and 

fasteners are inspected under the structures monitoring or equivalent program. In addition, the 

applicant stated that GALL Report, Chapter III, items B2-7, B2-10, B3-7, B4-7, B4-10, and B5-7 

all credit the GALL Report AMP XI.S6, “Structures Monitoring Program,” for managing the aging 

effect of loss of material. The applicant, therefore, does not consider use of the Structures 

Monitoring Program as an exception to the GALL Report AMP, “Bolting Integrity.” The applicant 

also stated that visual inspections performed by the Structures Monitoring Program are capable 

of detecting loss of material and are suitable for managing this aging effect in structural bolting. 

The applicant further stated that it avoids the aging effect of cracking in structural bolting by 

controlling lubricants that may cause contamination leading to cracking. The applicant manages 

the aging effect of loss of preload through the control of preload during installation and 

maintenance activities. 

The staff finds the applicant’s response to RAI B2.1.7-01 acceptable because the applicant’s 

Structures Monitoring Program has established controls, inspections, and processes that are 

capable of managing loss of material and cracking in structural bolting. The staff’s concern 

described in RAI B2.1.7-01 is resolved. 

The program description and the “scope of program” and “preventive actions” program elements 

of the GALL Report AMP XI.M18 reference NUREG-1339, which recommends that thread 

lubricants containing molybdenum disulfide not be used because they increase the potential for 

SCC in bolting, especially high-strength steel bolting. During its review of the applicant’s 

Reactor Head Closure Studs Program, the staff noted that the reactor head stud threads are 

lubricated with a lubricant containing molybdenum disulfide. Based on this information, the staff 

is unclear if the applicant uses thread lubricants containing molybdenum disulfide in other 

bolting applications. 

By letter dated December 29, 2009, the staff issued RAI B2.1.7-03 requesting that the applicant 

clarify if it uses thread lubricants containing molybdenum disulfide for bolting that is included 

within the scope of the Bolting Integrity Program. If it does use such lubricants, the staff also 

requested that the applicant explain why it did not identify such use as an exception to the GALL 

Report and how it will manage the aging effects of concern in NUREG-1339 during the period of 

extended operation. 
Aging Management Review Results 

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In its response, dated February 19, 2010, the applicant stated that review of its maintenance 

procedures and engineering observations confirmed that molybdenum disulfide lubricant is not 

used for bolting within the scope of the Bolting Integrity Program. The applicant stated that the 

common lubricants in its Bolting Integrity Program procedures have no molybdenum disulfide 

ingredients. The applicant further stated that field observations and discussions with 

maintenance and other engineering personnel confirm that molybdenum disulfide has not been 

used. 

The staff finds the applicant’s response acceptable because the applicant’s does not use thread 

lubricants containing molybdenum disulfide for bolting within the scope of the Bolting Integrity 

Program. The staff’s concern described in RAI B2.1.7-03 is resolved. 

The staff also reviewed the portions of the “scope of program,” “parameters monitored or 

inspected,” and “monitoring and trending” program elements associated with the exceptions to 

determine if the program will be adequate to manage the aging effects for which it is credited. 

The staff’s evaluation of these exceptions follows. 

Exception 1. LRA Section B2.1.7 identifies an exception to the “scope of program” program 

element. The applicant stated that the GALL Report Bolting Integrity Program specifies use of 

ASME Code Section XI, 1995 edition with 1996 addenda, but its current ISI Program is based 

on ASME Code Section XI, 2001 edition with 2002 and 2003 addenda. In addition, during the 

period of extended operation, a different ASME Code edition will be used in accordance with the 

provisions of 10 CFR 50.55a. 

The “scope of program” program element for the GALL Report AMP states, “The staff’s 

recommendations and guidelines for comprehensive bolting integrity programs that encompass 

all safety-related bolting are delineated in NUREG-1339, which includes the criteria established 

in the 1995 edition through the 1996 addenda of ASME Code Section XI.” The staff considers 

this reference to ASME Code Section XI, 1995 edition through 1996 addenda, to be a statement 

of historical fact related to issuance of NUREG-1339, not a recommendation that this specific 

ASME Code Section XI edition and addenda should be the basis for an applicant’s Bolting 

Integrity Program. In addition, the GALL Report, in general, references ASME Code Section XI, 

2001 edition with 2002 and 2003 addenda, which is the same edition and addenda on which the 

applicant bases its current ISI Program. On this basis, the staff finds the applicant’s current use 

of ASME Code Section XI, 2001 edition with 2002 and 2003 addenda, and the future use of 

those ASME Code editions and addenda in accordance with the provisions of 10 CFR 50.55a, 

acceptable. 

Exception 2. LRA Section B2.1.7 identifies an exception to the “parameters monitored or 

inspected” program element. The applicant stated that in EPRI NP-5769, the discussion of bolt 

preload indicates that job inspection torque is non-conservative because, for a given fastener 

tension, the torque required to restart the bolt is greater than the torque to which the bolt is 

initially tightened. The applicant further stated that it provides torque values in plant procedures, 

vendor instructions, and design documents or specifications. The torque values provided in 

procedures include consideration of the expected relaxation of the fastener over the life of the 

joint and gasket stress in application of pressure closure bolting. 

The staff determined that the LRA does not provide sufficient information for the staff to clearly 

understand the details of this exception. By letter dated December 29, 2009, the staff issued 

RAI B2.1.7-02. This RAI asked that the applicant provide a clearer description of the exception 

and the differences between the applicant’s Bolting Integrity Program and the recommendations 

in the GALL Report AMP. It also asked that the applicant justify how the actions taken under 

the Bolting Integrity Program are adequate to manage the aging effects, in lieu of the actions 

recommended in the GALL Report AMP. 
Aging Management Review Results 

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In its response, dated February 19, 2010, the applicant amended its LRA by revising the 

description of this exception. The revised description states that loss of preload is not a 

parameter of inspection under the Bolting Integrity Program. The applicant stated that, in lieu of 

inspection for loss of preload, preload is managed by control of preload during installation or 

maintenance activities and that guidance for proper installation torque is provided in plant 

procedures, if not provided by vendor instructions or by design documents or specifications. 

The applicant also stated that EPRI NP-5769, Volume 2, Section 10, indicates that torque 

inspection is non-conservative because, for a given fastener tension, the amount of torque 

required to restart a bolt is not a good indication of the amount of torque applied at installation. 

The applicant further stated that techniques for measuring the amount of bolt tension in an 

assembled joint are both difficult and unreliable, and inspection of preload is not necessary if the 

installation method has been carefully followed. The applicant credits control of preload during 

installation or maintenance activities, in lieu of direct inspection, to determine whether reduction 

in preload may have occurred. 

Based on its review of the LRA and the applicant’s clarification of the exception in response to 

RAI B2.1.7-02, the staff finds this exception acceptable because direct inspection for reduction 

in preload is unreliable, and proper application of preload during installation and maintenance 

activities can adequately manage the aging effect of loss of preload. The staff’s concern 

described in RAI B2.1.7-02 is resolved. 

Exception 3. LRA Section B2.1.7 identifies an exception to the “monitoring and trending” 

program element. Under this program element, the GALL Report, “Bolting Integrity Program,” 

states that if bolting connections for pressure retaining components (not covered by ASME 

Code Section XI) are reported to be leaking, then they may be inspected daily. If the leak rate 

does not increase, the applicant may decrease the inspection frequency to biweekly or weekly. 

However, the applicant stated that for pressure retaining components reported to be leaking, it 

will initiate the corrective action program and identify corrective actions, such as shortening the 

inspection frequency. The applicant bases these corrective actions on the analysis of trending 

data to ensure there is not a loss of intended function of the subject component. The applicant 

also stated that, when deemed necessary, it would implement preventive maintenance 

activities, such as gasket replacement or bolting tightness checks. 

The staff finds this exception acceptable because the applicant’s corrective action program is 

consistent with the requirements of 10 CFR Part 50, Appendix B. The applicant includes 

provisions for reporting, documenting, and evaluating safety significance as well as trending and 

implementing corrective actions for bolted pressure boundary components reported to be 

leaking. In addition, the corrective action program has provisions to determine an appropriate 

inspection frequency for a bolted pressure boundary component found to be leaking. 

Based on its audit and review of the applicant’s responses to RAIs B2.1.7-01, B2.1.7-02, and 

B2.1.7-03, the staff finds that elements one through six of the applicant’s Bolting Integrity 

Program, with acceptable exceptions, are consistent with the corresponding program elements 

of the GALL Report AMP, “Bolting Integrity,” and are, therefore, acceptable. 

Operating Experience. LRA Section B2.1.7 summarizes operating experience related to the 

Bolting Integrity Program. The applicant stated that its Bolting Integrity Program incorporates 

applicable industry experience on bolting issues, including concerns with material control and 

certification, bolting installation and inspection practices, and use of lubricants and injection 

sealants. The applicant also stated that it has reviewed the NRC INs, bulletins, circulars, and 

GLs listed in NUREG-1339. The applicant also stated that a review of plant operating 

experience identified issues with corrosion, missing or loose bolts, inadequate thread 

engagement, and improper bolt application, but there has been no reported case of cracking of 

bolts due to SCC. The applicant further stated that, in all cases, it corrected the identified 

concern or evaluated and accepted as-is, it identified no significant safety events, and it 
Aging Management Review Results 

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implemented additional actions, such as procedural enhancements, as needed to prevent 

recurrence. 

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicant reviewed the applicable aging effects and industry and plant-specific 

operating experience. As discussed in the Audit Report, the staff conducted an independent 

search of the plant operating experience information to determine if the applicant had 

adequately incorporated and evaluated operating experience related to this program. The staff 

found that the applicant had adequately identified and incorporated industry and applicable 

plant-specific operating experience. 

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program. The staff confirmed that the “operating 

experience” program element satisfies the criterion of SRP-LR Section A.1.2.3.10 and is, 

therefore, acceptable. 

UFSAR Supplement. LRA Section A1.7 provides the UFSAR supplement for the Bolting 

Integrity Program. The staff reviewed this UFSAR supplement description of the program and 

notes that it conforms to the recommended description for this type of program, as described in 

SRP-LR Tables 3.1-2, 3.2-2, 3.3-2, and 3.4-2. The staff also notes that the applicant committed 

(Commitment No. 9) to the ongoing implementation of the existing Bolting Integrity Program to 

manage the aging of applicable components during the period of extended operation. The staff 

determines that the information in the UFSAR supplement is an adequate summary description 

of the program, as required by 10 CFR 54.21(d). 

Conclusion. On the basis of its audit and review of the applicant’s Bolting Integrity Program, the 

staff determines that those program elements for which the applicant claimed consistency with 

the GALL Report are consistent. In addition, the staff reviewed the exceptions and justifications 

and determines that the AMP, with the exceptions, is adequate to manage the aging effects for 

which the LRA credits it. The staff concludes that the applicant has demonstrated that the 

effects of aging will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP, and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

3.0.3.2.4 Open-Cycle Cooling Water System Program 

Summary of Technical Information in the Application. LRA Section B2.1.9 describes the 

existing Open-Cycle Cooling Water System Program as consistent, with an enhancement, with 

the GALL Report AMP XI.M20, “Open-Cycle Cooling Water System.” The applicant stated that 

the program is used to manage the loss of material and reduction of heat transfer for those 

components exposed to raw water of the open-cycle cooling water system and that the program 

uses both surveillance and control techniques to manage the aging effects caused by biofouling, 

corrosion, erosion, and silting. The applicant also stated that the surveillance techniques 

include visual inspection and NDE of selected components in combination with thermal and 

hydraulic performance monitoring. The applicant further stated that the control techniques used 

in this program consist of water chemistry controls, flushes, and physical and chemical cleaning. 

Finally, the applicant considered the program consistent with commitments made in response to 

NRC GL 89-13. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. 
Aging Management Review Results 

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The staff compared elements one through six of the applicant’s program to the corresponding 

elements of the GALL Report AMP, “Open-Cycle Cooling Water System.” As discussed in the 

Audit Report, the staff confirmed that each element of the applicant’s program is consistent with 

the corresponding element of the GALL Report AMP, with the exception of the “preventive 

actions” program element. For this element, the staff determined the need for additional 

clarification, which resulted in the issuance of an RAI, discussed below. 

The GALL Report AMP, “Open-Cycle Cooling Water System,” indicates that the system 

components are constructed of appropriate materials and lined or coated to protect the 

underlying metal surfaces from being exposed to aggressive cooling water environments. 

However, during the audit, the staff determined that the applicant did not consider the aging 

issues associated with the internal epoxy coating. By letter dated December 29, 2009, the staff 

issued RAI B2.1.9-1 requesting that the applicant provide information that accurately depicts the 

material arrangement of the open-cycle cooling water system, including linings or coatings. In 

addition, the staff asked the applicant to provide additional information on how the coating 

system is managed for aging effects so that its degradation will not affect the operability of the 

system. 

In its response, dated February 19, 2010, the applicant stated that the coatings are not credited 

for aging management of the underlying material, and the basis document has been revised in 

order to clarify the coating material arrangement for the open-cycle cooling water system. The 

applicant also stated that it conducts visual inspections of the internal surfaces to detect coating 

failure or degradation, which would be evident by corrosion nodules, fresh rust stains, missing 

sections of coatings, or disbonded coatings. The applicant further stated that visual inspection 

procedures for heat exchanger channel heads and tubesheets require identification of any tube 

blockage or fouling. Finally, the applicant stated that the open-cycle cooling water system AMP 

basis document has also been revised to indicate the applicable plant procedures and 

procedure sections including the requirements for coating degradation and heat exchanger tube 

fouling with coating degradation products. 

The staff finds the applicant’s response acceptable because visual inspections will be used to 

identify coating degradation in the open-cycle cooling water system and heat exchanger 

plugging due to coating degradation products, which is consistent with guidance found in the 

GALL Report for ensuring protective coatings are inspected. The staff’s concern described in 

RAI B2.1.9-1 is resolved. 

The staff also reviewed the portions of the “detection of aging effects” and “acceptance criteria” 

program elements associated with the enhancement to determine if the program will be 

adequate to manage the aging effects for which it is credited. The staff’s evaluation of this 

enhancement follows. 

Enhancement. LRA Section B2.1.9, “Open-Cycle Cooling Water System,” identifies an 

enhancement to the “detection of aging effects” and “acceptance criteria” program elements. 

The applicant stated that it will clarify the guidance for conducting heat exchanger and piping 

inspections using NDE techniques and the related acceptance criteria during onsite procedures 

before the period of extended operation. 

The staff reviewed this enhancement against the corresponding program elements in the GALL 

Report, “Open-Cycle Cooling Water System” AMP, XI.M20. This enhancement is consistent 

with the GALL Report, “detection of aging effects” element, which states that nondestructive 

testing is an effective method to measure surface condition and the extent of wall thinning. 

Similarly, the enhancement is consistent with the GALL Report “acceptance criteria” element, 

which is based on the effective cleaning of biological fouling organisms and maintenance of 

protective coatings or linings. The degradation resulting from inadequately performing the 

cleaning of biological fouling organisms and maintaining the protective coatings or linings would 
Aging Management Review Results 

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be detectable with NDE techniques. Based on its review, the staff finds this enhancement 

acceptable because, when implemented before the period of extended operation, it will make 

the program consistent with the recommendations in the GALL Report AMP. 

Based on its audit and review of the applicant’s response to RAI B2.1.9-1, the staff finds that 

elements one through six of the applicant’s Open-Cycle Cooling Water System Program, with 

acceptable enhancement, are consistent with the corresponding program elements of the GALL 

Report AMP, “Open-Cycle Cooling Water System” and are, therefore, acceptable. 

Operating Experience. LRA Section B2.1.9 summarizes operating experience related to the 

open-cycle cooling water system. The applicant stated that, in 1994, it implemented a new 

chemistry control program for the emergency spray pond systems and, from 1994–2006, it 

made additional changes to the program that led to spray pond chemistry that was more 

susceptible to fouling. The applicant also stated that, in 2006, it observed degraded 

performance in the open-cycle cooling water heat exchangers for all three units. The applicant 

took corrective action to return the systems to full operability and to ensure that root cause 

issues were corrected. 

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicant reviewed the applicable aging effects and industry and plant-specific 

operating experience. As discussed in the Audit Report, the staff conducted an independent 

search of the plant operating experience information to determine if the applicant had 

adequately incorporated and evaluated operating experience related to this program. The staff 

found that the applicant had adequately identified and incorporated industry and applicable 

plant-specific operating experience. 

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions. The staff confirmed that the “operating 

experience” program element satisfies the criterion of SRP-LR Section A.1.2.3.10 and is, 

therefore, acceptable. 

UFSAR Supplement. LRA Section A1.9 provides the UFSAR supplement for the Open-Cycle 

Cooling Water System Program. The staff reviewed this UFSAR supplement description of the 

program and notes that it conforms to the recommended description for this type of program, as 

described in SRP-LR Tables 3.2-2, 3.3-2, and 3.4-2. The staff also notes that the applicant 

committed (Commitment No. 11) to enhancing the Open-Cycle Cooling Water System Program 

before entering the period of extended operation. Specifically, the applicant committed to 

clarifying the guidance for inspections using NDE techniques and related acceptance criteria for 

heat exchangers. In addition, the applicant committed to clarifying the guidance for conducting 

piping inspections using NDE techniques and related acceptance criteria. The staff determines 

that the information in the UFSAR supplement is an adequate summary description of the 

program, as required by 10 CFR 54.21(d). 

Conclusion. On the basis of its audit, answers to the RAI, and review of the applicant’s 

Open-Cycle Cooling Water System Program, the staff determines that those program elements 

for which the applicant claimed consistency with the GALL Report are consistent. In addition, 

the staff reviewed the enhancement and confirmed that its implementation through Commitment 

No. 11, prior to the period of extended operation would make the existing AMP consistent with 

the GALL Report AMP to which it was compared. The staff concludes the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP, 
Aging Management Review Results 

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and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

3.0.3.2.5 Closed-Cycle Cooling Water System 

Summary of Technical Information in the Application. LRA Section B2.1.10 describes the 

existing Closed-Cycle Cooling Water System Program as consistent, with exceptions and 

enhancements, with the GALL Report AMP XI.M21, “Closed-Cycle Cooling Water System.” The 

applicant stated that the program manages loss of material, cracking, and reduction in heat 

transfer for components in closed-cycle cooling water systems. In addition, the program 

includes both the maintenance of corrosion inhibitor concentration at the prescribed level and 

periodic testing and inspections to evaluate system and component performance. The applicant 

also stated that it maintains water chemistry, consistent with the EPRI Closed-Cycle Cooling 

Water Chemistry Guidelines, using nitrite as an iron corrosion inhibitor, tolyltriazole as a copper 

corrosion inhibitor, and glutaraldehyde as a biocide and as a means to control pH. The 

applicant further stated that the inspection processes include visual, eddy-current, and 

ultrasonic methods, and periodic testing includes functional demonstrations and monitoring of 

the thermal and hydraulic performance tests. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. 

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of the GALL Report, “Closed-Cycle Cooling Water System.” As discussed in the Audit 

Report, the staff confirmed that each element of the applicant’s program is consistent with the 

corresponding element of the GALL Report, “Closed-Cycle Cooling Water System,” with the 

exception of the “scope of program” program element. For this element, the staff determined 

the need for additional clarification, which resulted in the issuance of an RAI, discussed below. 

The GALL Report AMP XI.M21 recommends that the program include preventive measures to 

minimize corrosion and SCC as well as testing and inspection to monitor the effects of corrosion 

and SCC on the intended function of the components scoped into the license renewal process. 

However, during its audit, the staff noted that the applicant’s Closed-Cycle Cooling Water 

System Program does not conduct internal inspections or performance testing for all 

components within the scope of license renewal under 10 CFR 54.4(a)(2). 

By letter dated December 29, 2009, the staff issued RAI B2.1.10-1 requesting that the applicant 

provide justification for limiting the internal inspections and performance testing of components 

based upon the criteria that was used to scope these components into the license renewal 

process. In its response, dated February 19, 2010, the applicant stated that for each 

component, it selects a specific non-chemistry monitoring technique, from among those 

provided in EPRI TR-107396, to reflect the actual conditions of the component type, 

configuration, and license renewal intended functions to be managed. The applicant also stated 

that for those components with the function of material integrity, such as pressure boundary or 

leakage barrier, it verifies the effectiveness of the water chemistry conditions by the 

non-chemical monitoring technique of inspection, as provided in the EPRI document, Section 8, 

“Additional Monitoring Techniques.” The applicant further stated that for components with heat 

transfer functions, it will verify the effectiveness of the chemical conditions through NDE 

techniques, heat transfer performance testing, or flow monitoring, as described in the EPRI 

document. 

The staff finds the applicant’s response acceptable because the applicant conducts 

non-chemistry monitoring techniques to ensure the effectiveness of the water chemistry 

conditions, which is consistent with the GALL Report guidance. The staff’s concern described in 

RAI B2.1.10-1 is resolved. 
Aging Management Review Results 

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The staff also reviewed the portions of the “preventive actions,” “parameters monitored or 

inspected,” “detection of aging effects,” “monitoring and trending,” and “acceptance criteria,” 

program elements associated with the exceptions and enhancements to determine whether the 

program will be adequate to manage the aging effects for which it is credited. The staff’s 

evaluation of these exceptions and enhancements follows. 

Exception 1. LRA Section B2.1.10 identifies an exception to the “preventive actions” program 

element. In the GALL Report AMP, this program element recommends that the materials used 

in the closed-cycle cooling water system be appropriate for the type of service. The applicant 

stated that the essential cooling water system for each unit uses an aluminum “window” as the 

pressure boundary material between the closed-cycle cooling water and an ionization detector. 

The applicant also stated that its chemical treatment program does not include controls, 

described in EPRI TR–107396, that are appropriate for aluminum. The applicant further stated 

that it would maintain the integrity of the aluminum windows using the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program. 

The staff reviewed this exception to the GALL Report and noted that the applicant took the 

exception because it considered that its current water chemistry guidelines would not effectively 

manage the aging of aluminum components. However, further discussion with the applicant 

during the audit indicated that the material may not be aluminum. By letter dated 

December 29, 2009, the staff issued RAI B2.1.10-2 requesting that the applicant provide 

information on the actual material of the “window.” If the “window” is not aluminum, the staff 

asked the applicant to provide additional information on the AMP to be used. If the window is 

aluminum, the staff asked the applicant to provide the technical basis for the adequacy of the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to 

inspect the aluminum component. In its response, dated February 19, 2010, the applicant 

stated that the window material is aluminum and that its strongly-bonded, surface oxide film 

protects it from general corrosion. The applicant also stated that corrosion of aluminum usually 

manifests in the form of pitting corrosion and that it controls the chloride concentration in the 

closed-cycle cooling water system so that rapid loss of material from pitting is not anticipated. 

The applicant further stated that it will use visual inspection, in accordance with the Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program, to manage the age 

related degradation of the aluminum window component. 

The staff finds the program exception acceptable because the applicant is using a visual 

inspection technique, which is appropriate for managing loss of material due to pitting for the 

aluminum window. The staff’s concern described in RAI B2.1.10-2 is resolved. 

Exception 2. LRA Section B2.1.10 identifies an exception to “parameters monitored or 

inspected” and “monitoring and trending” program elements. In the GALL Report Closed-Cycle 

Cooling Water System AMP, the “parameters monitored or inspected” program element 

recommends that testing and inspection be conducted as described in EPRI TR–107396 and 

that parameters monitored for pumps include flow, suction pressure, and discharge pressure. 

The “parameters monitored or inspected” program element of the GALL Report AMP XI.M21 

also recommends that the parameters monitored for heat exchangers should include flow, inlet 

and outlet temperatures, and differential pressure. The “monitoring and trending” element of the 

GALL Report AMP further recommends that visual inspections and performance or functional 

tests should be performed to confirm the effectiveness of the closed-cycle cooling water 

program. The applicant stated the following exceptions to the GALL Report Closed-Cycle 

Cooling Water System AMP: 

 Heat exchangers are not monitored for differential pressure for the 

essential cooling water, spent fuel cooling and cleanup, and shutdown 

cooling heat exchangers systems. 
Aging Management Review Results 

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 The circulating pumps for the essential chilled water and essential cooling 

water system will not be subject to periodic internal visual inspections or 

casing NDE. 

 The ventilation cooling coils in the essential chilled water system are not 

monitored for differential pressure or subject to visual inspection. 

 The diesel generator jacket water heat exchanger, turbo air intercooler, 

turbocharger, and governor lube oil cooler are not individually monitored 

for flow, inlet and outlet temperatures, and differential pressure, and they 

are not visually inspected internally. 

 The reactor coolant hot leg sample cooler heat exchanger is not 

periodically inspected or tested. 

 Heat exchanger parameters are not monitored. Performance monitoring 

and inspections are not conducted to manage reduction in heat transfer 

for the letdown heat exchanger, auxiliary steam vent condenser, auxiliary 

steam radiation monitor cooler, cooling coils for the normal heating, 

ventilation, and air conditioning (HVAC) units, SG sampling coolers (hot 

leg, cold leg, downcomer blowdown), pressurizer steam space and surge 

line sample coolers, and safety injection sample coolers. 

The staff reviewed this exception to the GALL Report and noted that the applicant took the 

exception because these systems were scoped into the LRA for reasons other than being 

safety-related. In some cases, the applicant indicated that it took other measures, such as 

conducting visual inspections of other components made out of the same material in the same 

environment. However, the staff noted that there were many instances that the applicant 

indicated it did not need to conduct visual inspection or other performance testing of 

components and did not provide alternatives to managing the aging of these components. 

By letter dated December 29, 2009, the staff issued RAI B2.1.10-3 requesting that the applicant 

provide additional information for three items. The first item questioned why the applicant is not 

using an inspection technique to monitor loss of material for specific heat exchangers that do 

not have a license renewal heat transfer intended function, and how water chemistry control 

alone is adequate to manage this aging effect. In its response, dated February 19, 2010, the 

applicant stated that it verifies chemistry control measures for these heat exchangers (that do 

not have license renewal heat transfer functions but are evaluated as a pressure boundary or 

leakage barriers) through the visual inspection of internal surfaces of components made of 

similar materials and exposed to similar environments. The applicant also stated that the 

Closed-Cycle Cooling Water System Program basis document has been revised to identify the 

applicable plant procedures, procedure sections, and their inspection requirements for these 

internal visual inspections. The applicant further stated that it modified LRA Section B2.1.10 to 

reflect these additional changes. 

The second item in RAI B2.1.10-3 requested that the applicant clarify how water chemistry 

control, in combination with preventative maintenance and performance testing, will adequately 

manage the aging affects associated with the ventilation cooling coils, especially for loss of 

material. In its response, dated February 19, 2010, the applicant stated that it will verify the 

effectiveness of the water chemistry control measures for the ventilation cooling coils by 

performance testing, which may include, but is not limited to, cooling coil performance tests to 

verify that the required flow rates are achieved. The applicant stated that the ventilation coils 

are not subject to visual inspection or NDE because of their internal diameter and geometry. 

The applicant further stated that the GALL Report indicates that performance testing is one of 

the specific non-chemistry monitoring techniques provided in EPRI TR-107396, and these 
Aging Management Review Results 

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non-chemistry tests are considered preventative maintenance to ensure that the license renewal 

intended functions are maintained during the period of extended operation. 

The third item in RAI B2.1.10-3 requested that the applicant provide additional information 

describing why it is not using an inspection technique to monitor the aging effect of the reactor 

coolant hot leg sample cooler and how water chemistry control alone is adequate to managing 

the aging degradation. In its response, dated February 19, 2010, the applicant stated that the 

reactor coolant hot leg sample cooler is a sealed unit, not subject to opening for routine 

inspection or maintenance. The applicant also stated that it will evaluate the effectiveness of 

the water chemistry control measures for this heat exchanger by conducting visual inspection of 

internal surfaces for selected components fabricated of similar materials and exposed to 

closed-cycle cooling water of the same corrosion inhibitor program. The applicant further stated 

that it revised the Closed-Cycle Cooling Water System Program basis document to indentify the 

plant procedures, procedure sections, and inspection requirements for the internal surfaces of 

the representative components to serve as the leading indicators of the effectiveness of water 

chemistry control. 

Based on its review of the LRA and the information provided in the applicant’s response to 

RAI B2.1.10-3, the staff finds the exception acceptable because the applicant will use 

non-chemistry monitoring techniques to verify the effectiveness of its water chemistry control. 

The applicant will conduct inspections of components of the same material in the same 

environment as the components not being inspected as well as performance testing of 

ventilation cooling coils in accordance with the guidance in EPRI TR-107396, which is 

consistent with the guidance provided in the GALL Report. The staff’s concerns described in 

RAI B2.1.10-3 are resolved. 

Exception 3. LRA Section B2.1.10 identifies an exception to “preventive actions,” “parameters 

monitored or inspected,” “detection of aging effects,” “monitoring and trending,” and “acceptance 

criteria” program elements. In the GALL Report AMP, “Closed-Cycle Cooling Water System,” 

these program elements recommend the use of EPRI TR–107396, Revision 0, “Closed Cooling 

Water Chemistry Guidelines.” However, the applicant indicated that it bases the Closed-Cycle 

Cooling Water System Program on Revision 1 of this document, published in 2004. 

The staff reviewed this exception to the GALL Report and noted that the applicant took the 

exception because the EPRI Closed Cooling Water Chemistry Guidelines have been updated 

from the version cited in the GALL Report. The staff finds this exception acceptable because 

the newer version of the above EPRI guidelines contains all previous requirements and provides 

more recent operating experience information. 

Enhancement. LRA Section B2.1.10 identifies an enhancement to the “preventive actions” and 

“acceptance criteria” program elements. The applicant indicated that this enhancement 

expands on the existing program elements by incorporating the guidance of EPRI TR–107396, 

“Closed-Cooling Water Chemistry Guidelines,” with respect to water chemistry control for 

frequency of sampling and analysis, normal operating limits, action level concentrations, and 

time for implementing corrective actions upon attainment of action levels. 

The staff reviewed this enhancement against the corresponding program elements in the GALL 

Report AMP. The staff finds the applicant’s enhancement acceptable because it will make the 

program consistent with the GALL Report recommendation by setting the appropriate limits for 

water chemistry control with respect to frequency of sampling and analyses, normal operating 

limits, and action level concentrations. 

Based on its audit and review of the applicant’s responses to RAIs B2.1.10-1, B2.1.10-2, and 

B2.1.10-3, the staff finds that elements one through six of the applicant’s Closed-Cycle Cooling 

Water System Program, with acceptable exceptions and enhancement, are consistent with the 
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corresponding program elements of the GALL Report Closed-Cycle Cooling Water System AMP 

and are, therefore, acceptable. 

Operating Experience. LRA Section B2.1.10 summarizes operating experience related to the 

Closed-Cycle Cooling Water System Program. The applicant stated that there has been no 

evidence of significant fouling or loss of material that resulted in the loss of intended function for 

most of the closed-cycle cooling systems. However, the applicant also stated that in 2001, it 

identified elevated levels of chlorides and sulfates in the Unit 3 essential cooling water system 

due to a leak in a heat exchanger tube from the essential spray pond (ESP) system and that 

corrosion had occurred from the open-cycle cooling water side of the heat exchanger. The 

applicant plugged the tube to correct the leakage and expanded the inspection program to 

include100 percent of the other units’ essential cooling water heat exchange tubes. The 

applicant stated that this inspection revealed no further corrosion. 

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicant reviewed the applicable aging effects and industry and plant-specific 

operating experience. As discussed in the Audit Report, the staff conducted an independent 

search of the plant operating experience information to determine if the applicant had 

adequately incorporated and evaluated operating experience related to this program. The staff 

found that the applicant had adequately identified and incorporated industry and applicable 

plant-specific operating experience. 

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10 and is, 

therefore, acceptable. 

UFSAR Supplement. LRA Section A1.10 provides the UFSAR supplement for the Closed-Cycle 

Cooling Water System Program. The staff reviewed this UFSAR supplement description of the 

program and notes that it conforms to the recommended description for this type of program, as 

described in SRP-LR Tables 3.1-2, 3.2-2, 3.3-2, and 3.4-2. The staff also notes that the 

applicant committed (Commitment No. 12) to the ongoing implementation of the existing 

Closed-Cooling Water System Program and to the enhancement of the Closed-Cycle Cooling 

Water System Program before entering the period of extended operation. Specifically, the 

applicant committed to incorporating the guidance in the EPRI TR-107396 with respect to water 

chemistry control for frequency of chemistry sampling, normal operating chemistry limits, action 

level concentrations, and time limits for implementing corrective actions if the action levels are 

reached. The staff determines that the information in the UFSAR supplement is an adequate 

summary description of the program, as required by 10 CFR 54.21(d). 

Conclusion. On the basis of its audit and review of the applicant’s Closed-Cycle Cooling Water 

System Program, the staff determines that those program elements for which the applicant 

claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the 

exceptions and their justifications, and determines that the AMP, with the exceptions, is 

adequate to manage the aging effects for which the LRA credits it. The staff reviewed the 

enhancement and confirmed that its implementation through Commitment No. 12, prior to the 

period of extended operation, would make the existing AMP consistent with the GALL Report 

AMP to which it was compared. The staff concludes that the applicant has demonstrated that 

the effects of aging will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP, and 

concludes that it provides an adequate summary description of the program, as required by 10 

CFR 54.21(d). 
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3.0.3.2.6 Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems Program 

Summary of Technical Information in the Application. LRA Section B2.1.11 describes the 

existing Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems Program as consistent, with an enhancement, with the GALL Report AMP XI.M23, 

“Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems.” 

The applicant stated that the Inspection of Overhead Heavy Load and Light Load (Related to 

Refueling) Handling Systems Program manages loss of material for all cranes, trolley and hoist 

structural components, fuel handling equipment, and applicable rails within the scope of license 

renewal. The applicant also stated that visual inspections will be used to assess conditions, 

such as loss of material due to corrosion and visible signs of rail wear. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. The staff compared elements one 

through six of the applicant’s program to the corresponding elements of the GALL Report AMP. 

As discussed in the Audit Report, the staff confirmed that these elements are consistent with the 

corresponding element of the GALL Report AMP. The staff also reviewed the portions of the 

“detection of aging effects” program element associated with the enhancement to determine 

whether the program will be adequate to manage the aging effects for which it is credited. The 

staff’s evaluation of this enhancement follows. 

Enhancement. LRA Section B2.1.11 identifies an enhancement to the “detection of aging 

effects” program element. Specifically, the applicant stated that it will enhance to inspect for 

loss of material due to corrosion or rail wear. The “detection of aging effects” program element 

of the GALL Report AMP states that crane rails and structural components are visually 

inspected on a routine basis for degradation. The staff finds this enhancement acceptable 

because, when implemented, it will make this existing program consistent with the 

recommendations in the GALL Report AMP. 

Based on its audit, the staff finds that elements one through six of the applicant’s Inspection of 

Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program, with 

acceptable enhancement, are consistent with the corresponding program elements of the GALL 

Report AMP and are, therefore, acceptable. 

Operating Experience. LRA Section B2.1.11 summarizes operating experience related to the 

Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems 

Program. The applicant stated that it has identified no occurrences of unacceptable corrosion of 

components within the scope of the program. Additionally, the applicant stated that since it has 

not operated any cranes, hoists, trolleys, or fuel-handling equipment outside of their design 

limits or beyond their design lifetime, no fatigue-related structural failures have occurred. 

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicant reviewed the applicable aging effects and industry and plant-specific 

operating experience. As discussed in the Audit Report, the staff conducted an independent 

search of the plant operating experience information to determine if the applicant had 

adequately incorporated and evaluated operating experience related to this program. The staff 

found that the applicant had adequately identified and incorporated industry and applicable 

plant-specific operating experience. 

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program. The staff confirmed that the “operating 

experience” program element satisfies the criterion of SRP-LR Section A.1.2.3.10 and is, 

therefore, acceptable. 
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UFSAR Supplement. LRA Section A1.11 provides the UFSAR supplement for the Overhead 

Heavy Load and Light Load (Related to Refueling) Handling Systems Program. The staff 

reviewed this UFSAR supplement description of the program and notes that it conforms to the 

recommended description for this type of program, as described in SRP-LR Table 3.3-2. The 

staff also notes that the applicant committed (Commitment No. 13) to enhancing the Overhead 

Heavy Load and Light Load (Related to Refueling) Handling Systems Program before entering 

the period of extended operation. Specifically, the applicant committed to using the existing 

program and, before the period of extended operation, enhancing procedures to inspect for loss 

of material due to corrosion or rail wear. The staff determines that the information in the UFSAR 

supplement is an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

Conclusion. On the basis of its audit and review of the applicant’s Inspection of Overhead 

Heavy Load and Light Load (Related to Refueling) Handling Systems Program, the staff 

determines that those program elements for which the applicant claimed consistency with the 

GALL Report are consistent. In addition, the staff reviewed the enhancement and confirmed 

that its implementation through Commitment No. 13, prior to the period of extended operation, 

would make the existing AMP consistent with the GALL Report AMP to which it was compared. 

The staff concludes that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the UFSAR supplement for this AMP, and concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d). 

3.0.3.2.7 Fire Protection Program 

Summary of Technical Information in the Application. LRA Section B2.1.12 describes the Fire 

Protection Program as an existing program that is consistent, with exceptions and 

enhancements, with the GALL Report AMP XI.M26, “Fire Protection.” The applicant stated that 

the program manages loss of material for fire rated doors, fire dampers, diesel-driven fire 

pumps, and the carbon dioxide and halon fire suppression systems, cracking, spalling, and loss 

of material for fire barrier walls, ceilings, and floors, and hardness and shrinkage due to 

weathering of fire barrier penetration seals. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. 

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of the GALL Report “Fire Protection” AMP. As discussed in the Audit Report, the staff 

confirmed that each element of the applicant’s program is consistent with the corresponding 

element of the GALL Report AMP, with the exception of the “parameters monitored or 

inspected,” and “acceptance criteria” program elements. For these elements, the staff 

determined the need for additional clarification, which resulted in the issuance of RAIs. 

The “parameters monitored or inspected” program element of the GALL Report AMP, “Fire 

Protection,” recommends that the diesel-driven fire pump be observed during performance tests 

such as flow and discharge tests, sequential starting capability tests, and controller function 

tests for detection of any degradation of the fuel supply line. The “acceptance criteria” program 

element of the GALL Report AMP, “Fire Protection,” recommends that no corrosion is 

acceptable in the fuel supply line for the diesel-driven fire pump. The staff noted that the 

applicant’s basis document for this program indicated that Fuel Oil Chemistry and External 

Surface Monitoring Programs manage the fuel oil supply line. The PVNGS basis document also 

states to visually inspect the diesel fuel oil supply line for signs of degradation and references 

the source of the inspection as the LRA. It is not clear to the staff which program or procedure 
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the applicant uses for performing this inspection and where the applicant specified the 

acceptance criterion for the inspection. 

By letter dated December 29, 2009, the staff issued RAI B2.1.12-1 requesting that the applicant 

confirm which program is used to perform this inspection and identify where the acceptance 

criterion for the inspection is specified. 

In its response, dated February 19, 2010, the applicant stated that the Fuel Oil Chemistry 

Program manages the aging of internal surfaces of components exposed to fuel oil, including 

the diesel-driven fire pump fuel oil supply piping line. Further, the applicant stated that the 

One-Time Inspection Program, consistent with the GALL Report, verifies the effectiveness of 

this program. The applicant also stated that the One-Time Inspection Program was revised to 

include the fuel oil supply line of one diesel-driven fire pump in the sample of components to be 

inspected. The applicant stated that the External Surfaces Monitoring Program manages the 

aging of external surfaces of components associated with the diesel-driven fire pump, and is 

consistent with the GALL Report. 

The applicant stated that, consistent with the GALL Report AMP, “Fire Protection,” plant 

procedures require demonstration of the diesel-driven fire pump operability by starting and 

running each pump on a monthly basis. This test verifies that the fuel oil day tank is above the 

minimum level and detects degradation of the fuel oil supply line by visual inspection while the 

diesel driven fire pump is in operation. The applicant also stated that it revised the Fire 

Protection Program basis document to clarify the AMPs applied to manage the aging of the 

diesel-driven fire pump. 

The staff noted that the GALL Report, Chapter VII.G, “Auxiliary Systems - Fire Protection,” 

recommends the Fuel Oil Chemistry and One-Time Inspection Programs to manage the aging 

effect of loss of material for piping exposed to fuel oil. The staff also noted that for external 

surfaces, the GALL Report recommends the External Surface Monitoring Program. The staff 

finds the applicant’s response acceptable because it manages the aging effect of loss of 

material on the internal and external surfaces of the fuel oil supply line consistent with the GALL 

Report. In addition, the applicant includes the fuel oil supply line in the sample of components 

to be inspected in the One-Time Inspection Program, it performs the testing of the diesel-driven 

fire pump consistent with the GALL Report Fire Protection AMP, and it revised the Fire 

Protection Program basis document to clarify the AMPs applied to manage the aging of the 

diesel-driven fire pump. The staff’s concern described in RAI B2.1.12-1 is resolved. 

The staff also reviewed the portions of the “parameters monitored or inspected,” “detection of 

aging effects,” “monitoring and trending,” and “acceptance criteria,” program elements, 

associated with the exception and enhancements, to determine if the program will be adequate 

to manage the aging effects for which it is credited. The staff’s evaluation of these exceptions 

and enhancements follows. 

Exception. LRA Section B2.1.12 identifies an exception to the “parameters monitored or 

inspected,” and “detection of aging effects,” program elements. The exception states that halon 

and CO2 fire suppression systems are visually inspected and functionally tested once every 

18 months per the Technical Requirements Manual Surveillance Requirement (TSR). The 

“parameters monitored or inspected” and “detection of aging effects” program elements of the 

GALL Report AMP, “Fire Protection,” recommend that periodic visual inspections and functional 

testing be performed at least once every six months to examine the halon and CO2 fire 

suppression systems for signs of degradation. 

The applicant stated that this functional test would identify any mechanical damage to the halon 

and CO2 fire suppression systems that may prevent the system from performing its intended 

function. The applicant also stated that it considers the 18-month frequency sufficient to ensure 
Aging Management Review Results 

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system availability and operability based on a review of the past 10 years of station operating 

history that has shown no degradation or loss of intended function between test intervals. 

The staff reviewed the applicant’s CLB and confirmed that it performs the visual inspections and 

functional testing of the halon and CO2 fire suppression systems once every 18 months. The 

staff also reviewed the plant operating experience reports and did not find any evidence of 

age-related degradation in the halon or CO2 systems. Based on its review of plant operating 

experience and the fact that the applicant is performing testing and inspection in accordance 

with its CLB, the staff finds that the inspection and testing frequency of once every 18 months is 

adequate to ensure the system maintains its function. The staff finds the exception acceptable. 

However, as part of its annual update letter dated December 7, 2009, the applicant revised the 

exception such that the halon and CO2 dampers are integrity-validated every 54 months, a 

change from the 18 month periodicity as defined in the exception in the LRA. By letter dated 

December 29, 2009, the staff issued RAI B2.1.12-2, requesting that the applicant provide 

technical justification for the 54-month testing and inspection interval. 

In its response, dated February 19, 2010, the applicant stated the following: 

With respect to the 54 month destructive testing of the Electro-Thermal Links 

(ETLs), PVNGS has performed an engineering analysis, consistent with the 

methodology described within EPRI Technical Report 1006756 “Fire Protection 

Equipment Surveillance Optimization and Maintenance Guide 2003” to extend 

the frequency of the test so that the confidence of functionality obtained by 

successful completion of the test is aligned with reliability and logistical concerns 

of the test. The calculation indicates that a full functional test every six years of 

the dampers actuated by ETLs will maintain a 95% success rate assuming the 

same amount of failures as have occurred in the last 10 years and adjusting for 

uncertainty at the 99% level. The selection of a testing interval of 54 months, 

compared to the calculated value of 72 months for 95% success rate, provides 

an additional margin of protection. 

The 18 month halon and CO2 fire suppression systems inspection intervals were 

previously in the initial PVNGS Units 1 and 2 Operating Licenses (OL), 

Appendix A, Technical Specifications 3.7.11.3 and 3.7.11.6. The NRC approved 

the relocation of the fire protection technical specifications to the UFSAR in OL 

Amendments 14 and 8 for Units 1 and 2, respectively, dated April 8, 1987 (prior 

to the issuance of the Unit 3 OL), using the guidance in Generic Letter 86-10. 

Subsequently, following the creation of the licensee-controlled Technical 

Requirements Manual (TRM) when the improved standard Technical 

Specifications were implemented in August 1998 (OL Amendment No. 117 for all 

three units), the fire protection technical specifications were added to the TRM. 

In accordance with PVNGS OL License Conditions, APS may make changes to 

the approved fire protection program without approval of the Commission only if 

those changes would not adversely affect the ability to achieve and maintain safe 

shutdown in the event of a fire. The 18 month halon and CO2 fire suppression 

system circuit actuation testing and damper functional testing (destructive testing 

of the ETLs) intervals in the TRM were changed from 18 months to 54 months in 

November 2009 in accordance with the license condition as evaluated and 

documented in a PVNGS internal License Document Change Request. 

The staff reviewed the applicant response and noted that the engineering evaluation was 

performed assuming the same number of failures as have occurred in the last 10 years 

accounting for uncertainties. However, the number of failures in the past 10 years was based 

on testing performed every 18 months. The staff noted that the number of failures should 
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increase when the applicant performs tests every 54 months. The staff finds that the change in 

testing frequency may adversely affect the ability of this program to adequately manage aging 

so that the intended function of this system will remain consistent with the CLB for the period of 

extended operation. 

In a May 16, 2010 conference call, the staff discussed its concern with the applicant. The 

applicant agreed to supplement its response to RAI B2.1.12-2 and modify the commitment to 

address the staff’s concern. 

By letter dated July 21, 2010, the applicant submitted Amendment No. 20, which provided an 

updated commitment to the Fire Protection AMP. The applicant stated that the existing Fire 

Protection Program is credited for license renewal, and before the period of extended operation 

procedures, will be enhanced to perform the testing of the ETLs and functional testing of the 

halon and CO2 dampers. This testing will occur every 18 months, or at the frequency specified 

in the CLB in effect, upon entry into the period of extended operation. 

The staff finds that the applicant’s commitment adequately addresses the issue because the 

functional testing frequency of the halon and CO2 dampers will be once every 18 months or at 

the frequency specified in the CLB, and this frequency will assure that the intended function of 

this system will be maintained through the period of extended operation. The staff’s concern in 

RAI B2.1.12-2 is resolved. 

Enhancement 1. LRA Section B2.1.12 identifies an enhancement to the “parameters monitored 

or inspected,” “detection of aging effects,” “monitoring and trending,” and “acceptance criteria” 

program elements to expand on the existing program elements by adding trending requirements 

for the diesel-driven fire pump and including visual inspections of the fuel supply line to detect 

degradation. The staff confirmed that the applicant included this enhancement as Commitment 

No. 14 in LRA Appendix A, Table A4-1. 

This enhancement, when implemented, will make the Fire Protection Program consistent with 

the GALL Report AMP, “Fire Protection,” which recommends that performance of the fire pump 

be monitored during the periodic test to detect any signs of degradation in the fuel supply lines. 

Based on its review, the staff finds the enhancement acceptable because it will make the 

program consistent with the GALL Report. 

In its letter dated December 7, 2009, as part of its annual update, the applicant stated that it 

revised the procedures to incorporate the GALL Report AMP recommendation of visual 

inspections of the fuel supply line to detect degradation, and therefore, it deleted this part of 

enhancement 1. The applicant revised Commitment No. 14 to reflect that this enhancement of 

the procedure is complete. 

Enhancement 2. LRA Section B2.1.12 identifies an enhancement to the “parameters monitored 

or inspected,” “detection of aging effects,” “monitoring and trending,” and “acceptance criteria” 

program elements to expand on the existing program elements by adding criteria to inspect for 

mechanical damage, corrosion, and loss of material of the CO2 system discharge nozzles. The 

staff confirmed that the applicant included this enhancement as Commitment No. 14 in LRA 

Appendix A, Table A4-1. 

The staff notes that this enhancement, when implemented, will make the Fire Protection 

Program consistent with the GALL Report AMP, which recommends visual inspections to detect 

any sign of corrosion and mechanical damage of CO2 systems. Based on its review, the staff 

finds the enhancement acceptable because it will make the program consistent with the GALL 

Report. 

Enhancement 3. LRA Section B2.1.12 identifies an enhancement to the “parameters monitored 

or inspected,” “detection of aging effects,” “monitoring and trending,” and “acceptance criteria” 

program elements to expand on the existing program elements by adding criteria to state the 
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qualification requirements for inspecting penetration seals, fire rated doors, fire barrier walls, 

ceilings, and floors. The staff confirmed that the applicant included this enhancement as 

Commitment No. 14 in LRA Appendix A, Table A4-1. 

The staff notes that this enhancement, when implemented, will make the Fire Protection 

Program consistent with the GALL Report AMP, which recommends visual inspections by fire 

protection qualified inspectors of penetration seals, fire barrier wall ceilings and floors, and fire 

rated doors. Based on its review, the staff finds the enhancement acceptable because it will 

make the program consistent with the GALL Report. 

Based on its audit, review of the LRA, and review of the applicant’s responses to RAIs 

B2.1.12-1 and B2.1.12-2, the staff finds that elements one through six of the applicant’s Fire 

Protection Program, with acceptable exceptions and enhancements, are consistent with the 

corresponding program elements of the GALL Report AMP, “Fire Protection,” and are, therefore, 

acceptable. 

Operating Experience. LRA Section B2.1.12 summarizes operating experience related to the 

Fire Protection Program. The applicant stated that there have been instances of Thermo-Lag 

degradation and cracking, and it has reworked these portions of affected Thermo-Lag 

envelopes according to its specifications. The applicant also stated that it has experienced door 

skin cracks, which have been weld repaired according to specifications. The applicant further 

stated that plant staff and other industry representatives performed a fire protection audit in 

2005, which included multiple walkdowns of existing fire barriers and the halon and CO2

systems. The applicant stated that the audit team found no degraded fire barriers. 

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicant reviewed the applicable aging effects and industry and plant-specific 

operating experience. As discussed in the Audit Report, the staff conducted an independent 

search of the plant operating experience information to determine if the applicant had 

adequately incorporated and evaluated operating experience related to this program. The staff 

found that the applicant had adequately identified and incorporated industry and applicable 

plant-specific operating experience. 

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10 and is, 

therefore, acceptable. 

UFSAR Supplement. LRA Section A1.12 provides the UFSAR supplement for the Fire 

Protection Program. By letter dated December 7, 2009, the applicant submitted a revision to 

the UFSAR supplement to delete the enhancement to add trending requirements for the 

diesel-driven fire pump and include visual inspections of the fuel supply line to detect 

degradation because the procedure revisions are complete. The staff reviewed this UFSAR 

supplement description of the program and notes that it conforms to the recommended 

description for this type of program, as described in SRP-LR Table 3.3-2. 

The staff also notes that the applicant committed (Commitment No.14) to enhancing the Fire 

Protection Program before entering the period of extended operation. Specifically, the applicant 

committed to enhancing procedures to include trending requirements for the diesel driven fire 

pump (enhancement complete), enhancing procedures to inspect for mechanical damage, 

corrosion and loss of material of the CO2 system discharge nozzles, and enhancing procedures 

to state the qualification requirements for inspecting penetration seals, fire rated doors, fire 

barrier walls, ceilings, and floors. The staff determines that the information in the UFSAR 

supplement, as amended, is an adequate summary description of the program, as required by 

10 CFR 54.21(d). 
Aging Management Review Results 

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Conclusion. On the basis of its audit and review of the applicant’s Fire Protection Program and 

the applicant’s response to the staff’s RAIs, the staff determines that those program elements 

for which the applicant claimed consistency with the GALL Report are consistent. The staff 

reviewed the exception and its justification, and determines that the AMP is adequate to 

manage the aging effects for which the LRA credits it. The staff also reviewed the 

enhancements and confirmed that their implementation through Commitment No. 14, prior to 

the period of extended operation, will make the existing AMP consistent with the GALL Report 

AMP. The staff concludes that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended functions will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the UFSAR supplement as amended, for this AMP and concludes that it provides an 

adequate summary description of the program, as required by 10 CFR 54.21(d). 

3.0.3.2.8 Fire Water System Program 

Summary of Technical Information in the Application. LRA Section B2.1.13 describes the 

existing Fire Water System Program as consistent, with exceptions and enhancements, with the 

GALL Report AMP XI.M27, “Fire Water System.” The applicant stated that this program 

manages loss of material for water-based fire protection systems. The applicant also stated that 

the program performs periodic hydrant inspections, fire main flushing, sprinkler inspections, and 

flow tests, in accordance with National Fire Protection Association (NFPA) codes and 

standards, to ensure that the water-based fire protection systems are capable of performing 

their intended function. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. The staff compared elements one 

through six of the applicant’s program to the corresponding elements of the GALL Report AMP, 

“Fire Water System.” As discussed in the audit report, the staff confirmed that these elements 

are consistent with the corresponding elements of the GALL Report AMP. 

The staff also reviewed the portions of the “preventive actions,” “parameters monitored or 

inspected,” “detection of aging effects,” “acceptance criteria,” and “corrective actions” program 

elements, associated with the exceptions and enhancements, to determine whether the 

program will be adequate to manage the aging effects for which it is credited. The staff’s 

evaluation of these exceptions and enhancements follows. 

Exception 1. LRA Section B2.1.13 identifies an exception to the “detection of aging effects,” 

program element to perform power block hose station gasket inspections once per 18 months. 

The applicant stated that the TSR defines the inspection frequency to be 18 months. The 

“detection of aging effects” program element of the GALL Report AMP, “Fire Water System,” 

recommends that the gasket inspections be done annually. 

The staff reviewed the applicant’s CLB and confirmed that it performs gasket inspections once 

per 18 months. The staff noted that the applicant’s basis document for this program stated that 

it replaces any gaskets showing signs of deterioration. On the basis that the applicant is 

performing the gasket inspections in accordance with its CLB and that it is replacing any 

gaskets showing signs of degradation, the staff finds the frequency of inspection of once per 

18 months adequate to manage the aging effects and, therefore, finds the exception acceptable. 

Exception 2. LRA Section B2.1.13 identifies an exception to the “detection of aging effects,” 

program element to perform hydrostatic testing on fire hoses once every three years. The 

applicant stated that replacement fire hoses that have been hydrostatically tested are available, 

if needed, in lieu of performing a hydrostatic test. The applicant stated that its TSR defines the 

inspection frequency to be 36 months. The “detection of aging effects” program element of the 
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GALL Report AMP, “Fire Water System,” recommends that the fire hydrant hose hydrostatic 

tests be performed annually. 

The staff reviewed the applicant’s CLB and confirmed that it performs hydrostatic testing of fire 

hoses once every 36 months. The staff also reviewed the applicant’s surveillance procedure for 

hose hydrostatic testing and confirmed that the applicant replaces the hose with a 

hydrostatically tested hose in lieu of testing. The staff reviewed the plant operating experience 

and did not identify any age-related degradation for fire hoses. The staff finds the exception 

acceptable because the applicant is performing the hydrostatic test in accordance with the CLB 

and replaces the hoses with hydrostatically tested fire hoses, if needed, in lieu of the test. In 

addition, operating experience has not identified any age-related degradation associated with 

the fire hoses. 

Enhancement 1. LRA Section B2.1.13 identifies an enhancement to the “preventive actions” 

and “acceptance criteria” program elements to expand on the existing program elements by 

adding review and approval requirements under the Nuclear Administrative Technical Manual 

(NATM). The GALL Report AMP, “Fire Water System,” recommends that preventive actions be 

taken to ensure biofouling does not occur and that acceptance criteria ensure that no biofouling 

exists. The staff confirmed that the applicant included this enhancement as Commitment No. 15 

in LRA Appendix A, Table A4-1. 

The applicant stated that it will enhance its procedures to chemically treat fire water to mitigate 

biofouling to include review and approval requirements under the NATM. The staff finds that 

including this procedure under the scope of the NATM ensures that the applicant will review and 

approve any changes to this procedure in accordance with the requirements of its QA Program. 

The staff finds this enhancement acceptable because it will make the program consistent with 

the recommendations in the GALL Report AMP. 

Enhancement 2. LRA Section B2.1.13 identifies an enhancement to the “parameters monitored 

or inspected” program element to expand on the existing program element by enhancing the 

procedures to be consistent with the current code of record, or NFPA 25, 2002 edition. The 

staff confirmed that the applicant included this enhancement as Commitment No. 15 in LRA 

Appendix A, Table A4-1. The GALL Report Fire Water System AMP recommends that periodic 

flow testing is performed using the guidelines of NFPA 25, 1998 and 2002 editions. 

The applicant stated that it will enhance the procedures for its fire protection test program and 

fire suppression water system flow testing to be consistent with the current code of record or 

NFPA 25, 2002 edition. The staff finds this enhancement acceptable because it will make the 

program consistent with the recommendations in the GALL Report AMP. 

Enhancement 3. LRA Section B2.1.13 identifies an enhancement to the “detection of aging 

effects” program element to expand on the existing program element by adding field service 

testing of a representative sample of sprinklers or replacing sprinklers prior to 50 years in 

service, and testing thereafter every 10 years to ensure that signs of degradation are detected 

in a timely manner. The staff confirmed that the applicant included this enhancement as 

Commitment No. 15 in LRA Appendix A, Table A4-1. 

The GALL Report Fire Water System AMP recommends that sprinkler heads are inspected 

before the end of the 50-year sprinkler head service life and at 10-year intervals thereafter 

during the extended period of operation. The staff finds this enhancement acceptable because 

it will make the program consistent with the recommendations in the GALL Report AMP. 

Enhancement 4. LRA Section B2.1.13 identifies an enhancement to the “detection of aging 

effects” program element to expand on the existing program elements by enhancing procedures 

to be consistent with NFPA 25, Sections 7.3.2.1, 7.3.2.2, 7.3.2.3, and 7.3.2.4. The staff 
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confirmed that the applicant included this enhancement as Commitment No. 15 in LRA 

Appendix A, Table A4-1. 

The GALL Report AMP, “Fire Water System,” recommends that fire hydrant testing is performed 

to assure that the system functions by maintaining required operating pressures. The staff 

reviewed NFPA 25, Sections 7.3.2.1, 7.3.2.2, 7.3.2.3, and 7.3.2.4, and determined that these 

sections provide guidelines on how the fire hydrant testing should be performed, and for how 

long the pressure should be maintained to assure that system is functioning properly. The staff 

finds this enhancement acceptable because it will make the program consistent with the 

recommendation in the GALL Report AMP. 

Enhancement 5. LRA Section B2.1.13 identifies an enhancement to the “corrective action” 

program element to expand on the existing program elements by enhancing procedures so that 

the QA Programs will apply to fire protection SSCs that are within the scope of license renewal 

that are also part of the boundary of the water reclamation facility (WRF). The staff confirmed 

that the applicant included this enhancement as Commitment No. 15 in LRA Appendix A, 

Table A4-1. 

The GALL Report Fire Water System AMP recommends that for fire water systems and 

components identified within scope that are subject to an AMR for license renewal, the 

applicant’s 10 CFR Part 50, Appendix B, Program is used for corrective actions for aging 

management during the period of extended operation. The staff finds this enhancement 

acceptable because it will make the program consistent with the recommendation in the GALL 

Report AMP. 

Based on its audit, the staff finds that elements one through six of the applicant’s Fire Water 

System Program, with acceptable exceptions and enhancements, are consistent with the 

corresponding program elements of the GALL Report AMP, “Fire Water System,” and are, 

therefore, acceptable. 

Operating Experience. LRA Section B2.1.13 summarizes operating experience related to the 

Fire Water System Program. The applicant stated that with the addition of sodium hydroxide 

and sodium sulfite, the corrosion rate has been 0.3 mils per year, thus indicating successful 

corrosion control measures. The applicant also stated that it performed remote field eddycurrent testing on about 7,721 feet of 12-inch pipe covering the fire water main loop, and test 

results indicated that there were several sections of pipe that had localized degradation in 

excess of the minimum wall thickness. Further, the applicant stated that 6,000 feet of pipe on 

the north loop and 4,500 feet of pipe on the south loop was replaced with epoxy-lined, 

reinforced fiberglass pipe. The flushes of the deluge system, fire hydrants, and underground 

pipe identified little or no debris in the lines. A review of the past 10 years of plant operating 

experience provided no reports of gasket or fire hose degradation during inspections conducted 

at intervals of 18 months and three years, respectively. 

The staff reviewed operating experience information in the application and during the audit to 

determine if the applicant reviewed the applicable aging effects and industry and plant-specific 

operating experience. As discussed in the Audit Report, the staff conducted an independent 

search of the plant operating experience information to determine if the applicant had 

adequately incorporated and evaluated operating experience related to this program. The staff 

found that the applicant had adequately identified and incorporated industry and applicable 

plant-specific operating experience. 

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program and that implementation of the program has 

resulted in the applicant taking corrective actions. The staff confirmed that the “operating 
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experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10 and is, 

therefore, acceptable. 

UFSAR Supplement. LRA Section A1.13 provides the UFSAR supplement for the Fire Water 

System Program. The staff reviewed this UFSAR supplement description of the program and 

notes that it conforms to the recommended description for this type of program, as described in 

SRP-LR Table 3.3-2. 

The staff also notes that the applicant committed (Commitment No.15) to enhancing the Fire 

Water System Program before entering the period of extended operation. Specifically, the 

applicant committed that it will enhance specific procedures to include review and approval 

requirements under the NATM; and it will enhance procedures to be consistent with the current 

code of record or NFPA 25, 2002 edition. In addition, the applicant will enhance procedures to 

field service test a representative sample or replace sprinklers prior to 50 years in service and 

test thereafter every 10 years to ensure that signs of degradation are detected promptly. It will 

enhance procedures to be consistent with NFPA 25 Sections 7.3.2.1, 7.3.2.2, 7.3.2.3, and 

7.3.2.4 and enhance procedures so that the QA Programs will apply to fire protection SSCs that 

are within the scope of license renewal that are also part of the boundary of the WRF. 

The staff determines that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d). 

Conclusion. On the basis of its audit and the review of the applicant’s Fire Water System 

Program, the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. In addition, the staff reviewed the exceptions 

and justification and determines that the AMP, with the exceptions, is adequate to manage the 

aging effects for which the LRA credits it. In addition, the staff reviewed the enhancements and 

confirmed that their implementation through Commitment No.15, prior to the period of extended 

operation, will make the existing AMP consistent with the GALL Report AMP. The staff 

concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended functions will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR supplement for this AMP, and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d). 

3.0.3.2.9 Fuel Oil Chemistry Program 

Summary of Technical Information in the Application. LRA Section B2.1.14 describes the 

existing Fuel Oil Chemistry Program as consistent with exceptions and enhancements with the 

GALL Report AMP XI.M30, “Fuel Oil Chemistry.” The applicant stated that the Fuel Oil 

Chemistry Program manages loss of material on the internal surface of components in the 

emergency diesel generator (EDG) fuel oil storage and transfer system, diesel fire pump fuel oil 

system, and SBO generator system. The program includes procedures for testing and 

maintaining the quality of stored and new fuel oil, inspecting the fuel oil storage tanks, and 

performing a sample inspection of components in systems that contain fuel oil. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. 

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of the GALL Report Fuel Oil Chemistry AMP. The staff confirmed that these elements 

are consistent with the corresponding elements of the GALL Report AMP, with the exceptions of 

the “preventive actions,” “parameters monitored or inspected,” “monitoring and trending,” and 

“acceptance criteria” program elements, and the enhancements of “scope of program,” 
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“preventive actions,” “parameters monitored or inspected,” “detection of aging effects,” and 

“monitoring and trending” program elements. 

Exception 1. LRA Section B2.1.14 identifies an exception to the “preventive actions” program 

element. The GALL Report Fuel Oil Chemistry AMP states that biocides, stabilizers, and 

corrosion inhibitors are added to fuel oil to maintain its quality. The applicant stated in the LRA 

that it does not add stabilizers and corrosion inhibitors to the diesel fuel oil based on negligible 

underground temperature swings, an arid outdoor environment, and operating experience 

showing no water in the diesel fuel oil. Based on the staff’s audit of operational experience, 

which confirmed the absence of water in the diesel fuel oil, the staff finds this acceptable 

because the Surveillance and Monitoring Program will continue to verify the absence of water in 

the diesel fuel oil. 

Exception 2. LRA Section B2.1.14 states exceptions to the “parameters monitored or 

inspected,” and “acceptance criteria” program elements. The GALL Report Fuel Oil Chemistry 

AMP states that American Society for Testing and Materials (ASTM) Standards D1796 and 

D2709 are to be used for determination of water and sediment contamination in diesel fuel. The 

applicant stated in the LRA that TS 5.5.13 requires the use of ASTM Standard D1796-83. The 

staff finds this acceptable because both of these ASTM standards perform the same type of 

testing, and the use of ASTM D1796-83 means the applicant’s program will still be consistent 

with the intent of monitoring for water and sediment contamination in diesel fuel in the 

“parameters monitored or inspected” and “acceptance criteria” program elements of the GALL 

Report Fuel Oil Chemistry AMP. 

Exception 3. LRA Section B2.1.14 identifies an exception to the “monitoring and trending” 

program element. The GALL Report Fuel Oil Chemistry AMP states that water and biological 

activity or particulate contamination concentrations are monitored and trended in accordance 

with the plant’s TS, or at least quarterly. The applicant stated in the LRA that it does not monitor 

biological activity. In discussions with the applicant, the applicant clarified that it proactively 

adds biocide to each delivery of fuel oil, and that it monitors particulate contamination in the fuel 

as part of the surveillance program using ASTM D2276. The staff finds this acceptable because 

the monitoring for particulate contamination in the diesel fuel oil makes the applicant’s program 

consistent with the “monitoring and trending” program element of the GALL Report AMP, “Fuel 

Oil Chemistry.” 

Enhancement 1. LRA Section B2.1.14 states enhancements to the “scope of program,” 

“parameters monitored or inspected,” and “monitoring and trending” program elements. The 

applicant stated that, before the period of extended operation, it will enhance the procedures to 

extend the scope of the Fuel Oil Chemistry Program to include the SBO generator fuel oil 

storage tank and the SBO generator skid fuel tanks. The staff compared these enhancements 

to the appropriate program elements in the GALL Report Fuel Oil Chemistry AMP and, because 

the enhancements are consistent with the program elements in the GALL Report AMP, the staff 

finds them acceptable. 

Enhancement 2. LRA Section B2.1.14 states enhancements to the “preventive actions,” and 

“detection of aging effects” program elements. The applicant stated that, prior to the period of 

extended operation, it will enhance the procedures to include 10-year periodic draining, 

cleaning, and inspections of the diesel-driven fire pump day tanks, SBO generator fuel oil 

storage tank, and SBO generator skid fuel tanks. The staff compared these enhancements to 

the appropriate program elements in the GALL Report AMP, “Fuel Oil Chemistry,” and, because 

the enhancements are consistent with the program elements in the GALL Report AMP, the staff 

finds them acceptable. 

Enhancement 3. LRA Section B2.1.14 identifies an enhancement to the “detection of aging 

effects,” program element. The applicant stated that once, prior to the period of extended 
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operation, it will perform a UT or pulsed eddy-current (PEC) thickness examination to detect 

corrosion-related thinning on the tank bottoms of the EDG fuel oil storage tanks, EDG fuel oil 

day tanks, diesel-driven fire pump day tanks, SBO generator fuel oil storage tank, and SBO 

generator skid fuel tanks. The applicant also stated that it will perform a UT or PEC thickness 

examination to detect corrosion-related wall thinning if degradation is found during the visual 

inspections of the tanks. The staff compared these enhancements to the appropriate program 

elements in the GALL Report Fuel Oil Chemistry AMP and, because the enhancements are 

consistent with the program elements in the GALL Report AMP, the staff finds them acceptable. 

Based on its audit, the staff finds that elements one through six of the applicant’s Fuel Oil 

Chemistry Program, with acceptable exceptions and enhancements, are consistent with the 

corresponding program elements of the GALL Report AMP, “Fuel Oil Chemistry,” and are, 

therefore, acceptable. 

Operating Experience. LRA Section B2.1.14 summarizes operating experience related to the 

Fuel Oil Chemistry Program. The applicant stated that their operating experience has shown no 

instances of microbes in the EDG fuel oil, negligible underground temperature swings, and an 

absence of water in the EDG fuel oil. 

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicant reviewed the applicable aging effects and industry and plant-specific 

operating experience. The applicant provided the following operational experience: 

In 2005, during the U2R12 refueling outage, strainers downstream of the EDG 

fuel oil day tank were found to be clogged. The cause was determined to be a 

buildup of sediment in the fuel oil day tank. 

The applicant took corrective actions including re-filling the day tank from empty following 

inspection to remove the sediment on the tank bottom; writing one-time corrective maintenance 

work orders to clean, inspect, and flush the remaining fuel oil day tanks; removing a film of fuel 

oil sediment in one of the five tanks inspected; and establishing a 10-year periodic preventive 

maintenance task to inspect, clean, and flush the diesel fuel oil storage and day tanks. 

The staff also conducted an independent search of the plant operating experience information to 

determine if the applicant had adequately incorporated and evaluated operating experience 

related to this program. The staff found that the applicant had adequately identified and 

incorporated industry and applicable plant-specific operating experience. 

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10 and is, 

therefore, acceptable. 

UFSAR Supplement. LRA Section A1.14 provides the UFSAR supplement for the Fuel Oil 

Chemistry Program. The staff reviewed this UFSAR supplement description of the program and 

notes that it conforms to the recommended description for this type of program, as described in 

SRP-LR Table 3.3-2. The staff also notes that the applicant committed (Commitment No. 16) to 

enhancing the Fuel Oil Chemistry Program before the period of extended operation. 

Specifically, the applicant committed to enhancing their procedures to extend the scope of the 

program to include the SBO generator fuel oil storage tank and SBO generator skid fuel tanks. 

In addition, the applicant will enhance its procedures to include 10-year periodic draining, 

cleaning, and inspections on the diesel-driven fire pump day tanks, the SBO generator fuel oil 

storage tanks, and SBO generator skid fuel tanks. In addition, the applicant will conduct UT or 

PEC thickness examinations once on the tank bottoms and also to detect corrosion-related wall 
Aging Management Review Results 

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thinning if degradation is found during the visual inspections of the tanks. The one-time UT or 

PEC examination on the tank bottoms will be performed before the period of extended 

operation. The staff finds that the information in the UFSAR supplement is an adequate 

summary description of the program, as required by 10 CFR 54.21(d). 

Conclusion. On the basis of its audit and review of the applicant’s Fuel Oil Chemistry Program, 

the staff finds that those program elements for which the applicant claimed consistency with the 

GALL Report are consistent. In addition, the staff reviewed the exceptions and their 

justifications and finds that the AMP, with the exceptions, is adequate to manage the aging 

effects for which the LRA credits it. Also, the staff reviewed the enhancements and confirmed 

that their implementation through Commitment No. 16, prior to the period of extended operation, 

would make the existing AMP consistent with the GALL Report AMP. The staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP, and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

3.0.3.2.10 Reactor Vessel Surveillance Program 

Summary of Technical Information in the Application. LRA Section B2.1.15, describes the RV 

Surveillance Program, stating that this existing program is consistent with enhancement with the 

GALL Report AMP XI.M31, “Reactor Vessel Surveillance.” The applicant stated that the RV 

Surveillance Program manages loss of fracture toughness and consists of scheduled withdrawal 

and testing of RPV material surveillance coupons, consistent with 10 CFR Part 50, Appendix H, 

“Reactor Vessel Material Surveillance Program Requirements,” and with ASTM E185-82, 

“Standard Practice for Conducting Surveillance Tests for Light-Water Cooled Nuclear Power 

Reactor Vessels.” The applicant will revise the current schedule to withdraw the next capsule at 

the equivalent RPV clad-base metal exposure of approximately 54 effective full-power years 

(EFPYs) for the period of extended operation and to withdraw remaining standby capsules at 

equivalent RPV clad-base metal exposures not exceeding the 72 EFPYs expected for a 

possible second period of extended operation. 

Staff Evaluation. The staff reviewed the applicant's RV Surveillance Program to confirm 

whether the applicant's claim of consistency with the GALL Report RV Surveillance AMP with 

enhancements is valid. 

Appendix H of 10 CFR Part 50 specifies surveillance program criteria for 40 years of operation. 

The GALL Report AMP, “Reactor Vessel Surveillance,” specifies additional criteria for 60 years 

of operation. The staff determined that compliance with 10 CFR Part 50, Appendix H criteria for 

capsule design, location, specimens, test procedures, and reporting remains appropriate for this 

AMP because these items, which satisfy 10 CFR Part 50, Appendix H, will stay the same 

throughout the period of extended operation. To ensure that all capsules in the RPV, removed 

and tested during the period of extended operation, still meet the test procedures and reporting 

requirements of ASTM E 185-82, the staff imposes the following license condition to address 

this specific concern: 

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

procedures and reporting requirements of American Society for Testing and 

Materials (ASTM) E 185-82 to the extent practicable for the configuration of the 

specimens in the capsule. Any changes to the capsule withdrawal schedule, 

including spare capsules, must be approved by the NRC prior to implementation. 

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

changes to storage requirements must be approved by the NRC. 
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The 10 CFR, Part 50, Appendix H capsule withdrawal schedule during the period of extended 

operation is addressed according to the GALL Report’s consideration of eight criteria for an 

acceptable RPV surveillance program for 60 years of operation. 

Enhancements. The staff reviewed the enhancements and the associated justifications to 

determine whether this AMP is adequate to manage the aging effects for which it is credited. 

The enhancements are to keep two surveillance capsules in each RPV beyond 32 EFPYs of 

plant operation and then withdraw one at the equivalent RPV clad-base metal exposure of 

approximately 54 EFPYs (40 EFPYs actual operation during the period of extended operation) 

and the other at 72 EFPYs (54 EFPYs actual operation). This meets Criterion 5 of the GALL 

Report RV Surveillance AMP, which is applicable to a surveillance program that consists of 

capsules with a projected fluence of less than the 60-year fluence at the end of 40 years. The 

staff’s review of this AMP against the remaining seven criteria is discussed below. 

Criteria 1, 2, and 3 of the GALL Report AMP, “Reactor Vessel Surveillance,” regard evaluation 

of 60-year upper-shelf energy (USE) and pressure-temperature (P-T) limits, using RG 1.99, 

Revision 2, “Radiation Embrittlement of Reactor Vessel Materials.” The LRA RV Surveillance 

Program states that the applicant determined neutron embrittlement effects consistent with RG 

1.99, by using option 1b, “Neutron Embrittlement Using Surveillance Data.” The staff found, 

from its review of LRA Section 4.2, “Reactor Vessel Neutron Embrittlement Analysis,” that the 

applicant actually used option 1a, “Neutron Embrittlement Using Chemistry Tables,” of the GALL 

Report RV Surveillance AMP to evaluate USE and P-T limits for 60 years. Hence, by letter 

dated November 3, 2009, the staff issued RAI B2.1.15-1 requesting the applicant clarify which 

option was used. 

The applicant’s response to RAI B2.1.15-1, dated December 18, 2009, clarified that “[LRA] 

Tables 4.2-3 through 4.2-8 only present projections of embrittlement effects before results of 

surveillance data are applied. They do not reflect results of the RPV surveillance program.” 

The applicant further stated that its RPV program “will evaluate embrittlement parameters based 

on surveillance data that is, using GALL [AMP] XI.M31, option 1b, as described.” Therefore, 

RAI B2.1.15-1 is resolved. Further, compliance with RG 1.99, Revision 2 ensures that the AMP 

meets criteria 1, 2, and 3 of the GALL Report RV Surveillance AMP. 

For Criterion 4, regarding pulled and tested capsule specimens, the LRA RV Surveillance 

Program states that, “[f]ragments of surveillance specimens are retained for possible future 

use.” Hence, Criterion 4 is satisfied. 

The applicant’s proposed withdrawal schedule during the period of extended operation for the 

two capsules, as discussed earlier, was confirmed to meet Criterion 5. 

Criterion 6 does not apply to the AMP because it is for plants having capsules with a projected 

fluence exceeding the 60-year fluence at the end of 40 years. Criterion 7 also does not apply to 

the AMP because it is for plants having no surveillance capsules. 

Criterion 8 asks for justification for not including nozzle specimens in the surveillance program. 

The applicant did not address this issue in the RV Surveillance Program. However, the 

applicant addressed this issue indirectly in LRA Section 4.2.1. As indicated in Section 4.2.1 of 

this SER, the staff concludes that the current 32 EFPY neutron fluence for RPVs bounds 

54 EFPY neutron fluence, indicating that neutron embrittlement of RPV nozzle materials will 

remain low during the period of extended operation. Hence, similar to the CLB, nozzle 

specimens are not required to be included in the surveillance program during the period of 

extended operation. 

Based on the above evaluation of the applicant’s RV Surveillance Program, the staff concludes 

that the AMP has met the eight acceptance criteria of the GALL Report RV Surveillance AMP 

and is, therefore, acceptable. 
Aging Management Review Results 

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Operating Experience. In LRA Section B2.1.15, the applicant stated what the recent 

examination results of the RPV surveillance data revealed regarding neutron fluence, USE, and 

the reference nil-ductility transition temperature (RTNDT). Evaluation of operating experience of 

this AMP should not be limited to “the recent examination results.” Hence, by letter dated 

November 3, 2009, the staff issued RAI B2.1.15-2 requesting the applicant to provide a 

discussion of all tested RPV surveillance data. 

The applicant responded to RAI B2.1.15-2 in a letter dated December 18, 2009, stating that 

“[t]he results of the earlier coupon examinations are consistent with the most recent results, and 

are summarized in the Appendix D credibility evaluation of these three most-recent examination 

reports.” Hence, the applicant has supplied information regarding evaluation of earlier 

surveillance data, and RAI B2.1.15-2 is resolved. 

UFSAR Supplement. The applicant provided its UFSAR Supplement for the RV Surveillance 

Program in LRA Section A1.15. Appendix H of 10 CFR Part 50 requires licensees to submit 

proposed changes to their RV Surveillance Program withdrawal schedules to the NRC for 

review and approval. The staff reviewed this UFSAR supplement description of the program 

and notes that it conforms to the recommended description for this type of program, as 

described in SRP-LR Table 3.1-2. To ensure that this reporting requirement will carry forward 

through the period of extended operation, the staff has imposed a license condition to the 

applicant's RV Surveillance Program, as stated earlier in the staff’s evaluation. The staff 

reviewed the UFSAR Supplement and determines that the information in the supplement, with 

the license condition, provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

Conclusion. On the basis of its review of the applicant's RV Surveillance Program and RAI 

responses, the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

functions will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP, 

and concludes that, with the license condition, it provides an adequate summary description of 

the program, as required by 10 CFR 54.21(d). 

3.0.3.2.11 Selective Leaching of Materials Program 

Summary of Technical Information in the Application. LRA Section B2.1.17 describes the new 

Selective Leaching of Materials Program as consistent, with an exception, with the GALL Report 

AMP XI.M33, “Selective Leaching of Materials.” The applicant stated that this program 

manages the loss of material due to selective leaching for copper alloys with zinc content 

greater than 15 percent, copper alloys with aluminum content greater than eight percent, and 

gray cast iron components exposed to closed-cycle cooling water, demineralized water, 

secondary water, and raw water. The applicant also stated that this program includes a 

one-time visual inspection and mechanical methods to determine whether loss of material due 

to selective leaching is occurring. The applicant further stated that the program includes an 

engineering evaluation of components if it detects selective leaching. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. The staff compared elements one 

through six of the applicant’s program to the corresponding elements of the GALL Report AMP, 

“Selective Leaching of Materials.” As discussed in the Audit Report, the staff confirmed that 

these elements are consistent with the corresponding elements of the GALL Report AMP. 

Upon further review, however, the staff determined that additional information was needed 

regarding the “scope of program” element. The GALL Report AMP “Selective Leaching of 
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Materials” states in the “scope of program” element that the program should include a one-time 

visual inspection and hardness measurements of a selected set of sample components to 

determine whether loss of material due to selective leaching is occurring. However, the LRA did 

not specify sample size or selection criteria. The staff noted that due to the uncertainty in 

determining the most susceptible locations and the potential for aging to occur in other 

locations, large sample sizes may be required in order to adequately confirm that selective 

leaching is not occurring. By e-mail dated November 17, 2010, the staff requested that the 

applicant provide specific information regarding how the selected set of components to be 

sampled will be determined and the size of the sample of components that will be inspected. 

In its response dated December 3, 2010, the applicant stated that the representative sample 

size and inspection locations will be determined based on the materials of fabrication. The 

applicant also stated that a sample size of 20 percent of the site’s population (up to a maximum 

of 25 inspections) has been established for each group of components including different 

material and environment combinations. The applicant also stated that the specific inspection 

locations will be identified considering those components that are most susceptible to selective 

leaching and that sampling will not be repeated for equivalent system components between the 

three units. The staff finds the applicant’s response acceptable because the applicant’s 

selected set of components will be based on material and environment combinations, and the 

sample locations will focus on the leading indicator components. Additionally, the applicant’s 

program includes a sample size adequate to confirm selective leaching is not occurring. The 

staff’s concern described above is resolved. 

The staff also reviewed the portions of the “scope of program,” “preventive actions,” “parameters 

monitored or inspected,” and “detection of aging effects” program elements associated with the 

exception to determine if the program will be adequate to manage the aging effects for which it 

is credited. The staff’s evaluation of this exception follows. 

Exception. LRA Section B2.1.17 identifies an exception to the “scope of program,” “preventive 

actions,” “parameters monitored or inspected,” and “detection of aging effects” program 

elements. The GALL Report AMP, “Selective Leaching of Materials,” recommends hardness 

testing of selected components in addition to a one-time visual inspection. Alternatively, the 

applicant’s program includes use of other mechanical means (i.e., scraping or chipping) as a 

qualitative determination of selective leaching. The applicant stated that hardness testing may 

not be feasible for most components due to form and configuration and that other mechanical 

means provide an equally valid means of identification. Based on its review, the staff finds this 

exception acceptable because mechanical methods, such as scraping and chipping, can identify 

selective leaching of copper alloy and gray cast iron components. 

Based on its audit and review of the LRA, the staff finds that elements one through six of the 

applicant’s Selective Leaching of Materials Program, with exception, are consistent with the 

corresponding program elements of the GALL Report Selective Leaching of Materials AMP, and 

are, therefore, acceptable. 

Operating Experience. LRA Section B2.1.17 summarizes operating experience related to the 

Selective Leaching of Materials Program. The applicant stated that this is a new, one-time 

inspection program with no plant-specific operating experience. However, the applicant also 

stated that industry operating experience on selective leaching is documented in IN 94-59, 

“Accelerated Dealloying of Cast Aluminum-Bronze Valves Caused by Microbiologically Induced 

Corrosion.” The applicant further stated that it chemically treats the open-cycle cooling water 

systems with biocides to prevent microbiologically induced corrosion (MIC), and that it 

periodically recirculates systems that are not in continuous use to ensure adequate chemical 

mixing. 
Aging Management Review Results 

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The staff reviewed the operating experience information, in the application and during the audit, 

to determine if the applicant reviewed the applicable aging effects and industry and 

plant-specific operating experience. As discussed in the Audit Report, the staff conducted an 

independent search of the plant operating experience information to determine if the applicant 

had adequately incorporated and evaluated operating experience related to this program. The 

staff found that the applicant had adequately identified and incorporated industry and applicable 

plant-specific operating experience. 

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A1.2.3.10 and is, 

therefore, acceptable. 

UFSAR Supplement. LRA Section A1.17 provides the UFSAR supplement for the Selective 

Leaching of Materials Program. The staff reviewed this UFSAR supplement description of the 

program and notes that it conforms to the recommended description for this type of program, as 

described in SRP-LR Tables 3.1-2, 3.2-2, and 3.3-2. The staff also notes that the applicant 

committed (Commitment No. 19) to implementing the new Selective Leaching of Materials 

Program prior to entering the period of extended operation to manage the aging of applicable 

components. The staff determines that the information in the UFSAR supplement is an 

adequate summary description of the program, as required by 10 CFR 54.21(d). 

Conclusion. On the basis of its audit and review of the applicant’s Selective Leaching of 

Materials Program, the staff determines that those program elements for which the applicant 

claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the 

exception and justification, and determines that the AMP, with the exception, is adequate to 

manage the aging effects for which the LRA credits it. The staff concludes that the applicant 

has demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP, 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

3.0.3.2.12 Buried Piping and Tanks Inspection Program 

Summary of Technical Information in the Application. LRA Section B2.1.18 describes the new 

Buried Piping and Tanks Inspection Program as consistent, with exceptions, with the GALL 

Report AMP XI.M34, “Buried Piping and Tanks Inspection.” The applicant stated that this 

program manages loss of material caused by corrosion of the external surfaces of buried 

components. The applicant also stated that the program includes opportunistic or planned 

visual inspections to monitor the condition of protective coatings and wrappings on carbon steel, 

gray cast iron, or ductile iron components and to assess the condition of stainless steel 

components with no coatings or wraps. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. The staff compared elements one 

through six of the applicant’s program to the corresponding elements of the GALL Report AMP, 

“Buried Piping and Tanks Inspection.” As discussed in the Audit Report, the staff confirmed that 

these elements are consistent with the corresponding element of the GALL Report AMP. The 

staff also reviewed the portions of the “scope of program,” “preventive actions,” and “acceptance 

criteria” program elements associated with the exceptions to determine if the program will be 

adequate to manage the aging effects for which it is credited. The staff’s evaluation of these 

exceptions follows. 
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Exception 1. LRA Section B2.1.18 identifies an exception to the “scope of program” and 

“acceptance criteria” program elements. The scope of the GALL Report Buried Piping and 

Tanks Inspection AMP only includes buried steel piping, whereas the applicant’s program also 

includes buried stainless steel piping. The applicant stated that it will inspect buried stainless 

steel piping for loss of material due to general, pitting, and crevice corrosion as well as MIC. 

Based on its review, the staff finds this exception acceptable because the periodic inspections in 

the applicants program are adequate to identify the loss of material in buried stainless steel 

piping. 

Exception 2. LRA Section B2.1.18 identifies an exception to the “scope of program,” “preventive 

actions,” and “acceptance criteria” program elements. The GALL Report AMP, “Buried Piping 

and Tanks Inspection” recommends preventive measures such as coatings and wrappings to 

mitigate corrosion. However, the applicant’s program also includes buried stainless steel piping, 

portions of which may not be coated or wrapped. The applicant stated that it will inspect buried 

stainless steel piping for loss of material due to general, pitting, and crevice corrosion as well as 

MIC. During the AMP audit, the applicant stated that it had examined soil quality during the 

review of the fire protection system, and the results of soil chemistry analysis indicate that the 

soil is corrosive with chloride concentration greater than 250 parts per million and resistivity less 

than 2500 ohms per centimeter. The staff notes that given these soil conditions, the uncoated 

buried stainless steel piping is susceptible to pitting corrosion and, depending on the water table 

level where the pipe is buried, it may also be susceptible to MIC. The staff conducted a 

conference call with the applicant on May 20, 2010, during which the applicant agreed to revise 

their RAI response to answer staff questions. 

In a supplemental response to RAI B2.1.18-1, dated June 21, 2010, the applicant stated that 

before the period of extended operation, and again within the first 10 years of extended 

operation, it will excavate and inspect at least two 10-foot sections of stainless steel piping, 

inclusive of chemical volume and control, condensate transfer and storage, or fire protection. 

The staff finds the applicant’s response acceptable because the applicant will be performing 

four inspections of stainless steel piping and, as discussed in the Operating Experience 

Section below, 10 other inspections of steel and fire protection piping in the period prior to and 

during extended operation. These inspections will provide a reasonable assurance of the 

condition of buried piping that exceeds the existing GALL Report Buried Piping and Tanks 

Inspection AMP recommendations. 

Based on its audit and review of the applicant’s response to RAI B2.1.18-1, the staff finds that 

elements one through six of the applicant’s Buried Piping and Tanks Inspection Program, with 

acceptable exceptions, are consistent with the corresponding program elements of the GALL 

Report Buried Piping and Tanks Inspection Program and are, therefore, acceptable. 

Operating Experience. LRA Section B2.1.18 summarizes operating experience related to the 

Buried Piping and Tanks Inspection Program. The applicant stated that the Buried Piping and 

Tanks Inspection Program is a new program and, as such, it will evaluate industry and 

plant-specific operating experience during the development and implementation of this program. 

The applicant also stated that it has found degraded buried piping in the fire protection system. 

Segments of this ductile iron piping had localized corrosion, and the applicant replaced it with 

epoxy-lined, reinforced fiberglass pipe. 

The staff reviewed operating experience, in the application and during the audit, to determine if 

the applicant reviewed the applicable aging effects and industry and plant-specific operating 

experience. As discussed in the Audit Report, the staff conducted an independent search of the 

plant operating experience information to determine if the applicant had adequately incorporated 

and evaluated operating experience related to this program. 
Aging Management Review Results 

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During the audit, the staff reviewed the applicant’s condition reports. The staff noted that the 

applicant found coating damage on the external surfaces of underground fire protection piping. 

Abrasion from the bedding rock material caused this damage, which exposed the piping to 

corrosive attack. The staff also noted that the applicant conducted remote, field eddy-current 

inspections to assess the condition of the piping. The applicant also stated that it isolated and 

repaired the piping failures in the underground fire protection system without adversely affecting 

the functionality of the fire protection system. 

During its review, the staff identified operating experience, which warranted additional 

information to ensure the program would be effective in adequately managing aging effects 

during the period of extended operation. Additionally, a number of recent industry events 

involve leakage from buried piping due to corrosion stemming from coating damage during 

backfill of piping, failure of fiberglass piping, and failure of buried piping in and around piping 

penetrations. Based on information in the program basis document, it is not clear to the staff 

how the applicant considered this relevant industry operating experience in its program. By 

letter dated December 29, 2009, the staff issued RAI B2.1.18-1, requesting that the applicant 

provide additional information as to how it considered relevant industry operating experience 

during the development of its Buried Piping and Tanks Inspection Program. 

In its response, dated February 19, 2010, the applicant stated that it incorporated industry 

operating experience in the development of the Buried Piping and Tanks Inspection Program. 

The applicant also stated that it reviewed and included selected provisions of industry guideline 

documents and participated in industry forums on the subject. The applicant further stated that 

it used EPRI Report 1016456, “Recommendations for an Effective Program to Control the 

Degradation of Buried Pipe,” dated December 2008, and NEI Technical Report (TR) 07-07, 

“Industry Ground Water Protection Initiative, Final Guidance Document,” dated August 2007, in 

the development of this program. The applicant stated that it was engaged in the EPRI Buried 

Piping Integrity Group and the NEI initiative on buried piping to learn from the recent events, 

including the operating experience at Oyster Creek Nuclear Generating Station and Indian Point 

Nuclear Generating Units 2 and 3. 

Based on its review, the staff found the applicant’s response to RAI B2.1.18-1 unacceptable 

because the staff has not endorsed EPRI Report 1016456 and NEI TR 07-07. The staff 

conducted a follow-up conference call with the applicant on May 20, 2010, during which the 

applicant agreed to revise their RAI response. In the supplemental responses to RAI B2.1.18-1, 

dated June 21, 2010, and July 21, 2010, the applicant provided all of its plant-specific operating 

experience related to buried piping. Four of the five leaks or degradation occurred in the fire 

protection system. The applicant stated that in addition to risk ranking of piping included in their 

commitment to the NEI initiative on buried piping, it will excavate and visually inspect at least 10 

feet of piping during the period prior to extended operation and again during the first 10-year 

period of extended operation at the following locations: 

 two inspections of stainless steel piping in each unit 

 two inspections of cathodically protected steel piping in each unit 

 three inspections of fire protection piping with potentially degraded cathodic bonding 

straps 

The applicant also stated that prior to the period of extended operation it will enact provisions to 

ensure that power is maintained to the cathodic protection system at least 90 percent of the time 

and that it will perform National Association of Corrosion Engineers cathodic protection surveys 

annually. 

The staff found that the applicant’s response did not specifically state that steel piping 

containing hazardous materials would be inspected, and there is no docketed information on the 
Aging Management Review Results 

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quality of the backfill used during installation of the buried chemical and volume control, diesel 

fuel storage and transfer, domestic water, and essential spray ponds piping. By letter dated 

September 27, 2010, the staff issued follow-up RAI B2.1.18-1 requesting that the applicant 

provide additional information on the adequacy of its aging management of piping containing 

hazardous materials and justify why backfill quality is considered adequate such that damage 

will not occur to coatings (and piping when no coating is installed) in the buried chemical and 

volume control, diesel fuel storage and transfer, domestic water, and essential spray ponds 

piping. 

In its responses dated October 13, 2010, and November 10, 2010, the applicant stated that the 

essential spray pond system does not contain hazardous material. The applicant also stated 

that there are approximately 1697 feet of in-scope, buried diesel fuel oil piping of which only 

82 feet is not under concrete or asphalt. The applicant also stated that as part of its 

participation in the NEI industry buried piping initiative, it will excavate and inspect 10 feet of 

buried diesel fuel oil piping between January 1, 2012, and December 31, 2015. Finally, the 

applicant committed to inspect at least one 10 foot segment of this piping in each 10 year 

interval during the period of extended operation. The applicant further stated that the 

specifications for backfill ensure that buried piping and its coatings would not be damaged; 

however, it did find evidence that coarse angular backfill was utilized during construction of the 

fire protection system. Portions of this system have been and continue to be replaced with the 

applicant using appropriate quality backfill. The applicant stated that excavations of essential 

spray pond piping have revealed proper installation of backfill and that the pipe coating was 

intact. The staff noted that the applicant’s September 27, 2010, RAI response stated that it 

would augment the buried piping inspection plans to include three fire protection piping locations 

based on plant-specific operating experience of leaks. 

The staff noted that as a result of the applicant aligning its first diesel fuel oil piping inspection 

with the industry buried piping initiative, the inspection, depending on which unit it is conducted, 

could precede the 10-year period prior to the period of extended operation by as little as 

31⁄2 years and as much as 6 years. Based on its review, the staff finds the applicant’s response 

to follow-up RAI B.2.1.18-1 acceptable because, (a) even though the first inspection of the 

buried diesel fuel oil piping could occur at 24 years into plant life, there is enough operating time 

to determine if coating damage and subsequent pipe corrosion has occurred, (b) the applicant 

will conduct an inspection of buried diesel fuel oil piping in each of the two 10-year periods 

during the period of extended operation, (c) the essential spray pond piping system does not 

contain hazardous materials, (d) the specifications for backfill ensure that buried piping and its 

coatings were not damaged, and (e) it has augmented the fire protection inspections based on 

plant-specific operating experience. The staff’s concern described in RAI B.2.1.18-1 is 

resolved. 

The LRA states that the chemical and volume control, diesel fuel storage and transfer, domestic 

water, fire protection, and essential spray pond systems include buried piping. Based on a 

review of plant-specific operating experience, the staff notes that the only in-scope buried piping 

failures have been in fire protection piping. The staff also notes that the applicant has enhanced 

the buried pipe program with additional inspections of the fire protection piping to ensure that 

the extent of condition has been identified. The staff finds the applicant’s response acceptable 

because (a) cathodic protection will be available 90 percent of the time and annual NACE 

qualified surveys will be conducted, (b) all carbon steel piping is coated, (c) specifications for 

backfill ensure that buried piping and its coatings were not damaged and has augmented the 

fire protection inspections based on plant-specific operating experience, (d) excavated visual 

inspections of at least 10 linear feet of buried pipe in each material group will be conducted, and 

(e) the applicant will conduct a 10-foot excavated direct visual inspection of buried diesel fuel oil 

piping as part of its participation in the NEI industry buried piping initiative. 
Aging Management Review Results 

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The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately incorporated and evaluated operating experience related 

to this program. 

Based on its audit and review of the application, and review of the applicant’s response to 

RAI B2.1-18-1, the staff finds that operating experience related to the applicant’s program 

demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the 

scope of the program and that implementation of the program has resulted in the applicant 

taking corrective actions. The staff confirmed that the “operating experience” program element 

satisfies the criterion in SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it acceptable. 

UFSAR Supplement. LRA Section A1.18 provides the UFSAR supplement for the Buried Piping 

and Tanks Inspection Program. The staff reviewed this UFSAR supplement description of the 

program, including changes made as a result of RAIs, and notes that it conforms to the 

recommended description for this type of program, as described in SRP-LR Tables 3.2-2, 3.3-2, 

and 3.4-2. The staff also notes that the applicant committed (Commitment No. 20) to implement 

the new Buried Piping and Tanks Inspection Program, inspections, and operating provisions of 

the cathodic protection system beyond those recommended in GALL AMP XI.M34 prior to 

entering the period of extended operation to manage the aging of applicable components. The 

staff determines that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d). 

Conclusion. On the basis of its audit and review of the applicant’s Buried Piping and Tanks 

Inspection Program, the staff determines that those program elements for which the applicant 

claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the 

exceptions and justifications, and determines that the AMP, with the exceptions, is adequate to 

manage the aging effects for which the LRA credits it. The staff concludes that the applicant 

has demonstrated that the effects of aging will be adequately managed so that the intended 

functions will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP, 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

3.0.3.2.13 One-Time Inspection of American Society of Mechanical Engineers Code Class 1 

Small-Bore Piping 

Summary of Technical Information in the Application. LRA Section B2.1.19 describes the 

existing One-Time Inspections of ASME Code Class 1 Small-Bore Piping Program as 

consistent, with an exception, with the GALL Report AMP XI.M35, “One-Time Inspections of 

ASME Code Class 1 Small-Bore Piping.” The applicant stated that the One-Time Inspection of 

ASME Code Class 1 Small-Bore Piping Program manages cracking of ASME Code Class 1 

piping, less than or equal to four inches. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. The staff compared elements one 

through six of the applicant’s program to the corresponding elements of the GALL Report AMP. 

As discussed in the Audit Report, the staff confirmed that each element of the applicant’s 

program is consistent with the corresponding element of the GALL Report AMP, with the 

exception of “parameters monitored or inspected” program element. For this element, the staff 

determined the need for additional clarification, which resulted in the issuance of an RAI. 
Aging Management Review Results 

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The “parameters monitored or inspected” program element of the GALL Report One-Time 

Inspections of ASME Code Class 1 Small-Bore Piping AMP recommends that inspections will 

detect cracking in ASME Code Class 1 small-bore piping. During its audit, the staff noted that 

socket welds that fall within the weld examination sample will be examined in accordance with 

ASME Section XI Code requirements. During its audit, the staff further noted that if a qualified 

volumetric examination procedure for socket welds, endorsed by the industry, is available and 

incorporated into ASME Section XI at the time of the small-bore socket weld inspections, then 

volumetric examinations will be conducted on small-bore socket welds. The staff noted that if a 

volumetric examination procedure for socket welds, endorsed by the industry, is not available 

and incorporated into the ASME Section XI at the time of the small-bore socket weld 

inspections, then present ASME Section XI Code requirements will be used for examination of 

socket welds. The staff also noted that present ASME Section XI Code only requires surface 

examination for small-bore piping, but surface examination will not detect cracking that initiates 

on the inside of the piping before leakage occurs. 

By letter dated December 29, 2009, the staff issued RAI B2.1.19-1 requesting the applicant to 

clarify what examination method it will use to detect cracking that initiates from the inside of 

socket welds, if a volumetric examination procedure endorsed by the industry for socket welds 

is not available. 

In its response, dated February 19, 2010, the applicant stated that if no volumetric examination 

procedure for ASME Code Class 1 small bore socket welds has been endorsed by the industry 

and incorporated into ASME Section XI at the time it performs inspections of socket welded 

ASME Class 1 small-bore piping, it will use a plant procedure for volumetric examination of 

ASME Code Class 1 small-bore piping with socket welds. The applicant also stated that it 

revised LRA Sections A1.19 and B2.1.19 to include the use of a plant procedure for volumetric 

examination of ASME Code Class 1 small-bore piping with socket welds in the event a 

volumetric examination procedure endorsed by the industry and incorporated into ASME 

Section XI is not available. 

Based on its review, the staff finds the applicant’s response to RAI B2.1.19-1 acceptable 

because the applicant has committed to volumetric examination of small-bore piping socket 

welds, which is capable of detecting cracking initiated from the inside wetted area of the weld 

and is consistent with the recommendations of the GALL Report AMP. The staff’s concern 

described in RAI B2.1.19-1 is resolved. 

The staff also reviewed the portions of the “scope of program” program element associated with 

exception to determine if the program will be adequate to manage the aging effects for which it 

is credited. The staff’s evaluation of this exception follows. 

Exception. LRA Section B2.1.19 identifies an exception to the “scope of program” program 

element. The applicant stated in the LRA that for the risk-informed process, it performs 

examination requirements consistent with EPRI TR-112657, “Revised Risk-Informed Inservice 

Inspection Evaluation Procedure,” Rev. B-A, instead of EPRI Report 1000701, “Interim Thermal 

Fatigue Management Guideline.” The staff noted that although the applicant no longer uses 

risk-informed methods to select locations for ISIs, the applicant uses the results of previous 

risk-informed evaluations to select small-bore piping locations to be subjected to this one-time 

inspection. 

The applicant further stated that guidelines for identifying piping susceptible to potential effects 

of thermal stratification or turbulent penetration that are provided in EPRI Report 1000701 are 

also provided in EPRI TR-112657, and the recommended inspection volume for welds in EPRI 

Report 1000701 are identical to those for inspection of thermal fatigue in risk-informed ISI 

programs. Therefore, the risk-informed process examination requirements meet the 

recommendations of the GALL Report. The staff noted that, although the inspection volumes 
Aging Management Review Results 

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are identical, it is not clear if the applicant will inspect welds with the highest likelihood of 

degradation (e.g. welds with the highest stress but not necessarily highest risk category). The 

staff also reviewed the applicant’s selection of welds that would be subjected to volumetric 

one-time inspection based on the risk-informed method and found that only butt welds would be 

inspected. The staff noted that, although the butt welds to be inspected have the highest risk, 

the environment of butt welds is not the same as for socket welds due to the crevice inherent in 

socket welds; the crevice could lead to aging effects in socket welds, which could be missed if 

the applicant inspects only butt welds. 

By letter dated December 29, 2009, the staff issued RAI B2.1.19-2 requesting the applicant to 

specify if locations that it will inspect, according to risk-informed methods, also bound the 

locations of the highest likelihood of degradation. The staff also requested the applicant to 

justify how it would identify the degradation of socket welds if the risk-informed selection of 

locations of small-bore piping for volumetric inspection does not include socket welds. 

In its response, dated February 19, 2010, the applicant stated that Class 1 socket welds are in 

the category of low probability of failure and are not included in the risk-informed sample 

population for volumetric inspection. The applicant further stated that it will augment the 

inspection population to include at least one socket weld in each unit with a different socket 

weld location selected for each unit. The applicant also stated that it revised LRA 

Sections A1.19 and B2.1.19, as shown in Amendment 9, to include a volumetric inspection of at 

least one socket weld in each unit with a different socket weld location selected for each unit. 

The staff finds that the selection of locations of ASME Class 1 small-bore piping subject to the 

one-time inspection is not adequate given that the applicant has experienced multiple failures in 

its Class 1 socket welds. The GALL Report AMP states that: 

This inspection should be performed at a sufficient number of locations to ensure 

an adequate sample. This number, or sample size, is based on susceptibility, 

inspectability, dose considerations, operating experience, and limiting locations 

of the total population of ASME Code Class 1 small-bore piping locations. 

The applicant’s statement in its response “at least one socket weld” did not provide a definitive 

number concerning the inspection sample size. This was previously identified as Confirmatory 

Item 3.0.3.2.13-1. 

In a conference call with the applicant, dated July 21, 2010, the staff stated it did not have 

assurance that the applicant would select a sufficient number of samples, as recommended by 

the GALL Report AMP XI.M35, to ensure adequate aging management. The applicant stated 

that it would modify its One-Time Inspection Program (discussed in SER Section 3.0.3.1.6) to 

volumetrically inspect 10 percent of the socket weld population for each unit. Although its ISI 

program does not use risk-informed methodology, it plans to use its risk-informed methodology 

to select the most susceptible welds from its population. The applicant will provide an 

assessment to show that the number of samples it inspects will be statistically significant and 

that, with the screening methodology, the inspection will provide reasonable assurance that if 

aging (cracking) of socket welds exists, the program will detect it. The staff finds the sample 

selection methodology acceptable, as it is consistent with the GALL Report One-Time 

Inspection of ASME Code Class 1 Small Bore Piping, which states that the sample should be 

based on “susceptibility, inspectability, dose considerations, operating experience, and limiting 

locations of the total population of ASME Code Class 1 small-bore piping locations.” 

In its response dated July 30, 2010, and supplemented by letter dated December 3, 2010, the 

applicant revised its AMP to volumetrically inspect at least 10 percent of Class 1 socket welds 

per unit with a maximum of 25 welds. The applicant further stated that the weld sample 

selection will be based on risk insights and susceptibility to aging degradation. The applicant 

stated that the Class 1 socket weld population is approximately 300 to 400 per unit and 
Aging Management Review Results 

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approximately 1000 for the entire station. The staff noted that the sampling of at least 

10 percent with 25 welds maximum in each unit, results in examining of 75 welds total. In 

addition, the applicant stated that weld selection will be based on “risk insight” and “the potential 

for aging degradation.” 

The staff finds that the number of welds to be inspected and the weld selection methodology are 

consistent with GALL Report AMP XI.M35, “One-Time Inspections of ASME Code Class 1 

Small-Bore Piping.” This AMP recommends that, “[t]his number, or sample size, is based on 

susceptibility, inspectability, dose considerations, operating experience, and limiting locations of 

the total population of ASME Code Class 1 small-bore piping locations.” Since the number of 

welds to be inspected and the selection methodology, which will include the most risk significant 

and most susceptible welds, is consistent with the GALL Report recommendations, the staff 

finds that aging management of Class 1 socket welds is adequately addressed, and 

Confirmatory Item 3.0.3.2.13-1 is closed. 

By letter dated December 3, 2010, the applicant also provided information regarding its 

inspection schedule. The applicant stated that the One-Time Inspection Program will be 

implemented within the 6 years prior to the period of extended operation. The staff finds the 

applicant’s proposed inspection schedule is consistent with the recommendations of the GALL 

Report regarding timely implementation of the small bore piping inspections and is, therefore, 

acceptable. 

Based on its review of the applicant’s responses to RAIs B2.1.19-1 and B2.1.19-2, the staff 

finds that elements one through six of the applicant’s One-Time Inspections of ASME Code 

Class 1 Small Bore Piping Program, with an acceptable exception, are consistent with the 

corresponding program elements of the GALL Report AMP and are therefore, acceptable. 

Operating Experience. LRA Section B2.1.19 summarizes operating experience related to the 

one-time inspections of the ASME Code Class 1 Small Bore Piping program. The LRA states 

that it has experienced cracking of stainless steel ASME Code Class 1 piping less than or equal 

to a nominal pipe size of 4 inches. Furthermore, a hairline weld failure was caused by cyclic 

fatigue due to vibration combined with inadequate support on a shutdown cooling suction line. 

The applicant performed piping modifications that have reduced the excessive vibration. The 

applicant’s review of the second 10-year ISI Interval Summary Reports for Units 1, 2, and 3 

indicate there were no code repairs or code replacements required for continued service of 

ASME IWB Code components during the second 10-year ISI interval. 

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicant reviewed the applicable aging effects and industry and plant-specific 

operating experience. As discussed in the Audit Report, the staff conducted an independent 

search of the plant operating experience information to determine if the applicant had 

adequately incorporated and evaluated operating experience related to this program. 

The staff’s independent search of plant-specific operating history found three instances of 

cracking of Class 1 small-bore piping. The staff noted that LER 528-1987-018, 

LER 528-1996-006, and LER 528-2004-001 document the relevant cases of cracking. The staff 

noted that the applicant needs to evaluate all of the cracking events and determine if it needs a 

plant-specific AMP for periodic inspections of ASME Code Class 1 small-bore piping, as 

recommended in the GALL Report AMP. By letter dated December 29, 2009, the staff issued 

RAI B2.1.19-3 asking the applicant to provide plans to manage the aging of small-bore piping. 

In its response, dated February 19, 2010, the applicant stated that it has experienced three 

instances where failures have occurred in ASME Code Class 1 small-bore piping with socket 

welds; the failures were reported in Licensee Event Reports LER 528-1987-018, 

LER-528-1996-006, and LER 528-2004-001. The applicant further stated that it conducted 

evaluations to determine the cause of each of the failures. In each case, the applicant 
Aging Management Review Results 

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determined that the failure was a design-related failure that resulted from improper support of 

the components. The applicant stated that since cracking due to stress corrosion or thermal 

and mechanical loading was determined not to be the cause, a plant-specific AMP is not 

necessary. 

Based on its review, the staff finds the applicant’s response to RAI B2.1.19-3 unacceptable 

because the information from the operating experience review indicated that all three failures 

were due to high-cycle fatigue. The staff noted that high-cycle fatigue is a form of mechanical 

loading. The applicant’s response did not include an adequate basis to conclude that a 

plant-specific AMP is not necessary. 

The GALL Report One-Time Inspection of ASME Code Class 1 Small-Bore Piping AMP 

recommends the use of the One-Time Inspection of ASME Code Class 1 Small-Bore Piping 

only for those plants that have not experienced cracking of ASME Code Class 1 small-bore 

piping resulting from stress corrosion or thermal and mechanical loading. It further states that 

for those plants that have experienced cracking, it recommends periodic inspection of the 

subject piping, managed by a plant-specific AMP. 

In a conference call, dated July 21, 2010, the applicant clarified that one of the socket weld 

failures reported was out of the scope of license renewal since it was determined to be an 

ASME Code Class 2 component. The applicant stated that it had experienced two failures in 

ASME Code Class 1 small-bore welds due to the same design deficiency, therefore, it will revise 

its operating experience discussion and withdraw LER 528-1996-006. The applicant stated that 

it corrected the design deficiency and has not experienced failures for an extended period of 

time. 

The staff agrees that the applicant does not have to count failures of non-class 1 components in 

the context of program applicability. The staff also agrees that the One-Time Inspection AMP 

still applies because the applicant implemented design changes to mitigate the causal factors. 

As part of the corrective action process, it also evaluated similar systems and components. The 

staff agrees that the applicant has not experienced failures for an extended period of time; 

however, the staff emphasized that the applicant must justify its proposed sample size of the 

One-Time Inspection Program as statistically significant. The applicant agreed to modify its 

commitment associated with this program to incorporate the expanded sample size. These 

actions are consistent with the GALL Report One-Time Inspection of ASME Code Class 1 

Small-Bore Piping AMP. 

The staff finds that the operating experience related to the applicant’s program demonstrates 

that it can adequately manage the detrimental effects of aging on SSCs within the scope of the 

program and that implementation of the program has resulted in the applicant taking corrective 

actions. The staff confirmed that the “operating experience” program element satisfies the 

criterion in SRP-LR Section A.1.2.3.10 and is, therefore, acceptable. 

UFSAR Supplement. LRA Section A1.19 provides the UFSAR supplement for the One-Time 

Inspections of ASME Code Class 1 Small-Bore Piping Program. The staff reviewed this UFSAR 

supplement description of the program against the recommended description for this type of 

program, as described in SRP-LR Table 3.1-2. The staff notes that the applicant committed 

(Commitment No. 21) to implement the One-Time Inspection of ASME Code Class 1 Small-Bore 

Piping Program prior to entering the period of extended operation to manage the aging of 

applicable components. The staff determines that the information in the UFSAR supplement is 

an adequate summary description of the program, as required by 10 CFR 54.21(d). 

Conclusion. On the basis of its audit and review of the applicant’s One-Time Inspection of 

ASME Code Class 1 Small-Bore Piping Program, the staff determines that those program 

elements for which the applicant claimed consistency with the GALL Report AMP are 

consistent. In addition, the staff reviewed the exception and justification, and determines that 
Aging Management Review Results 

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the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits 

it. The staff concludes that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended functions will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the UFSAR supplement for this AMP, and concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d). 

3.0.3.2.14 External Surfaces Monitoring Program 

Summary of Technical Information in the Application. LRA Section B2.1.20 describes the new 

External Surfaces Monitoring Program as consistent, with an exception, with the GALL Report 

AMP XI.M36, “External Surfaces Monitoring.” The applicant stated that the program manages 

loss of material on the external surfaces of steel, aluminum, and copper alloy components, and 

hardening and loss of strength of elastomeric materials. In addition, the applicant stated that 

the program includes the use of visual inspection and physical manipulation. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. The staff compared elements one 

through six of the applicant’s program to the corresponding elements of the GALL Report 

External Surfaces Monitoring AMP. As discussed in the Audit Report, the staff confirmed that 

each element of the applicant’s program is consistent with the corresponding element of the 

GALL Report AMP, with the exception of the “parameters monitored or inspected” and 

“detection of aging effects” program elements. For these elements, the staff determined the 

need for additional clarification, which resulted in the issuance of RAIs. The staff’s RAIs and the 

applicants responses are discussed under evaluation of the exception below. 

The staff also reviewed the portions of the “scope of program,” “preventive actions,” “detection 

of aging effects,” “monitoring and trending,” and “acceptance criteria” program elements 

associated with the exception to determine whether the program will be adequate to manage 

the aging effects for which it is credited. The staff’s evaluation of this exception follows. 

Exception. LRA Section B2.1.20 identifies an exception to the “scope of program,” “preventive 

actions,” “detection of aging effects,” “monitoring and trending,” and “acceptance criteria” 

program elements. The staff also considers this exception to affect the “parameters monitored 

or inspected” program element. The exception concerns the inclusion of aluminum, copper 

alloy, and elastomeric materials in the applicant’s program, whereas the GALL Report AMP only 

manages aging effects associated with steel components. The applicant’s External Surfaces 

Monitoring Program includes a provision to conduct physical manipulations as part of the 

inspection of elastomeric materials to address the aging effect of loss of ductility. The applicant 

intends to apply the visual inspection methods recommended in the GALL Report AMP to 

inspect aluminum and copper alloys. 

The GALL Report External Surfaces Monitoring AMP recommends visual inspection of 

component surfaces at least once per refueling cycle. The Gall Report AMP recommends that 

the applicant inspect surfaces that are inaccessible or not readily visible during plant operations 

and refueling outages at intervals that would ensure that the component intended function is 

maintained. In addition to visual inspections, the applicant’s program includes physical 

manipulation to detect elastomeric material aging effects, such as hardening and surface texture 

changes. However, under the applicant’s AMP, not all inaccessible elastomeric components 

are physically manipulated to detect aging effects. 

By letter dated December 29, 2009, the staff issued RAI B2.1.20-1 requesting that the applicant 

provide details on its use of alternative methods to detect the effects of aging on those 

elastomeric components not accessible for physical manipulation. If the aging management 

method involves sampling or inspection of an equivalent or analogous component, material, and 
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environment combination, such that aging specific to these artifacts will be detected, the staff 

requested the applicant to provide the alternative methods. 

In its response, dated February 19, 2010, the applicant stated that visual inspections are the 

primary method for detecting degradation of elastomeric components. The applicant specified 

that these visual inspections include observation of discoloration, checkering, and cracking, 

which are visually detectable age-related degradation effects for elastomers. The applicant also 

stated that physical manipulation can verify the absence of hardening or loss of strength for 

elastomers. The applicant further stated that it identified no specific elastomeric components 

expected to be inaccessible to visual inspection. 

However, the staff notes that visual examination of the external surfaces of an elastomer may 

not always reveal the need for physical manipulation because hardening does not always 

display checkering or cracking. The staff finds the applicant’s response to RAI B2.1.20-1 

unacceptable because visual examination alone is not an appropriate method to determine 

whether an elastomer is experiencing hardening or loss of strength. In a letter dated 

June 21, 2010, the applicant supplemented its response to RAI B2.1.20-1, stating that it will 

conduct physical manipulation on all accessible elastomeric material. The staff finds this 

response acceptable because the combination of visual examination and physical manipulation 

of elastomers has proven to be effective in detecting degradation in elastomers. The staff’s 

concern in RAI B2.1.20-1 is resolved. 

The GALL Report External Surfaces Monitoring AMP consists of periodic visual inspections of 

steel components to manage loss of material on external surfaces. The applicant’s program is 

also credited with managing aging of aluminum components. Compared to steel, aluminum is 

not as conducive to visual inspection to detect degradation because under the pertinent plant 

environments and conditions, the degradation of aluminum involves the formation of a thin 

aluminum oxide film, which is indistinguishable from its initial service condition. The extent of 

corrosion of aluminum is not detectable by the visual inspection methods used for steel until the 

degradation is so extensive that component functionality is compromised. 

By letter dated December 29, 2009, the staff issued RAI B2.1.20-2 requesting that the applicant 

explain how visual inspections can assess loss of material on aluminum components. The staff 

also requested if the applicant intends to use other contact methods or optical instruments in the 

inspection process. 

In its response, dated February 19, 2010, the applicant stated that it does not anticipate rapid 

and aggressive corrosion because the aluminum components are exposed to a mild 

environment. The applicant further stated that visual inspection of aluminum components 

includes the specific, visually observable corrosion effects of chipping, cracking, flaking, 

oxidizing, or missing paint and coatings and that presence of these corrosion effects would 

indicate degradation deficiencies before the loss of component intended function. 

The staff finds the applicant’s response acceptable because the program specifically includes 

the observation of aging defects on painted surfaces or protective coatings, and pitting corrosion 

is a visually detectable aging effect on non-painted or non-coated aluminum components. 

Inspection of paint or coatings on external surfaces provides an adequate method to manage 

aging effects of aluminum components because this method does not rely solely on detection of 

oxidation and general corrosion products on bare aluminum metal surfaces. The staff’s concern 

described in RAI B2.1.20-2 is resolved. 

Based on its audit, review of the application, and review of the applicant’s responses to RAIs 

B2.1.20-1 and B2.1.20-2, the staff finds that elements one through six of the applicant’s External 

Surfaces Monitoring Program, and an acceptable exception, are consistent with the 

corresponding program elements of the GALL Report External Surfaces Monitoring AMP and 

are, therefore, acceptable. 
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Operating Experience. LRA Section B2.1.20 summarizes operating experience related to the 

External Surfaces Monitoring Program. The applicant stated that, while this is a new program, 

existing system inspections via walkdowns have been effective in maintaining the material 

condition of plant systems. The applicant also stated that these inspections are consistent with 

industry practice. The applicant further stated that it initiates corrective actions for any 

deficiencies or adverse trends identified in the walkdowns. 

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicant reviewed the applicable aging effects and industry and plant-specific 

operating experience. As discussed in the Audit Report, the staff conducted an independent 

search of the plant operating experience information to determine if the applicant had 

adequately incorporated and evaluated operating experience relevant to this program. The staff 

found that the applicant had adequately identified and incorporated industry and applicable 

plant-specific operating experience. 

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10 and is, 

therefore, acceptable. 

UFSAR Supplement. LRA Section A1.20 provides the UFSAR supplement for the External 

Surfaces Monitoring Program. The staff reviewed this UFSAR supplement description of the 

program and notes that it conforms to the recommended description for this type of program, as 

described in SRP-LR Tables 3.2-2, 3.3-2, and 3.4-2. The staff also notes that the applicant 

committed (Commitment No. 22) to implement the new External Surfaces Monitoring Program 

prior to entering the period of extended operation to manage the aging of applicable 

components. The staff determines that the information in the UFSAR supplement is an 

adequate summary description of the program, as required by 10 CFR 54.21(d). 

Conclusion. On the basis of its audit and review of the applicant’s External Surfaces Monitoring 

Program, the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report are, indeed, consistent. In addition, the staff reviewed the 

applicant's exception and its justification, and determines that the AMP, with the exception, is 

adequate to manage the aging effects for which the LRA credits it. The staff concludes that the 

applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended functions will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP, and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

3.0.3.2.15 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program 

Summary of Technical Information in the Application. LRA Section B2.1.22 describes the new 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program as 

consistent, with exceptions with the GALL Report AMP XI.M38, “Inspection of Internal Surfaces 

in Miscellaneous Piping and Ducting Components.” The applicant stated that this program 

manages cracking and loss of material of internal surfaces of piping, piping components, and 

ducts made of steel, aluminum, and copper alloys. In addition, the program manages the 

hardening and loss of strength of elastomers. The applicant also stated that it will conduct 

visual inspections to identify conditions that could result in the loss of intended functions in 

SSCs. Inspections include surface or volumetric examinations for cracking of stainless steel 

exposed to diesel exhaust and external or internal physical manipulation of elastomers to 

assess their hardening and loss of strength. The applicant further stated that the program 
Aging Management Review Results 

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pertains to the aging management of the above-listed hardware not supported by other 

programs, and this AMP will use a site-specific work control process to conduct and document 

the recommended inspections. The applicant also stated that within 10 years of the start of the 

period of extended operation, it will review the process to ensure that there are enough 

inspections of components covered by this AMP to establish the adequacy of the inspections. If 

it conducts an insufficient number of inspections, additional inspections will be carried out to 

assure completeness before entering the period of extended operation. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. 

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of the GALL Report Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components AMP. As discussed in the Audit Report, the staff confirmed that each 

element of the applicant’s program is consistent with the corresponding element of the GALL 

Report AMP, with the exception of the “detection of aging effects” and the “acceptance criteria” 

program elements related to fire protection piping. For these elements, the staff determined the 

need for additional clarification, which resulted in the issuance of an RAI. By letter dated 

December 29, 2009, the staff issued RAI B2.1.22-1 requesting that the applicant provide clarify 

the “detection of aging effects” and “acceptance criteria” program elements for thinning and 

narrowing of pipe walls. 

In its response by letter dated February 19, 2010, the applicant stated that for the “detection of 

aging effects” program element it will use visual inspections to assess the condition of piping. If 

it witnesses wall thinning, by evidence of pitting, erosion, or other corrosion mechanisms, then it 

will conduct ultrasonic inspections to verify the adequacy of pipes for continued operation. For 

the “acceptance criteria” program element, the applicant stated that it will follow the ASME or 

American National Standards Institute (ANSI) specifications or design calculations for minimum 

wall thickness. The applicant further stated that it clarified the “acceptance criteria” program 

element in the basis document to reflect the method used to quantify and track the thinning of 

pipes. The staff reviewed the applicant’s response to RAI B2.1.22-1 and finds it acceptable 

because visual examinations of pipes, followed by UT, are suitable to characterize pipe wall 

thickness with its acceptance based on industry standards or engineering calculations. 

The staff also reviewed the portions of the “scope of program,” “parameters monitored or 

inspected,” “detection of aging effects,” and “monitoring and trending” program elements 

associated with exceptions to determine if the program will be adequate to manage the aging 

effects for which it is credited. 

Exception 1. LRA Section B.2.1.22 identifies an exception to the “scope of program,” 

“parameters monitored or inspected,” “detection of aging effects,” and “monitoring and trending” 

program elements. The applicant recognized that the inclusion of stainless steel, aluminum, 

copper alloys, and elastomers in the “scope of program,” beyond steel, constitutes an exception 

to the GALL Report AMP. To detect aging effects and degradation of materials, the applicant 

stated that it will continue to use visual examination techniques to assure there is no loss of 

intended functions in piping, piping components, ducts, and other components. The staff noted 

that the GALL Report allows for visual examinations and observations for loss of material, 

provided that the inspected material is steel. The staff also noted that aluminum, stainless steel, 

and copper alloys typically do not have painted surfaces, which indicate the severity of aging on 

the material surface. The staff further noted that program element “detection of aging effects,” 

of the GALL Report, calls for the applicant to identify and justify the inspection technique used 

for detecting the aging effects of concern. 
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Upon further review of the LRA, amendments, and RAI responses, the staff found that the 

applicant will use the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program to manage aging of aluminum and copper alloy materials. In RAIs 

B2.1.10-2 and B2.1.20-2, dated December 29, 2009, the staff asked the applicant to provide 

input on the detection, monitoring, and trending of aging effects on internal surfaces of relevant 

hardware made of aluminum. By letter dated February 19, 2010, the applicant responded 

noting that the resistance to corrosion of aluminum and iron-based and copper-based alloys 

depends on their environment. In most environments, aluminum will exhibit excellent corrosion 

resistance due to its regenerating surface oxide film. For iron-based and copper-based alloys 

exposed to the closed-cycle cooling water chemistry, the applicant will use corrosion inhibitors 

to manage loss of material. For aluminum, in the closed-cycle cooling water chemistry, the 

applicant does not anticipate rapid and aggressive loss of material and pitting because the 

water chemistry moderates the chloride and total halide ion concentrations. When visually 

inspecting components made of iron-based and copper-based alloys, the applicant will look for 

pitting, discoloration, surface irregularities, cracking, and other signs of distress. If visual 

internal inspections indicate age-related degradation in excess of the established acceptance 

criteria, then the applicant will remedy any deficiencies via its corrective action program. The 

staff agrees with the applicant’s response. The applicant addresses the staff's concern in the 

responses to RAIs B2.1.10-2 and B2.1.20-2, and it is resolved. 

In programs where the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components AMP serves in a supporting role, as in the Closed-Cycle Cooling Water System 

Program, the applicant stated that it manages corrosion via inhibitors. 

With the information provided by the applicant, the staff finds this program exception acceptable 

because the applicant will accomplish detection, monitoring, and trending of aging effects in 

stainless steel, aluminum, and copper alloys through an established work control process. The 

applicant will remedy deficiencies per its corrective action program and, within 10 years before 

extended operation, it will review all systems within the scope of the program for aging effects to 

provide reasonable assurance that their intended functions will remain through the next 

inspection cycle. Exception 2 below provides the staff's evaluation of the exception specific to 

elastomers. 

Exception 2. LRA Section B.2.1.22 states a second exception affecting the “scope of program,” 

“parameters monitored or inspected,” “detection of aging effects,” and “monitoring and trending” 

program elements. The applicant stated this exception includes visual and physical inspections 

of elastomers to assess hardening and loss of strength. The staff acknowledged the inclusion 

of elastomers to be an exception to the “scope of program” element and the applicant’s intent to 

track their hardening and loss of strength to be an exception to the “parameters monitored or 

inspected” element. The staff also noted that the applicant identified and justified the inspection 

technique as recommended by the GALL Report “detection of aging effects” program element, 

yet, the technique is in addition to the visual examination recommended by the GALL Report 

and affects the “monitoring and trending” program element. By letters dated 

December 29, 2009, and February 19, 2010, the staff issued RAIs B2.1.20-1 and 3.3.2.2.5-1, 

respectively, which requested the applicant to clarify any conditions limiting the testing and 

inspections of elastomers (i.e., inaccessible locations, thermal aging, etc.). By letters dated 

February 19, 2010, and March 24, 2010, the applicant responded to the RAIs, stating that there 

are no inaccessible elastomers for inspection and that it will inspect all elastomeric flexible 

components based on plant procedures irrespective of the prevailing temperatures. 

Upon review of the LRA and the applicant’s responses to the RAIs, the staff finds this program 

exception acceptable because the applicant has defined appropriate inspection techniques 

(physical manipulations and supplemental tests if necessary) to assure the elastomers are 

properly monitored and inspected and that their pliability and ductility remains through the next 
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inspection cycle. In addition, the applicant will remedy deficiencies per its corrective action 

program and, within 10 years of entering the period of extended operation, it will check 

elastomers for aging effects to provide reasonable assurance that their intended functions will 

remain through the next inspection cycle. 

Exception 3. LRA Section B.2.1.22 states a third exception to the “scope of program,” 

“parameters monitored or inspected,” “detection of aging effects,” and “monitoring and trending” 

program elements. In this exception the applicant stated that for stainless steel components 

exposed to diesel exhaust, it will use a volumetric evaluation to detect SCC of applicable 

internal surfaces. The staff noted that NUREG 1833, “Technical Bases for Revision to the 

License Renewal Guidance Documents,” recommends a plant-specific AMP to evaluate 

whether the hot diesel exhaust gases will negatively affect the internal surfaces of the diesel 

engine exhaust piping and piping components. The staff evaluated and accepted this exception 

because the applicant uses Subsection IWA-2000 of the ASME Code Section XI for volumetric 

and visual examination techniques as valid inspection methods for the detection of cracking in 

metallic components. In addition, the applicant will remedy deficiencies per its corrective action 

program and will check the internal surfaces of the diesel exhaust piping and its components for 

aging effects within 10 years before entering the period of extended operation. 

Based on its audit and review of the applicant’s response to RAIs, the staff finds that elements 

one through six of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program, with acceptable exceptions, are consistent with the 

corresponding program elements of the GALL Report Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components AMP and are, therefore, acceptable. 

Operating Experience. LRA Section B2.1.22 summarizes operating experience related to the 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The applicant 

stated that this is a new program; therefore, there is no programmatic operating experience. In 

discussions between the applicant and the staff, the staff concluded that the operating 

experience identified by the staff’s independent database search, supplemented by the 

applicant during the audit, is bounded by industry operating experience (i.e. no previously 

unknown aging effects were identified by the applicant or the staff). 

The staff, however, noted that any operating experience resulting from maintenance and 

inspection activities of systems and components that is supportive to this AMP, should be 

included. By letter dated December 29, 2009, the staff issued RAI B2.1.16-1 requesting the 

applicant to provide a summary of operating experience resulting from observations for loss of 

material, cracking, and loss of heat transfer related maintenance, inspections, and associated 

corrective action activities. In its response, dated February 19, 2010, the applicant stated that 

the plant-specific operating experience compiled from 1996–October 2009 resulted in 

16,000 aging effects documents. These instances, however, were more relevant to other 

programs such as the Lubricating Oil Analysis Programs (i.e., the applicant exhibited the 

capacity to effectively identify the existence of water in the lubricating oil which could result in a 

loss of material of internal surfaces of such environments). 

Based on its audit, review of the application, and response to the RAI, the staff finds that 

operating experience related to the applicant’s program demonstrates that it can adequately 

inspect and assess detrimental conditions affecting the aging of SSCs within the scope of the 

program. The staff confirmed that the “operating experience” program element satisfies the 

criterion in SRP-LR Section A.1.2.3.10 and is, therefore, acceptable. 

UFSAR Supplement. LRA Section A1.22 provides the UFSAR supplement for the Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program. The staff reviewed this 

UFSAR supplement description of the program against the recommended description for this 

type of program, as described in SRP-LR Tables 3.2-2, 3.3-2, and 3.4-2. The staff also notes 
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that the applicant committed (Commitment No. 24) to implement the new Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program prior to entering the period 

of extended operation to manage the aging of applicable components. The staff determines 

that the information in the UFSAR supplement is an adequate summary description of the 

program, as required by 10 CFR 54.21(d). 

Conclusion. On the basis of its audit and review of the applicant’s Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program, the staff determines that 

those program elements for which the applicant claimed consistency with the GALL Report are 

consistent. In addition, the staff reviewed the exceptions and justifications, and determines that 

the AMP, with the exceptions, is adequate to manage the aging effects for which the LRA 

credits it. The staff concludes that the applicant has demonstrated that the effects of aging will 

be adequately managed so that the intended functions will be maintained consistent with the 

CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the UFSAR supplement for this AMP, and concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d). 

3.0.3.2.16 Lubricating Oil Analysis Program 

Summary of Technical Information in the Application. LRA Section B2.1.23 describes the 

existing Lubricating Oil Analysis Program as consistent, with exceptions, with the GALL Report 

AMP XI.M39, “Lubricating Oil Analysis.” The applicant stated that the Lubricating Oil Analysis 

Program manages loss of material and reduction of heat transfer for components with surfaces 

exposed to lubricating and hydraulic oils. The applicant also stated that the program ensures 

that it maintains lubricating and hydraulic oil environments in mechanical systems to the 

required quality based on vendor and industry guidelines. The program monitors and controls 

oil contaminants, primarily water and particulates within acceptable limits, thereby preserving an 

environment that is not conducive to aging effects and that selected components’ aging will be 

tracked so that corrective actions can be taken before a loss of intended function occurs. The 

program is implemented through plant procedures that address sampling, testing, and 

management of samples and schedules. Its effectiveness is verified through the One-Time 

Inspection Program (see SER Section 3.0.3.2.13). 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. The staff compared elements one 

through six of the applicant’s program to the corresponding elements of the GALL Report 

Lubricating Oil Analysis AMP. As discussed in the Audit Report, the staff confirmed that each 

element of the applicant’s program is consistent with the corresponding element of the GALL 

Report AMP, with the exception of the “parameters monitored or inspected” and “acceptance 

criteria” program elements. For these elements, the staff determined the need for additional 

clarifications, which resulted in the issuance of RAIs. 

The “acceptance criteria” program element of the GALL Report Lubricating Oil Analysis AMP 

recommends particle concentration to be determined in accordance with industry standards. 

For each component, water and particle concentration should be based on the manufacturer’s 

recommendations or industry standards. Viscosity band tolerances and metal limits, determined 

by spectral analysis and ferrography, are also based on manufacturer’s recommendations, 

industry standards, or other justified basis. The applicant, however, stated that testing criteria, 

as described in its basis document, may be exceeded, but this would not necessarily mean the 

lubricating oil is “non-conforming.” The staff noted that the applicant did not substantiate the 

basis for using lubrication oil with parameters outside the limits of the acceptance criteria. By 

letter dated December 29, 2009, the staff issued RAI B2.1.23-1 requesting the applicant to 

provide its sources of the acceptance criteria and its justification for the continued use of 

lubricating oil outside manufacturer’s recommendations or industry standards. 
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In its response, dated February 19, 2010, the applicant revised the Lubricating Oil Analysis AMP 

basis document to reflect the background for program element “acceptance criteria” and clarify 

the method by which the continued use of lubricating oil outside manufacturer’s 

recommendations or industry standards is allowed, subject to the approval of the lubrication 

engineer. Justification for the continued use is based on industry guidelines, national standards, 

suppliers’ and manufacturers’ specifications, and academic literature. 

The staff reviewed the applicant’s input and compared the references used by the applicant to 

those listed in the GALL Report Lubricating Oil Analysis AMP. For example, the industry 

standard ASTM D 4378—also acceptable by the International Standardization Organization—

provides background and guidance for monitoring, sampling, testing, validating, and ensuring 

lubricants remain within acceptable parameters throughout their life cycle in power generating 

turbines. ASTM D 6224 provides background and guidance for monitoring mineral oils based 

on testing, rather than their in-service or calendar time, to save operating and maintenance 

costs while minimizing machine problems. The staff finds these references applicable and the 

applicant’s response to RAI B2.1.23-1 acceptable because the applicant revised the Lubricating 

Oil Analysis AMP basis document element “acceptance criteria” to reflect current industry 

practices while maintaining a firm foundation on fundamentals. The staff finds the applicant’s 

Lubricating Oil Analysis Program element “acceptance criteria” to conform to the GALL Report 

Lubricating Oil Analysis AMP. The staff’s concern described in RAI B2.1.23-1 is resolved. 

The staff also reviewed the portions of the “parameters monitored or inspected” and 

“acceptance criteria” program elements associated with exceptions to determine whether the 

program will be adequate to manage the aging effects for which it is credited. The staff’s 

evaluation of these exceptions follows. 

Exception 1. LRA Section B2.1.23 identifies an exception to the “parameters monitored or 

inspected” and “acceptance criteria” program elements of the GALL Report. For components 

with periodic oil changes, the GALL Report recommends oil to be sampled for particle count and 

water contamination. These can indicate wear and corrosion in systems and components, 

which limit their intended functions. The LRA Lubricating Oil Analysis Program and its basis 

document state that diesel engine oils are evaluated based on elemental analysis techniques as 

described in ASTM D 6595, “Determination of Wear Metals and Contaminants in Used 

Lubricating Oils or Used Hydraulic Fluids by Rotating Disc Electrode Atomic Emissions 

Spectroscopy,” instead of particle count and water checks. These examination techniques are 

more thorough than those found in the GALL Report. The staff reviewed the applicant’s claim 

and noted that, even though emissions spectroscopy could determine the presence of wear 

metals and contaminants accurately, neither ASTM D 6595 nor the applicant’s basis document 

lists any acceptance criteria for the elemental analysis. By a letter dated December 29, 2009, 

the staff issued RAI B2.1.23-3 requesting the applicant to provide the acceptance criteria for 

elemental wear metals in lubricating oil and further information indicating that the elemental 

analysis gives a greater degree of insight into a lubricant’s condition over the particle counting 

technique. 

In its response, dated February 19, 2010, the applicant stated that ASTM D6595 does not have 

rigid acceptance criteria. Instead, the applicant uses it to define precision and accuracy in the 

collected data, determining trends in machine acceptability. The applicant conducts additional 

testing for data outliers and deals with operability issues through its corrective action program. 

The applicant also stated that National Academy of Sciences 1638, “Cleanliness Requirements 

of Parts Used in Hydraulic Systems,” listed in the GALL Report, advocates particle counting but 

does not discriminate between contaminants; whereas, the spectrometer testing and elemental 

analysis distinguishes between oil additives for performance enhancement versus wear metals. 

The staff finds that acceptance of lubricating oil based on trend analysis, with data collected 

through elemental analysis and then further trended, acceptable because of the applicant’s 
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close monitoring of oil and machine conditions. These techniques enhance its ability to take 

immediate corrective actions, thus ensuring SSCs will maintain their intended functions. The 

staff’s concern described in RAI B2.1.23-3 is resolved. Therefore, this exception to the GALL 

Report Lubricating Oil Analysis AMP is acceptable. 

Exception 2. LRA Section B2.1.23 identifies an exception to the “parameters monitored or 

inspected” and “acceptance criteria” program elements of the GALL Report Lubricating Oil 

Analysis Program. In the GALL Report AMP, program element “parameters monitored or 

inspected,” recommends that for components that do not have regular oil changes, the flash 

point is used to verify that the oil is suitable for continued use. The applicant stated that its 

Lubricating Oil Analysis Program considers flash point as an indicator of fuel oil contamination 

of the lubrication oil; therefore, only lubricating oil in components with a potential of 

contamination with fuel oil are subject to flash point testing. The staff noted that it is not 

necessary to monitor flash point for non-diesel applications because the potential for fuel oil 

contamination is minimal. Therefore, this exception to the GALL Report Lubricating Oil Analysis 

AMP is acceptable. 

Exception 3. LRA Section B2.1.23 identifies an exception to the “parameters monitored or 

inspected” and “acceptance criteria” program elements. In the GALL Report AMP, program 

element 3, “parameters monitored or inspected,” recommends that for components that do not 

have regular oil changes, the neutralization number is determined to verify the oil suitability for 

continued use. The applicant stated that its Lubricating Oil Analysis Program tests diesel 

engine lubrication oils using the “total base number” parameter. The applicant does not use the 

“total acid number” parameter for evaluations of lubricants because of its limited utility in engine 

applications. It was not clear to the staff why the applicant uses only the “total base number” to 

monitor the lubricating oil of diesel engines and what lubricating oils of other components will be 

monitored with the “total acid number.” By letter dated December 29, 2009, the staff issued 

RAI B2.1.23-2 requesting that the applicant provide a justification for monitoring only the “total 

base number” parameter for lubricating oil in diesel engines and also to provide information as 

to where the “neutralization number,” the “total acid number” and “total base number” is used for 

monitoring lubricating oil in other components. 

In its response, dated February 19, 2010, the applicant stated that it uses “neutralization” to 

identify the amount of titration injected to neutralize an oil sample. For example, the “total base 

number” indicates the amount of an acid added to the sample to neutralize its base, while the 

“total acid number” indicates the amount of base materials added to do the same for acidic oils. 

The applicant also stated that diesel oils by design are basic, but turn acidic during the 

combustion process. Base number testing is, therefore, admissible on diesel oils. The 

applicant also stated that its other lubricating oils do not have the base additive as part of their 

formulation. Testing of these oils for “total acid number” is, therefore, appropriate because they 

become increasingly acidic as they degrade. The staff finds this exception to the GALL Report 

Lubricating Oil Analysis AMP, element “parameters monitored or inspected,” acceptable 

because the applicant applies the appropriate neutralization number depending on the 

lubricating oil used in specific oil systems. The staff’s concern described in RAI B2.1.23-2 is 

resolved. Therefore, this exception to the GALL Report Lubricating Oil Analysis AMP is 

acceptable. 

Operating Experience. LRA Section B2.1.23 summarizes operating experience related to the 

Lubricating Oil Analysis Program. The applicant stated that the site specific operating 

experience revealed no patterns or events involving loss of the intended function of any systems 

or components as a result of aging effects related to lubricating oil contamination or 

degradation. 

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicant reviewed the applicable aging effects and industry and plant-specific 
Aging Management Review Results 

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operating experience. As discussed in the Audit Report, the staff conducted an independent 

search of the plant operating experience information to determine if the applicant had 

adequately incorporated and evaluated operating experience related to this program. The staff 

found that the applicant had adequately identified and incorporated industry and applicable 

plant-specific operating experience. 

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10 and is, 

therefore, acceptable. 

UFSAR Supplement. LRA Section A1.23 provides the UFSAR supplement for the Lubricating 

Oil Analysis Program. The staff reviewed this UFSAR supplement description of the program 

against the recommended description for this type of program, as described in SRP-LR 

Tables 3.2-2, 3.3-2, and 3.4-2. The staff also notes that the applicant committed (Commitment 

No. 25) to the ongoing implementation of the existing Lubricating Oil Analysis Program to 

manage the aging of applicable components during the period of extended operation. The staff 

determines that the information in the UFSAR supplement is an adequate summary description 

of the program, as required by 10 CFR 54.21(d). 

Conclusion. On the basis of its audit and review of the applicant’s Lubricating Oil Analysis 

Program, including responses to RAIs, the staff determines that those program elements for 

which the applicant claimed consistency with the GALL Report are consistent. In addition, the 

staff reviewed the exceptions and justifications, and determines that the AMP, with the 

exceptions, is adequate to manage the aging effects for which the LRA credits it. The staff 

concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended functions will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR supplement for this AMP, and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d). 

3.0.3.2.17 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Used in Instrumentation Circuits Program 

Summary of Technical Information in the Application. LRA Section B2.1.25 describes the 

existing Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements 

Used in Instrumentation Circuits Program as consistent, with enhancements, to the GALL 

Report AMP XI.E2, “Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ 

Requirements Used in Instrumentation Circuits.” The applicant stated that the scope of the LRA 

program includes the cables and connections used in sensitive instrumentation circuits with 

sensitive, high voltage, low-level signals within the ex-core neutron monitoring system. The 

applicant also stated that the program manages embrittlement, cracking, melting, discoloration, 

swelling, or loss of dielectric strength leading to reduced insulation resistance. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report AMP. The staff also reviewed the enhancements to determine whether the 

enhancements will make the program consistent with the one described in the GALL Report. 

The staff also reviewed and confirmed that the plant’s conditions are bounded by the conditions 

for which the GALL Report was evaluated. The staff compared elements one through six of the 

applicant’s program to the corresponding elements of the GALL Report AMP. As discussed in 

the Audit Report, the staff confirmed that each element of the applicant’s program is consistent 

with the corresponding element of the GALL Report AMP, with the exception of the radiation 

monitoring question discussed below. The staff determined the need for additional clarification, 

which resulted in the issuance of an RAI. 
Aging Management Review Results 

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The GALL Report AMP under the “scope of program” element states that this program applies 

to electrical cables and connections (cable system) used in circuits with sensitive, high-voltage, 

low-level signals such as radiation monitoring and nuclear instrumentation that are subject to an 

AMR. The LRA AMP, under the same program attribute only includes the ex-core neutron 

monitoring system cable system (nuclear instrumentation), and the staff noted that this does not 

include radiation monitoring. In a letter dated December 29, 2009, the staff issued 

RAI B2.1.25-1. This RAI requested the applicant to explain how the scope of the Electrical 

Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Used in 

Instrumentation Circuits Program is consistent with the corresponding GALL Report AMP, 

considering the fact that the LRA AMP does not include radiation monitoring cables. In 

response to the staff’s request, in a letter dated February 19, 2010, the applicant stated that all 

radiation monitors within the scope of license renewal, except for two, are either EQ or are 

active components with no external high-voltage, low-signal cable. The two non-EQ area 

radiation monitors, RU-37 and RU-38, had previously been evaluated as low-voltage instrument 

circuits and should have been evaluated as instrument circuits with sensitive, high-voltage, 

low-level signals. The applicant revised the scope of its program to include the non-EQ area 

radiation monitors, RU-37 and RU-38. The applicant also stated that it revised LRA Appendix 

A, Section A1.25 and Commitment No. 27 in Table A4-1, and Appendix B, Section B2.1.25 to 

include the non-EQ area radiation monitors within the scope of the program. The applicant 

further stated that it uses calibration surveillance tests to manage the aging of the cable 

insulation and connections for non-EQ area radiation monitors within the scope of license 

renewal. 

The staff finds the applicant response acceptable because the applicant included non-EQ area 

radiation monitors (RU-37 and RU-38) in the scope of the Electrical Cables and Connections 

Not Subject to 10 CFR 50.49 EQ Requirements Used in Instrumentation Circuits Program. 

Radiation monitoring cables that are environmentally qualified are subject to 10 CFR 50.49 

requirements and are not required to be in scope of the Electrical Cables and Connectors Not 

Subject to 10 CFR 50.49 EQ Requirements Used in Instrumentation Circuits Program. The 

cables that are inside active components are parts of an active assembly and are not subject to 

AMR. The staff’s concern in RAI B2.1.25-1 is resolved. 

The GALL Report Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ 

Requirements Used in Instrumentation Circuits Program states, under “detection of aging 

effects,” that in cases where a calibration or surveillance program does not include the cabling 

system in the surveillance, the applicant will perform cable system testing. In the LRA AMP, 

under the same program attribute, the applicant states the ex-core neutron monitoring system is 

calibrated every 18 months, in accordance with scheduled surveillance and maintenance testing 

procedures. The GALL Report AMP recommends that cables disconnected during scheduled 

surveillance are to be tested separately. 

In a letter dated December 29, 2009, the staff issued RAI B2.1.25-2 requesting the applicant to 

explain whether the ex-core neutron monitoring cables are disconnected during the 18-month 

scheduled surveillance. If they are, the staff requested the applicant to explain why it does not 

perform cable testing in accordance with the GALL Report AMP. If they are not, the staff 

requested the applicant to identify plant surveillance procedures that show that these cables are 

not disconnected. 

In a letter dated February 19, 2010, the applicant responded to the staff’s request stating that 

the ex-core neutron monitoring cables are disconnected during the 18-month scheduled 

surveillance and that it revised the LRA AMP to require testing of the ex-core neutron monitoring 

cables. The applicant also stated that it revised LRA Appendix A, Section A1.25 and 

Commitment No. 27 in Table A4-1 and Section B2.1.25 to require testing of the ex-core neutron 

monitoring cables. The applicant further stated that it conducts cable tests, such as insulation 
Aging Management Review Results 

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resistance testing or other tests, to detect deterioration of the cable insulation system. The 

applicant will test the cable before the period of extended operation and every 10 years 

thereafter. Before testing, the applicant will determine acceptance criteria based on the type of 

cable and type of test performed. The staff finds the applicant’s response acceptable because 

the ex-core neutron monitoring cables are disconnected during the 18-month surveillance and 

then tested separately. The testing frequency and methods are consistent with those in the 

GALL Report AMP. The staff’s concern in RAI B2.1.25-2 is resolved. 

The staff also reviewed the portions of the “scope of program,” “detection of aging effects,” and 

“corrective actions” program elements associated with enhancement to determine if the program 

will be adequate to manage the aging effects for which it is credited. The staff’s evaluation of 

this enhancement follows. 

Enhancements. In the LRA Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ 

Requirements Used in Instrumentation Circuits Program, the applicant stated that, before the 

period of extended operation, the following enhancement will be implemented in the following 

program elements: 

Scope of Program – Element 1, Parameters Monitored or Inspected - Element 3, 

Detection of Aging Effects - Element 4, Acceptance Criteria - Element 6, and 

Corrective Actions – Element 7 

Procedures will be enhanced to identify license renewal scope, require cable 

testing of ex-core neutron monitoring cables, require an evaluation of the 

calibration results for non-EQ area radiation monitors and require that 

acceptance criteria for cable testing be established based on the type of cable 

and type of test performed. 

The staff finds the enhancements acceptable because the action will be taken before the period 

of extended operation and will make the applicant’s existing program consistent with the 

recommendations in the GALL Report AMP. Further, the applicant has committed 

(Commitment No. 27) to implement these actions prior to the period of extended operation. 

Based on its audit and review, the staff finds that, with enhancements, elements one through 

six of the applicant’s Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ 

Requirements Used in Instrumentation Circuits Program are consistent with the corresponding 

program elements of the GALL Report AMP and are, therefore, acceptable. 

Operating Experience. LRA Section B2.1.25 summarizes operating experience related to the 

program. The applicant stated that industry operating experience has identified occurrences of 

cable and connection insulation degradation in high-voltage, low-level instrumentation circuits 

performing radiation monitoring and nuclear instrumentation functions. The majority of 

occurrences are related to cable and connection insulation degradation inside of containment 

near the RV or to a change in an instrument readout associated with a proximate change in 

temperature inside the containment. 

The applicant stated that a review of plant operating experience identified issues with ex-core 

noise and spiking. The applicant performed a root cause analysis and carried out corrective 

actions, including system walk-downs and testing, which identified cable and connection 

characterization. The applicant also stated that it continued coaxial connector replacements, 

utilization of ferrite beads, and improved grounding—all of which have been effective in 

improving overall performance. The staff noted that industry operating experience has identified 

a case where a change in temperature across a high-range radiation monitor cable in 

containment resulted in a substantial change in the reading of the monitor. The staff further 

noted that degradation of the circuit cable can cause changes in instrument calibration. 
Aging Management Review Results 

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The staff reviewed the operating experience, in the application and during the audit, to 

determine if the applicant reviewed the applicable aging effects and industry and plant-specific 

operating experience. As discussed in the Audit Report, the staff conducted an independent 

search of the plant operating experience information to determine if the applicant had 

adequately incorporated and evaluated operating experience related to this program. The staff 

found that the applicant had adequately identified and incorporated industry and applicable 

plant-specific operating experience. 

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10 and is, 

therefore, acceptable. 

UFSAR Supplement. LRA Section A1.25 provides the UFSAR supplement for the Electrical 

Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Used in 

Instrumentation Circuits Program. The staff reviewed this UFSAR supplement description of the 

program and notes that it conforms to the recommended description for this type of program, as 

described in SRP-LR Table 3.6-2. The staff also noted that the applicant committed 

(Commitment No. 27) to enhance the program prior to entering the period of extended operation 

to manage the aging of applicable components. The staff determines that the information in the 

UFSAR supplement, as amended, is an adequate summary description of the program, as 

required by 10 CFR 54.21(d). 

Conclusion. On the basis of its audit, review of the LRA including responses to RAIs, and 

review of the applicant’s Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ 

Requirements Used in Instrumentation Circuits Program, the staff finds that, with 

enhancements, all program elements are consistent with the GALL Report. The staff concludes 

that the applicant has demonstrated that 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 concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

3.0.3.2.18 American Society of Mechanical Engineers Section XI, Subsection IWE Program 

Summary of Technical Information in the Application. LRA Section B2.1.27 describes the 

existing ASME Section XI, Subsection IWE Program with exceptions that are consistent with the 

program elements in GALL Report AMP XI.SI, “ASME Section XI, Subsection IWE.” The ASME 

Section XI, Subsection IWE Program manages loss of material and loss of sealing of the steel 

liner of the concrete containment building. For the inspection interval from July 18, 2008 to 

July 17, 2018, for Unit 1; from March 18, 2007 to March 17, 2017, for Unit 2; and from 

January 11, 2008 to January 10, 2018, for Unit 3; PVNGS performs containment ISIs in 

accordance with the 2001 Edition of ASME Section XI, Subsection IWE, with the 2002 and 2003 

addenda, supplemented with the applicable requirements of 10 CFR 50.55a(b)(2)(ix). 

The applicant conducts inspections to identify and manage any containment liner degradation 

due to loss of material that could result in loss of intended function. Included in this inspection 

program are the containment liner plate and its integral attachments, such as piping and 

electrical penetrations, access hatches, the fuel transfer tube, and pressure-retaining bolting. 

The applicant uses a general visual examination to identify indications of degradation. All areas 

requiring augmented examination, per criteria IWE-1240 and IWE-2420, receive a detailed 

visual inspection. Article IWE-3000 specifies acceptance criteria for components subject to IWE 

exam requirements. 
Aging Management Review Results 

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Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. The staff compared elements one 

through six of the applicant’s program to the corresponding elements of the GALL Report ASME 

Section XI, Subsection IWE program. As discussed in the Audit Report, the staff confirmed that 

the program elements “preventive actions,” “parameters monitored or inspected,” “detection of 

aging effects,” and “monitoring and trending” of the LRA AMP were consistent with the 

corresponding elements of the GALL Report AMP. Sufficient information was not available to 

determine if elements “scope of program,” and “acceptance criteria” of the LRA AMP were 

consistent with the corresponding elements of the GALL Report AMP. 

In order to obtain the information necessary to verify if the LRA program element “scope of 

program” is consistent with the corresponding element of the GALL Report AMP, the staff 

issued RAI B2.1.27-2 in a letter dated December 29, 2009. This RAI requested the applicant to 

explain why it did not include pressure retaining bolts in the scope of the LRA ASME Section XI, 

Subsection IWE AMP. In addition, the applicant was requested to explain how it implements the 

recommendations contained in EPRI NP-5769, EPRI TR-104213 and NUREG-1339 to prevent 

or mitigate degradation or failure of structural bolts with actual yield strength of 150 kilo-pounds 

per square inch (ksi) for containment high-strength, pressure-retaining bolts. 

In its response to RAI B2.1.27-2, dated February 19, 2010, the applicant stated that the LRA 

program inspects pressure-retaining, high-strength bolts for aging management as part of the 

ASME Section XI, Subsection IWE Program. In addition, it has revised the AMP to add 

“pressure retaining bolting” to the list of in-scope components in the program element “scope of 

program.” 

The applicant also stated that there are no containment pressure retaining bolts used that are 

subject to the recommendations contained in EPRI NP-5769, EPRI TR-104213, and 

NUREG-1339. The operating experience addressed in these documents concerns bolting 

material with yield strength above 150 ksi. PVNGS specifications require that bolting subjected 

to the internal containment design pressure shall conform to ASME SA-320, Grade L43, or 

ASME SA-325. ASME SA-320, Grade L43 bolting material has a specified minimum yield 

strength of 105 ksi. ASME SA-325 bolting material has a specified minimum yield strength of 

92 ksi or 81 ksi, depending on the bolt size. 

The staff finds the applicant’s response to B2.1.27-2 acceptable because the applicant has 

revised the AMP to add pressure retaining bolts to the ASME Section XI, Subsection IWE AMP 

list of in-scope components. The pressure retaining bolts used have a minimum yield strength 

of between 81 ksi and 105 ksi, and there is a reasonable assurance that the actual yield 

strength of these bolts will not exceed 150 ksi. Therefore, additional evaluations for SCC, as 

recommended in NUREG 1339, EPRI NP-5769, and EPRI TR-104213, are not necessary for 

the pressure retaining bolts used by the applicant. Based on the preceding discussion, the staff 

has determined that the “scope of program” element of the LRA ASME Section XI, ISI IWE AMP 

is consistent with corresponding element of the GALL Report AMP. 

The program element “acceptance criteria” of the GALL Report AMP requires that containment 

steel material loss exceeding 10 percent of the nominal containment wall thickness, or material 

loss that is projected to exceed 10 percent wall thickness before the next examination, is 

documented. Such areas are to be accepted by engineering evaluation or corrected by repair 

or replacement in accordance with ASME Code, Subsection IWE-3122. During the audit, it was 

not clear to the staff how the applicant addresses this requirement in the AMP, since an 

applicant inspection report documented local degradation of the containment liner plate with 

loss of thickness of 0.04 inch. This local loss of thickness of 0.04 inch is more than 10 percent 

of the measured containment liner plate thickness of 0.263 to 0.27 inch minus the coating. 
Aging Management Review Results 

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Therefore, in RAI B2.1.27-4, the staff requested the applicant to explain the basis for 

acceptance of local loss of thickness of greater than 10 percent of the nominal wall thickness. 

In response to the RAI B2.1.27-4, dated February 19, 2010, the applicant stated that the 

containment liner plate was examined to evaluate a minor loss of material, apparently caused 

by the removal of a temporary lug. This slight damage to the containment liner plate resulted 

from original construction activities. The depth of the gouge was found to exceed 10 percent of 

the nominal thickness. In support of the engineering evaluation, the surrounding area was 

examined by UT to determine the actual thickness of the liner, and the responsible engineer 

evaluated the condition in accordance with the design specification. The condition was deemed 

acceptable with no corrective action required, and the damage was determined not to be 

aging-related and would not affect the ability of the liner plate to perform its intended function 

during the period of extended operation. 

The staff finds the response to RAI B2.1.27-4 acceptable because the applicant has performed 

an engineering evaluation in accordance with ASME Code, Section IWE-3122 to accept a 

material loss exceeding 10 percent of the nominal containment wall thickness. In addition, since 

the loss was determined not to be age-related, the applicant did not have to project material loss 

until the next IWE examination. Therefore, the staff has determined that element “acceptance 

criteria” of the LRA ASME Section XI, Subsection IWE AMP is consistent with the corresponding 

element of the GALL Report AMP. 

The staff also reviewed the portions of the program elements “scope of program,” “parameter 

monitored/inspected,” “monitoring and trending,” and “acceptance criteria,” associated with 

exceptions, to determine whether the program will be adequate to manage the aging effects for 

which it is credited. The staff’s evaluation of these exceptions follows. 

Exception 1. LRA Section B2.1.27 takes an exception to the “scope of the program” element. 

The applicant stated it will implement the 2001 edition of ASME Section XI, Subsection IWE. 

Pressure retaining containment seals and gaskets are not addressed by the 2001 edition of 

ASME Section XI, Subsection IWE (with the 2002 and 2003 addenda). These components are 

evaluated under 10 CFR Part 50, Appendix J. 

The staff finds the exception to the “scope of the program” program element acceptable 

because GALL AMP XI.S1, “ASME Section XI, Subsection IWE,” states that IWE evaluation 

shall be in accordance with the ASME Section XI, Subsection IWE 2001 edition including the 

2002 and 2003 Addenda. Pressure retaining seals and gaskets inspections were originally 

included in the 1995 edition of the ASME Section XI, Subsection IWE code but were eliminated 

from the 2001 edition (with the 2002 and 2003 addenda) of the code. 

Exception 2. LRA Section B2.1.27, takes an exception to program element 3, “parameters 

monitored or inspected.” In the GALL Report AMP, XI.S1, “ASME Section XI, Subsection IWE,” 

the program element provides seven categories of examination per Table IWE-2500-1. 

However, the program element in the LRA states that the program is in accordance with the 

2001 Edition of the ASME Section XI code, which does not specify seven categories of 

examination in Table IWE-2500-1. 

The staff finds this exception acceptable because the seven categories of examination listed in 

the GALL Report AMP were included in the 1995 Edition of the ASME Section XI code; 

however, they were deleted from the 2001 Edition of the code. The GALL Report AMP states 

that IWE evaluation shall be in accordance with the ASME Section XI, Subsection IWE 

2001 edition including the 2002 and 2003 addenda. 

Exception 3. LRA Section B2.1.27 takes an exception to program element 5 “monitoring and 

trending.” In the GALL Report AMP XI.S1, “ASME Section XI, Subsection IWE,” the program 

element recommends reexamining flaws accepted by engineering evaluation for three 
Aging Management Review Results 

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consecutive inspection periods. The GALL Report AMP program element also discusses 

additional examinations per IWE-2430. Alternatively, the program element in the LRA states 

that the program is in accordance with the 2001 Edition of the ASME Section XI code, which 

recommends reexamining flaws during the next inspection period; it deletes IWE-2430. 

The staff finds this exception acceptable because it complies with the intent of the GALL Report 

AMP XI.S1, “ASME Section XI, Subsection IWE,” to comply with IWE-2430 inspection 

periodicity. The 2001 Edition of the ASME Section XI, Subsection IWE, article IWE-2420 

requires reexamination of the flaws during the next inspection period and deletes IWE-2430 

which was included in 1995 edition of the code. 

Exception 4. LRA Section B2.1.27 takes an exception to the program element 6 (acceptance 

criteria). In the GALL Report AMP, this program element refers to acceptance criteria discussed 

in Table IWE-3410-1. Alternatively, these program elements in the LRA state, that Table 

IWE-3410-1 was deleted before the issuance of the 2001 Edition of ASME Section XI. The LRA 

further states that the acceptance standards previously specified in Table IWE-3410-1 are now 

given in Section IWE-3500. 

The staff finds this exception acceptable because it complies with the intent of the GALL Report 

AMP XI.S1, “ASME Section XI, Subsection IWE.” The applicant's use of IWE-3500 is 

appropriate since IWE-3410-1 was deleted from the ASME Section XI, Subsection IWE, 2001 

Edition of the code, but the intent is for applicants to continue to use this acceptance criteria. 

Operating Experience. LRA Section B2.1.27 summarizes operating experience related to the 

ASME Section XI ISI, IWE program. The applicant stated that it conducted the latest ASME 

Section XI, Subsection IWE program inspections at Units 1, 2, and 3 between April 2005 and 

May 2006. An evaluation of the results from the ISI examination indicated that the integrity of 

the containment system has been maintained. All discrepancies were corrected or determined 

“use-as-is,” in accordance with work control practices and ASME Section XI. 

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicant reviewed the applicable aging effects and industry and plant-specific 

operating experience. As discussed in the Audit Report, the staff conducted an independent 

search of the plant operating experience information to determine if the applicant had 

adequately incorporated and evaluated operating experience related to this program. 

The LRA ASME Section XI, Subsection IWE AMP states that the applicant conducted general 

visual examinations for period two of the first interval of the program for Unit 3. It gave special 

attention to the areas at the floor level mentioned in IN 2004-09, “Corrosion of Steel 

Containment and Containment Liner.” It did not observe abnormal conditions or signs of 

degradation. However, it was not clear from the review of supporting documentation if the 

applicant considered liner plate corrosion concerns, identified in IN 2004-09, and recent industry 

operating experience related to Beaver Valley Power Station for liner plate corrosion. 

Therefore, in RAI B2.1.27-3 the staff requested the applicant to explain if it considered the 

applicability of IN 2004-09 and Beaver Valley Power Station containment liner plate corrosion 

for PVNGS containments to avoid similar problems. PVNGS containment liner plate is of 

identical design and construction to the Beaver Valley Power Station. 

In response to the RAI B2.1.27-3, in a letter dated February 19, 2010, the applicant repeated 

the information contained in LRA Section B2.1.27-3 concerning IN 2004-09, including that the 

there were no areas that have evidence of water or moisture contacting the liner plate or 

penetrating the joint between the liner plate and the floor. The applicant also stated that EPRI 

performed a self-assessment of the IWE and IWL Programs for all three units and had no 

concerns. The EPRI self-assessment concluded that the IWE and IWL Programs address all 

issues listed in IN 2004-09. The applicant further stated that no liner plate corrosion similar to 

the Beaver Valley Power Station operating experience has been identified. This conclusion is 
Aging Management Review Results 

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based on the applicant’s inspection of the Unit 3 liner plate at different elevations after the 

coating was removed. These areas had scratches or blisters in the coating that required 

replacement of the coating. No signs of liner plate corrosion were detected in the base metal of 

the liner prior to re-coating. The staff finds the response to RAI B2.1.27-3 acceptable because 

the applicant has not found any liner plate degradation or evidence of water or moisture at the 

joint between the containment floor and liner plate as described in IN 2004-09. The applicant 

has not found any evidence of through-wall corrosion of the liner plate. 

In LRA, Appendix B, Section B2.1.32, “Structures Monitoring Program,” it states that no credit is 

taken for coatings in the determination of aging effects for the underlying materials. Although 

the coatings are not credited for aging management, the staff believed their failure could affect 

the functioning of safety systems. SER Section 3.0.3.3.2 documents the staff's evaluation of the 

applicant’s coatings assessment program, which the applicant has in lieu of an AMP. 

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program and that implementation of the program has 

resulted in the applicant taking corrective actions. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10 and is, 

therefore, acceptable. 

UFSAR Supplement. LRA Section A1.27 provides the UFSAR supplement for the ASME 

Section XI, Subsection IWE Program. The staff reviewed this UFSAR supplement description of 

the program and notes that it conforms to the recommended description for this type of 

program, as described in SRP-LR Table 3.5-2. The staff also notes that the applicant 

committed (Commitment No. 29) to the ongoing implementation of the existing ASME 

Section XI, Subsection IWE Program to manage the aging of the steel liner of the concrete 

containment building during the period of extended operation. The staff determines that the 

information in the UFSAR supplement is an adequate summary description of the program, as 

required by 10 CFR 54.21(d). 

Conclusion. On the basis of its review of the applicant’s ASME Section XI, Subsection IWE 

Program, the staff finds all program elements consistent with the GALL Report AMP. In 

addition, the staff reviewed the exceptions and justifications, and determines that the AMP, with 

the exceptions, is adequate to manage the aging effects for which the LRA credits it. The staff 

concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended functions will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR supplement for this AMP, and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d). 

3.0.3.2.19 Masonry Wall Program 

Summary of Technical Information in the Application. LRA Section B2.1.31 describes the 

existing Masonry Wall Program as being consistent, with enhancement, with the GALL Report 

AMP XI.S5, “Masonry Wall Program.” In the LRA, the applicant states that the Masonry Wall 

Program is part of the Structures Monitoring Program that implements monitoring requirements 

for structures, as specified in 10 CFR 50.65. For Seismic Category I structures, the Masonry 

Wall Program manages cracking of masonry walls and structural steel restraint systems of the 

masonry walls within the scope of license renewal based on guidance provided in the Office of 

Inspection and Enforcement (IE) Bulletin 80-11, “Masonry Wall Design,” and IN 87-67, “Lessons 

Learned from Regional Inspections of Licensee Actions in Response to NRC IE Bulletin 80-11.” 

In the LRA, the applicant explains that some masonry walls are located in non-Category I 

structures and are within scope of license renewal based on UFSAR commitments to satisfy fire 

protection. The applicant stated that the guidance of IE Bulletin 80-11 does not apply; however, 
Aging Management Review Results 

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aging management of these walls is evaluated under the Fire Protection Program. The 

applicant explained that the two non-seismic Category I structures that contain masonry walls 

within the scope of license renewal are the turbine building and fire pump house. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. The staff compared elements one 

through six of the applicant’s program to the corresponding elements of the GALL Report 

Masonry Wall Program. As discussed in the Audit Report, the staff confirmed that each element 

of the applicant’s program is consistent with the corresponding element of the GALL Report 

AMP, with the exception of “detection of aging effects” and “acceptance criteria.” For these 

elements, the staff determined the need for additional clarification, which resulted in the 

issuance of RAIs. 

While reviewing the “detection of aging effects” program element, the staff noted that 

inspections for in-scope SSCs, including masonry walls, were scheduled to result in the 

complete observation of all systems of one ‘equivalent unit’ on a frequency of approximately 

10 years. Observations would be conducted in different areas of different units to include a 

cross section of all three units. Using this method would ensure that, within a 30-year cycle, all 

units and all areas of each unit would be monitored. In the GALL Report Masonry Wall 

Program, it states that the primary parameter monitored or inspected is wall cracking that could 

potentially invalidate the evaluation basis and that masonry walls may be inspected as part of 

the Structures Monitoring Program (GALL Report, Chapter XI.S6) conducted under the 

Maintenance Rule. Industry standards (e.g., American Concrete Institute (ACI) 349.3R-96), 

identified in the GALL Report Structures Monitoring Program, suggest a five-year inspection 

frequency for structures exposed to natural environment, structures inside primary containment, 

continuous fluid-exposed structures, and structures retaining fluid or pressure. Industry 

standards recommend a 10-year inspection frequency for below-grade structures and structures 

in a controlled interior environment. It is not clear to the staff if all SSCs at each unit inspected 

under this AMP are in accordance with the industry standard inspection frequency or if only 

representative SSCs at each plant will be inspected within a 30-year period, implying that SSCs 

at each unit are completely inspected only once during the 30-year period. 

By letter dated December 29, 2009, the staff issued RAI B2.1.32-1, asking the applicant to 

explain the inspection frequency for each unit and the plant in general. If the inspection interval 

exceeds the industry standard, the applicant must clearly explain the basis for extending the 

interval and explain how the chosen interval will adequately manage aging during the period of 

extended operation. 

By letter dated February 19, 2010, the applicant responded to the RAI. SER Section 3.0.3.2.20 

for the Structures Monitoring Program includes a summary of the RAI response and a detailed 

discussion of the staff’s review of this issue. 

While reviewing the “acceptance criteria” program element, the staff noted that the applicant 

points to the Structures Monitoring Program, which includes the Masonry Wall Program. The 

Structures Monitoring Program provides guidance for the determination of performance criteria 

of SSCs included within the scope of the Maintenance Rule. A component observation report is 

to be prepared after each inspection that considers all the individual observations in relation to 

the ability of the structure to provide the necessary support and protection for the SSCs included 

within the structure. If any areas are found to have significant aging effects, engineering 

notifications are made to determine appropriate corrective action. SSC deficiencies are 

categorized as minor, adverse, or critical. It is unclear to the staff what criteria the applicant 

uses to classify a deficiency as minor, adverse, or critical. By letter dated December 29, 2010, 

the staff issued RAI B2.1.32-2, asking the applicant to provide the criteria used to categorize a 
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SSC deficiency as minor, adverse, or critical and include references to site documents or 

procedures that contain the categorization criteria. 

By letter dated February 19, 2010, the applicant responded to the RAI. SER Section 3.0.3.2.20 

for the Structures Monitoring Program includes a summary of the RAI response and a detailed 

discussion of the staff’s review of this issue. The staff also reviewed the portions of the 

“detection of aging effects” program element associated with the enhancement to determine 

whether the program will be adequate to manage the aging effects for which it is credited. The 

staff’s evaluation of this enhancement follows. 

Enhancement. LRA Section B2.1.31 identifies an enhancement to “detection of aging effects” to 

specify ACI 349.3R-96 as the reference for qualification of personnel to inspect structures under 

the Structures Monitoring Program. The staff finds this enhancement acceptable because when 

implemented, the AMP B2.1.31, “Masonry Wall Program,” will be consistent with the GALL 

Report Masonry Wall Program. Inspector qualifications will be commensurate with industry 

codes, standards and guidelines, which will help provide assurance that the applicant will 

adequately manage the effects of aging. 

Based on its audit and review of the applicant’s responses to RAIs B2.1.32-1 and B2.1.32-2, the 

staff finds that elements one through six of the applicant’s Masonry Wall Program, with 

acceptable enhancement, are consistent with the corresponding program elements of the GALL 

Report Masonry Wall Program and are, therefore, acceptable. 

Operating Experience. LRA Section B2.1.31 summarizes operating experience related to the 

Masonry Wall Program. The LRA discusses cracking in the Unit 1 control building, which was 

found to be acceptable by engineering evaluation but required additional monitoring to verify the 

cracks were not progressing. The applicant inspected the same areas in Units 2 and 3 and 

found no cracks. During the audit, the staff reviewed that status of the cracks and found that 

they had been monitored appropriately, and that none of the cracks had grown. The LRA also 

explains that it has found no cracks larger than one-eighth of an inch and that engineering has 

evaluated all identified cracks. The LRA further explains that the applicant has found no 

degraded steel bracing. 

The staff also reviewed operating experience information, in the application and during the 

audit, to determine if the applicant reviewed the applicable aging effects and industry and 

plant-specific operating experience. As discussed in the Audit Report, the staff conducted an 

independent search of the plant operating experience information to determine if the applicant 

had adequately incorporated and evaluated operating experience related to this program. The 

staff found that the applicant had adequately identified and incorporated industry and applicable 

plant-specific operating experience. 

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program and that implementation of the program has 

resulted in the applicant taking corrective actions. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, 

therefore, the staff finds it acceptable. 

UFSAR Supplement. In LRA Section A1.31, the applicant provided the UFSAR supplement for 

the Masonry Wall Program. The staff reviewed this UFSAR supplement section and notes that 

it conforms to the recommended description for this type of program as described in SRP-LR 

Table 3.5-2. The staff also notes that the applicant committed (Commitment No. 33) to enhance 

the Masonry Wall Program prior to entering the period of extended operation. Specifically, the 

applicant committed to specifying ACI 349.3R-96 as the reference for qualification of personnel 

to inspect structures under the Structures Monitoring Program. The staff determines that the 
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information in the UFSAR supplement is an adequate summary description of the program, as 

required by 10 CFR 54.21(d). 

Conclusion. On the basis of its audit and review of the applicant’s Masonry Wall Program, 

including responses to RAIs, the staff determines that those program elements for which the 

applicant claimed consistency with the GALL Report are consistent. In addition, the staff 

reviewed the enhancement and confirmed that its implementation through Commitment No. 33, 

prior to the period of extended operation, would make the existing AMP consistent with the 

GALL Report AMP to which it was compared. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP, 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

3.0.3.2.20 Structures Monitoring Program 

Summary of Technical Information in the Application. LRA Section B2.1.32 describes the 

existing Structures Monitoring Program as being consistent, with enhancement, with the GALL 

Report AMP XI.S6, “Structures Monitoring Program.” The program implements the 

requirements of 10 CFR 50.65 (Maintenance Rule) and is consistent with the guidance of 

NUMARC 93-01, Rev. 2 and RG 1.160, Rev. 2. The Structures Monitoring Program provides 

inspection guidelines for concrete elements, structural steel, masonry walls, structural features 

(e.g., caulking, sealants, and roofs), structural supports, and miscellaneous components such 

as doors. The Structural Monitoring Program manages cracking, loss of material, and change in 

material properties by monitoring the condition of structures and structural supports that are 

within the scope of license renewal. The program includes all masonry walls and water-control 

structures within the scope of license renewal. The program monitors settlement for each major 

structure and inspects equipment, piping, conduits, cable trays, HVAC equipment, and 

instrument components. The applicant inspects each of the spray ponds every five years and 

performs settlement monitoring for each major structure every five years. For other inspections, 

it monitors representative SSCs at each of the three units, such that it inspects the equivalent of 

one complete unit every 10 years. All three units will be 100-percent inspected (with the 

possible exception of inaccessible areas) within a 30-year period. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. The staff compared elements one 

through six of the applicant’s program to the corresponding elements of the GALL Report 

Structures Monitoring Program. As discussed in the Audit Report, the staff confirmed that each 

element of the applicant’s program is consistent with the corresponding element of the GALL 

Report, with the exception of “detection of aging effects,” and “acceptance criteria.” For these 

elements, the staff determined the need for additional clarification, which resulted in the 

issuance of RAIs. 

While reviewing the “detection of aging effects” program element, the staff noted that 

inspections for in-scope SSCs are scheduled to result in total observation of all systems of one 

“equivalent Unit” on a frequency of approximately 10 years. To include a cross section of all 

three units, the applicant conducts observations in different areas of different units. Within a 

30-year cycle, it monitors all units and all areas of each unit. The staff further noted that 

industry standards identified in the GALL Report Structures Monitoring Program (e.g., 

ACI 349.3R-96) suggest a five-year inspection frequency for structures exposed to a natural 

environment, structures inside primary containment, continuous fluid-exposed structures, and 

structures retaining fluid or pressure; and a 10-year inspection frequency for below-grade 

structures and structures in a controlled interior environment. It is not clear to the staff that all 
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SSCs at each unit, inspected under this AMP, are consistent with the industry standards 

inspection frequency (e.g., as noted in ACI 349.3R-96) or if only representative SSCs at each 

plant will be inspected within a 30-year period, implying that SSCs at each unit are completely 

inspected only once during the 30-year period. 

By letter dated December 29, 2009, the staff issued RAI B2.1.32-1, asking the applicant to 

explain in more detail the inspection frequency for each unit and the plant in general. If the 

inspection interval exceeds the industry standard, the applicant must clearly explain the basis 

for extending the interval and explain how the chosen interval will adequately manage aging 

during the period of extended operation. 

By letter dated February 19, 2010, the applicant responded to the RAI and explained that of the 

three units at PVNGS, a complete “representative unit” is inspected over every 10-year period. 

The applicant further explained that to include a cross section of all three units, it conducts 

observations in different areas of different units. In addition, other site programs look at civil 

SSCs, over and above those required by the Maintenance Rule. In addition, the applicant 

stated that structures are not subject to sustained aggressive adverse environmental conditions. 

The staff reviewed the applicant’s response and found it unacceptable because the staff does 

not believe that an inspection of a “representative unit” on the suggested 10-year interval will 

capture degradation throughout the three units. The staff believes that the applicant must 

inspect each unit on an interval not to exceed 10 years. The staff discussed this issue with the 

applicant during the license renewal inspection held the week of February 22, 2010. By letter 

dated April 1, 2010, the applicant supplemented their response to RAI B2.1.32-1, committing to 

enhancing the Structures Monitoring Program to inspect structures within the scope of license 

renewal on a 10-year frequency. 

Although this response addressed the staff’s concern with the “representative unit” approach 

and with structures being inspected at intervals greater than 10 years, it did not completely align 

the inspection interval with the guidance in ACI 349.3R. The guidance recommends a five-year 

inspection interval for structures within primary containment and structures exposed to a natural 

environment. The staff discussed these issues with the applicant during a conference call on 

April 12, 2010. 

By letter dated May 21, 2010, the applicant supplemented its response to RAI B2.1.32-1 to align 

the inspection frequencies of safety-related structures (structures within primary containment) 

with the guidance in ACI 349.3R (Commitment No. 34). For non-safety-related structures, the 

applicant maintained a 10-year inspection interval for exterior surfaces. The applicant explained 

that it based this frequency on the associated risk, the non-aggressive exterior environment, 

and site operating experience. Specifically, the applicant explained that the site experiences 

very low rainfall, the water table is well below the lowest structures, and freeze cycles are 

infrequent and usually occur during dry conditions. The applicant also explained that there is 

minimal site experience with external concrete degradation and that any degradation detected 

during the period of extended operation will lead to a reassessment of the inspection frequency. 

The staff reviewed the applicant’s supplemental responses and found them acceptable because 

for safety-related structures the applicant has aligned the inspection frequency with the 

recommended guidance in ACI 349.3R. Further, the staff finds the 10-year inspection 

frequency acceptable for the non-safety-related structures exposed to an external environment 

because the site has a relatively benign environment. The low rainfall, minimal exposure to 

groundwater, and negligible weathering region classification (per ASTM C33), are all factors that 

reduce the degradation potential of the environment on exposed concrete. In addition, the site 

has minimal experience with concrete degradation due to exterior exposure and, if degradation 

is detected, the adequacy of the inspection frequency will be reassessed. The staff’s concerns 
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in RAI B2.1.32-1 are resolved. Based on the review of the applicant’s responses, the staff finds 

the “detection of aging effects” program element acceptable. 

While reviewing the “acceptance criteria” program element, the staff noted the LRA Structures 

Monitoring Program states that acceptance criteria are to be commensurate with industry codes, 

standards, and guidelines, and are to consider industry and plant-specific operating experience. 

The Structures Monitoring Program provides guidance for the determination of performance 

criteria for SSCs included within the scope of the Maintenance Rule. These guidelines are used 

to establish inspection attributes for SSCs monitored by the Structures Monitoring Program with 

deficiencies categorized as minor, adverse, or critical, and depending on the deficiency 

categorization, the SSCs are considered acceptable or unacceptable. In the GALL Report 

Structures Monitoring Program, ACI 349.3R-96 provides an acceptable basis for developing 

acceptance criteria for concrete structural elements, steel liners, joints, coatings, and 

waterproofing membranes. It is unclear to the staff if the applicant has used ACI 349.3R-96 to 

provide the basis to establish the deficiency categorizations or if it uses some other basis and 

what criteria it uses to categorize a SSC deficiency as minor, adverse, or critical. 

By letter dated December 29, 2010, the staff issued RAI B2.1.32-2, asking the applicant to 

provide the criteria used to categorize a SSC deficiency as minor, adverse, or critical and 

include references to site documents or procedures that contain the categorization criteria. 

By letter dated February 19, 2010, the applicant defined the deficiency categories as follows: 

Critical – A deficiency that requires corrective action (repair or more frequent 

inspection) to provide confidence that the associated structure will continue to 

perform its design function until the next regular inspection. For the purpose of 

this definition, the regular inspection interval is 10 years, (i.e., until the same 

structural element is reinspected in any unit), except for the spray ponds where 

the observation frequency is 5 years. A critical deficiency in one Unit area will 

precipitate an inspection of the corresponding structural elements in the other 

two Units. 

Adverse – A deficiency that should be repaired (or inspected more frequently), 

when repair or more frequent inspection is not required to maintain the 

structure’s functional capability. Such repairs may be done to prevent further 

degradation, maintain general material conditions, or to promote overall plant 

appearance. An Adverse deficiency in one Unit area will precipitate an 

inspection of the corresponding structural elements in the other two Units. 

Minor – A deficiency that is acceptable as is, with no action required. 

The applicant’s response further specified the deficiency categories for concrete as follows: 

Critical Deficiency – Conditions of degradation that must be repaired to 

continue to maintain the concrete component’s functional capability or to restore 

the concrete component to its applicable functional capability. Transportability 

concerns shall be evaluated for all critical deficiencies. 

Adverse Deficiency – Conditions of degradation that do not expose the 

embedded steel re-enforcement, do not impact the design function of the 

concrete component, or is passive (non-active condition) where it is not required 

to maintain the concrete component’s functional capability. However, such 

repairs should be performed to prevent further degradation or to promote overall 

plant appearance. 

Minor Deficiency – Conditions of degradation that do not expose the embedded 

steel re-enforcement, do not impact the design function of the concrete 
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component, or is passive (non-active condition) shall be acceptable without 

further evaluation. 

The staff reviewed the applicant’s response and found it vague and qualitative, compared to the 

detailed evaluation criteria provided in ACI 349.3R for concrete structural elements, steel liners, 

joints, coatings, and waterproofing membranes. Therefore, the staff finds the applicant’s 

deficiency criteria unacceptable for the period of extended operation. 

By letter dated May 21, 2010, the applicant supplemented the original response and committed 

to enhance the Structures Monitoring Program, before the period of extended operation, to 

quantify the acceptance criteria and critical parameters for monitoring degradation 

(Commitment No. 34). The applicant further stated that the program will be enhanced to 

incorporate applicable industry codes, standards, and guidelines (e.g. ACI 349.3R-96, 

ANSI/ASCE 11-90) for acceptance criteria. 

The staff reviewed the applicant’s supplemental response and found it acceptable because the 

applicant committed to enhance the Structures Monitoring Program to include the acceptance 

criteria discussed in the GALL Report Structures Monitoring Program. The staff’s concern in 

RAI B2.1.32-2 is resolved. Based on the review of the applicant’s responses, the staff finds the 

“acceptance criteria” program element acceptable. 

The staff also reviewed the portions of the “detection of aging effects” program element 

associated with an enhancement to determine whether the program will be adequate to manage 

the aging effects for which it is credited. The staff’s evaluation of this enhancement follows. 

Enhancement. LRA Section B2.1.32 identifies an enhancement to “detection of aging effects” to 

specify ACI 349.3R-96 as the reference for qualification of personnel to inspect structures under 

the Structures Monitoring Program. The staff found this enhancement acceptable because 

when implemented the LRA Structures Monitoring Program will be consistent with the GALL 

Report Structures Monitoring Program relative to inspector qualifications being commensurate 

with industry codes, standards, and guidelines to help provide assurance that the applicant will 

adequately manage the effects of aging. 

Based on its audit, review of the LRA Structures Monitoring Program, and review of the 

applicant’s responses to RAIs B2.1.32-1 and B2.1.32-2, the staff finds that elements one 

through six of the applicant’s Structures Monitoring Program, with acceptable enhancement, are 

consistent with the corresponding program elements of the GALL Report Structures Monitoring 

Program and are, therefore, acceptable. 

Operating Experience. LRA Section B2.1.32 summarizes operating experience related to the 

Structures Monitoring Program. The staff interviewed the applicant’s technical personnel during 

the audit to confirm that plant-specific operating experience revealed no degradation not 

bounded by industry experience. The staff reviewed operating experience information, in the 

application and during the audit, to determine if the applicant reviewed the applicable aging 

effects and industry and plant-specific operating experience. As discussed in the Audit Report, 

the staff conducted an independent search of the plant operating experience information to 

determine if the applicant had adequately incorporated and evaluated operating experience 

related to this program. 

During its review, the staff identified two condition report disposition requests related to leakage 

of SFP water. The staff determined the need for additional information, which resulted in the 

issuance of an RAI. 

By letter dated December 29, 2010, the staff issued RAI B2.1.32-3, asking the applicant to 

discuss any apparent cause analysis performed to identify the source of leakage as well as 

corrective actions taken to stop leakage. The staff asked the applicant to explain how the 

leakage has affected the condition of the concrete and what steps it has taken or will take to 
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ensure adequacy of the concrete during the period of extended operation. The staff also asked 

the applicant to discuss any actions taken to ensure the drain system remains free and clear 

allowing the system to properly prevent water from accumulating behind the liner. 

By letter dated February 19, 2010, the applicant responded and explained that the SFP is 

equipped with a telltale drain system, designed to capture leakage through the SFP liner. In 

July of 2005, in Unit 1, borated water leakage was discovered at two locations on the exterior 

face of the SFP concrete walls. The applicant explained that this leakage was a result of 

backed-up water within the telltale drain system, due to the telltale drain valves being in the 

closed position for an extended period. With no place to drain, the water in the telltale drain 

system eventually migrated through the SFP concrete walls via extremely small cracks. Once 

the drain valves were re-opened, each drain line released a large amount of borated water. 

The applicant further explained that currently, and continuing through the period of extended 

operation, plant personnel open the valves and record drained water on a daily basis. The 

applicant explained that this procedure should keep water from backing up and leaking through 

the concrete. The applicant will measure and trend drainage from the telltale system and 

investigate any abnormalities through the corrective action program. The applicant also 

explained that in order to ensure the drain lines were clear, it inspected all telltale drain lines in 

all units via boroscope between 2008 and 2009, and it will re-inspect the lines on a two-year 

frequency. The applicant further explained that Construction Technology Laboratories (CTL) 

performed an NDE of the SFP concrete walls; the CTL inspection report concluded that the 

borated water leakage did not have an adverse impact on the concrete. 

The staff reviewed the applicant’s response and found that the actions taken to unclog the drain 

system and monitor it in the future would provide some assurance of reduced leakage through 

the concrete. However, the staff requested the applicant to provide more information on the 

extent of the leakage as well as a more detailed discussion of their confidence that the leakage 

is no longer passing through the concrete walls. 

By letter dated May 21, 2010, the applicant supplemented their original response and provided 

the CTL inspection report, which documented the NDE conducted after the leakage incident in 

2005. In their response, the applicant explained that leakage through the concrete in areas that 

were initially identified as showing leakage stopped completely, based on the fact that there are 

no longer wetted areas visible. In addition, the applicant explained that in 2006 and 2007, 

shallow aquifer wells were installed down-gradient of each unit. These wells are sampled 

periodically and no radioactivity has been detected. The applicant further explained that it 

determined that approximately eight ounces of fluid leaked from both leakage locations in 2005. 

The applicant also stated that no indications of leakage have been identified in Units 2 or 3. 

The staff reviewed the applicant’s response and found it acceptable because the NDE 

investigation showed no significant degradation to the concrete as a result of the 2005 leakage 

event. The amount of leakage through the concrete was minimal, and inspections of accessible 

concrete since the event show no indications of continued leakage. In addition, the applicant 

has plans in place to properly maintain the telltale drain system. This reduces the likelihood of 

future leakage migrating through the concrete and causing degradation. The staff’s concern in 

RAI B2.1.32-3 is resolved. 

Based on its audit, review of the application, and review of the applicant’s response to 

RAI B2.1.32-3, the staff finds that operating experience related to the applicant’s program 

demonstrate that it can adequately manage the detrimental effects of aging on SSCs within the 

scope of the program and that implementation of the program has resulted in the applicant 

taking corrective actions. The staff confirmed that the “operating experience” program element 

satisfies the criterion in SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it acceptable. 
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In LRA, Appendix B, Section B2.1.32, “Structures Monitoring Program,” it states that no credit is 

taken for coatings in the determination of aging effects for the underlying materials. Although 

the coatings are not credited for aging management, the staff believed their failure could affect 

the functioning of safety systems. SER Section 3.0.3.3.2 documents the staff’s evaluation of the 

applicant’s coatings assessment program, which the applicant has in lieu of an AMP. 

UFSAR Supplement. In LRA Section A1.32, the applicant provided the UFSAR supplement for 

the Structures Monitoring Program. The staff reviewed this UFSAR supplement section and 

notes that it conforms to the recommended description for this type of program as described in 

SRP-LR Table 3.5-2. The staff also notes that the applicant committed (Commitment No. 34) to 

enhance the Structures Monitoring Program prior to entering the period of extended operation. 

Specifically, the applicant committed to specifying ACI 349.3R-96 as the reference for 

qualification of personnel to inspect structures under the Structures Monitoring Program. 

The applicant also committed to align inspection frequencies with the guidance in ACI 349.3R, 

except for the exterior surfaces of non-safety-related structures, for which the applicant 

maintained a 10-year inspection interval. The Structures Monitoring Program will be enhanced 

to quantify the acceptance criteria and critical parameters for monitoring degradation, and to 

provide guidance for identifying unacceptable conditions requiring further technical evaluation or 

corrective action. Procedures will also be enhanced to incorporate applicable industry codes, 

standards and guidelines for acceptance criteria. 

Conclusion. On the basis of its audit and review of the applicant’s Structures Monitoring 

Program, as well as the RAIs discussed above, the staff determines that those program 

elements for which the applicant claimed consistency with the GALL Report are consistent. 

Also, the staff reviewed the enhancement and confirmed that its implementation through 

Commitment No. 34, prior to the period of extended operation, would make the existing AMP 

consistent with the GALL Report AMP to which it was compared. The staff concludes that the 

applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP, and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

3.0.3.2.21 Regulatory Guide 1.127, “Inspection of Water-Control Structures Associated with 

Nuclear Power Plants” 

Summary of Technical Information in the Application. LRA Section B2.1.33 describes the 

existing RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear Power 

Plants” program as consistent, with an enhancement, with the GALL Report AMP XI.S7, 

“RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants.” In 

the LRA, the applicant explains that PVNGS is not committed to RG 1.127; however, a 

Structures Monitoring Program is in place that includes all water-control structural components 

within the scope of RG 1.127. The applicant further explains that the program manages aging 

for the water-control structures associated with emergency cooling water systems, and that the 

inspections are performed on a frequency of at least once every five years, based on 

acceptable inspection results from previous inspections. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. The staff compared elements one 

through six of the applicant’s program to the corresponding elements of the RG 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants AMP in the GALL 

Report. As discussed in the Audit Report, the staff confirmed that each element of the 

applicant’s program is consistent with the corresponding element of the GALL Report AMP, with 
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the exception of the “detection of aging effects” and “acceptance criteria” program elements. 

For these elements, the staff determined the need for additional clarification, which resulted in 

the issuance of RAIs. 

The “detection of aging effects” element of the GALL Report AMP discusses special inspections 

immediately following the occurrence of significant natural phenomena, such as large floods, 

earthquakes, hurricanes, tornadoes, and intense local rainfalls. In the corresponding element of 

the AMP basis document, the applicant states that PVNGS has no earthen dams or other water 

control structures in-scope for license renewal that would require special inspections after the 

occurrence of significant natural phenomena. By letter dated March 2, 2010, the staff issued 

RAI B2.1.33-1 requesting the applicant to explain why it is unnecessary to inspect the spray 

pond structures after unusual natural events. 

In its response, dated April 1, 2010, the applicant explained that the spray pond structures are 

Seismic Category I and designed to remain functional after a safe shutdown earthquake, 

extreme wind phenomena, and other design basis events. The PVNGS Technical 

Requirements Manual, TLCO 3.3.103, requires corrective action to be initiated to evaluate the 

effect upon facility features important to safety following a seismic event greater than or equal to 

0.02 gravity. The applicant further stated that it would enter other unusual natural events into 

the corrective action plan to assess the need for inspection of the spray ponds. The staff 

reviewed the applicant’s response and finds it acceptable because it explains that the applicant 

will take actions to assess the need for spray pond inspections after significant natural 

phenomena. The staff’s concern in RAI B2.1.33-1 is resolved. 

The “acceptance criteria” element of the GALL Report AMP states that the “evaluation criteria” 

provided in Chapter 5 of ACI 349.3R provides acceptance criteria for determining the adequacy 

of observed aging effects and specifies criteria for further evaluation. In the corresponding 

element of the AMP basis document, it states that that SSC deficiencies are categorized as 

minor, adverse, or critical and, depending on the deficiency categorization, the SSCs are 

considered to be acceptable or unacceptable. It is not clear to the staff that these statements 

are consistent because reviewed basis documents do not include criteria to categorize a SSC 

deficiency as minor, adverse, or critical. Therefore, by letter dated December 29, 2009, the staff 

issued RAI B2.1.32-2 requesting the applicant to provide the criteria used to categorize a SCC 

deficiency as minor, adverse or critical. This issue applies to all the AMPs that follow the plant 

procedures related to the Structures Monitoring Program (i.e. Structures Monitoring, Masonry 

Wall, and Water-Control Structures). 

By letter dated February 19, 2010, the applicant responded to the RAI. SER Section 3.0.3.2.20 

includes a summary of the RAI response and a detailed discussion of the staff’s review of this 

issue. 

The staff also reviewed the portions of the “detection of aging effects” program element 

associated with the enhancement to determine if the program will be adequate to manage the 

aging effects for which it is credited. The staff’s evaluation of this enhancement follows. 

Enhancement. LRA Section B2.1.33 identifies an enhancement to the “detection of aging 

effects” program element. The LRA explains that the applicant will enhance procedures to 

specify that the essential spray pond inspections include concrete below the water level. The 

GALL Report recommends inspections of concrete below the water level to detect aging effects. 

As such, implementation of the enhancement through Commitment No. 35 will make the 

applicant’s program consistent with the GALL Report and, therefore, acceptable. 

Based on its audit, review of the LRA AMP, and review of the applicant’s responses to 

RAIs B2.1.33-1 and B2.1.32-2, the staff finds that elements one through six of the applicant’s 

RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 
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Program, with acceptable enhancement, are consistent with the corresponding program 

elements of the GALL Report AMP, and are, therefore, acceptable. 

Operating Experience. LRA Section B2.1.33 summarizes operating experience related to the 

RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 

Program. The LRA discusses cracking on the outer surfaces of the sidewalls of the spray 

ponds and explains that there are no visual indications associated with the cracks that would 

indicate the structural integrity of the walls is compromised. The LRA also discusses a leak that 

was discovered on the south end of the west wall of the Unit 1 Spray Pond A. The applicant 

determined that the source of the leak was a damaged expansion joint, which was repaired. 

The applicant examined similar locations in the other ponds and found no evidence of leakage. 

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicant reviewed the applicable aging effects and industry and plant-specific 

operating experience. As discussed in the Audit Report, the staff conducted an independent 

search of the plant operating experience information to determine if the applicant had 

adequately incorporated and evaluated operating experience related to this program. 

During its review, the staff identified operating experience that required clarification and resulted 

in the issuance of an RAI as discussed below. 

During the on-site operating experience review, the applicant provided several condition reports 

that discussed degradation of the spray pond concrete walls. During walkdowns, the staff 

observed cracking and spalling near the top of the spray pond walls. Therefore, by letter dated 

March 2, 2010, the staff issued RAI B2.1.33-2 asking the applicant to explain how the AMP is 

addressing degradation of the spray pond walls and how the structural stability of the walls will 

be maintained during the period of extended operation. 

In its response, dated April 1, 2010, the applicant stated that it would continue to inspect the 

spray pond walls on a five-year frequency during the period of extended operation. The 

applicant also explained that the existing condition of the spray pond structures has been 

assessed and will be reworked prior to the period of extended operation. 

The staff reviewed the applicant’s response and found it unacceptable because it did not clearly 

explain what ‘rework’ meant, and it did not discuss the criteria used to identify the degraded 

locations for rework. The staff discussed these with the applicant in a conference call on 

May 14, 2010, during which the applicant stated it would submit a supplemental response that 

would also include a repair plan. 

By letter dated June 21, 2010, the applicant submitted a supplemental response to 

RAI B2.1.33-2. The response explained that the spray pond concrete restoration will be 

completed using existing approved engineering specifications for concrete work. The response 

further explained that current inspections have identified degradation on the surface of the spray 

pond walls and delamination in the top 6–8 inches of the walls. Currently, the applicant is 

developing corrective actions, including the possibility of removing and re-pouring the top of the 

concrete walls, and repairing reinforcement as needed. The corrective actions will be 

completed for each spray pond, with priority given to the spray pond with the most degradation, 

before the period of extended operation. The applicant’s response further explained that it 

plans to begin the corrective actions in 2011 with Unit 1 and should be completed on all units by 

2015. The response also stated that the wall degradation was evaluated; the evaluation 

concluded that the structural integrity of the spray ponds is not challenged and the spray ponds 

remain operable. The applicant also added Commitment No. 56 to address the spray pond 

repair schedule. 

The staff reviewed the applicant’s response and found it acceptable because it explains the 

degradation is in the top 6–8 inches of the spray pond walls and does not affect the structural 
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integrity of the walls. The response also outlines a plan to fix the degradation prior to the period 

of extended operation (Commitment No. 56). The staff’s concern in RAI B2.1.33-2 is resolved. 

Based on its audit, review of the application, and review of RAI B2.1.33-2 response, the staff 

finds that operating experience related to the applicant’s program demonstrates that the 

program can adequately manage the detrimental effects of aging on SSCs within the scope of 

the program and that implementation of the existing program has resulted in the applicant taking 

corrective actions. The staff confirmed that the “operating experience” program element 

satisfies the criterion in SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it acceptable. 

UFSAR Supplement. LRA Section A1.33 provides the UFSAR supplement for the RG 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants Program. The 

staff reviewed this UFSAR supplement description of the program and notes that it conforms to 

the recommended description for this type of program, as described in SRP-LR Table 3.5-2. 

The staff also notes that the applicant has committed (Commitment No. 35) to the ongoing 

implementation of the existing RG 1.127, Inspection of Water-Control Structures Associated 

with Nuclear Power Plants Program to manage the aging of applicable components during the 

period of extended operation. The applicant also committed (Commitment No. 35) to enhancing 

the procedures, prior to the period of extended operation, to specify inspections of concrete 

below the water level. The applicant further committed (Commitment No. 56) to develop a 

repair plan for the spray pond wall degradation and to implement the repairs beginning in 2011 

and expecting to complete repairs by 2015. The staff determines that the information in the 

UFSAR supplement is an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

Conclusion. On the basis of its audit and review of the applicant’s RG 1.127, Inspection of 

Water-Control Structures Associated with Nuclear Power Plants Program, and the applicant's 

responses to the RAIs, the staff determines that those program elements for which the applicant 

claimed consistency with the GALL Report are consistent. The staff reviewed the enhancement 

and confirmed that its implementation through Commitment No. 35, prior to the period of 

extended operation, would make the existing AMP consistent with the GALL Report AMP to 

which it was compared. Also, the staff reviewed Commitment No. 56, which was added to 

address the spray pond wall degradation prior to the period of extended operation, and found it 

acceptable. The staff concludes that the applicant has demonstrated that the effects of aging 

will be adequately managed so that the intended function(s) will be maintained consistent with 

the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). Finally, the 

staff reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d). 

3.0.3.2.22 Metal Fatigue of Reactor Coolant Pressure Boundary Program 

Summary of Technical Information in the Application. LRA Section B3.1 describes the existing 

Metal Fatigue of RCPB program as consistent, with enhancements, with the GALL Report 

AMP X.M1, “Metal Fatigue of Reactor Coolant Pressure Boundary.” In the LRA, the applicant 

identifies the Metal Fatigue of RCPB program (Metal Fatigue AMP) as an existing program that, 

when enhanced, will be consistent with the program elements in the GALL Report AMP. 

In a letter dated May 27, 2010, the applicant submitted LRA Amendment No. 16. In this 

amendment, the applicant modified the program description, enhancements, and “operating 

experience” program element description for the LRA AMP, in order to reconcile inconsistencies 

between the AMP and corresponding discussions in LRA Section 4.3.1. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. 
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The staff compared elements one through six of the applicant’s program to the corresponding 

elements of the GALL Report Metal Fatigue AMP. As discussed in the Audit Report, the staff 

confirmed that each element of the applicant’s program is consistent with the corresponding 

element of the GALL Report AMP, with the exception of the “operating experience” program 

element, the enhancements, and the corresponding discussions in LRA Section 4.3.1 “Fatigue 

Aging Management Program.” For these areas, the staff determined the need for additional 

clarification, which resulted in the issuance of RAIs. SER Section 4.3.1 discusses these RAIs in 

detail. 

The staff noted that the program did not account for applicable TS tracking requirements for the 

design basis transients that are discussed and evaluated in UFSAR Section 3.9.1.1 and in 

UFSAR Tables 3.9.1-1 and 3.9-1. These TS tracking requirements are in accordance with 

TS 5.5.5, which requires the applicant to implement the following administrative controls: 

5.5.5 Component Cyclic or Transient Limit 

This program provides controls to track the UFSAR Section 3.9.1.1 cyclic and 

transient occurrences to ensure that components are maintained within the 

design limits. 

Thus, the staff questioned why the applicant did not account for applicable TS tracking 

requirements in the program description and “scope of program” element of the AMP. 

The staff also noted that the program’s monitoring methods included both cycle-count (CC) 

monitoring, cycle-based fatigue (CBF) monitoring, and stress-based fatigue (SBF) monitoring 

methods. The staff noted that of these methods, only the CC and CBF monitoring methods 

involve tracking and counting the number of design basis transients occurring at each of the 

units. The staff noted there were apparent inconsistencies between the transients monitored by 

the AMP and those tracked under TS 5.5.5. By letter dated April 28, 2010, the applicant 

submitted Amendment 14 to the LRA to address and correct the inconsistencies. The staff 

noted that, of these methods, only the CBF method would perform periodic updates of the 

cumulative usage factor (CUF) values in accordance with the “detection of aging effects” 

program element recommendations in the GALL Report. The applicant indicated that the CC 

monitoring method would not perform periodic updates of CUF values. In order for the CC 

monitoring method to be consistent with the “detection of aging effects” program element in the 

GALL Report Metal Fatigue AMP, the applicant needs to clarify whether this method performs a 

CUF update calculation if the acceptance criterion on cycle limits is reached. 

By letter dated April 28, 2010, the applicant submitted Amendment 14 to the LRA to address 

and amend the CC monitoring basis. The staff verified that the amended CC monitoring basis 

performs periodic CUF updates when a CC action limit is reached. Based on this review, the 

staff finds that the applicant’s CC monitoring basis is acceptable because the amended basis is 

consistent with the staff recommendation in the “detection of aging effects” program element in 

the GALL Report Metal Fatigue AMP. 

The applicant’s SBF monitoring method credits performing periodic updates of the CUF values 

for specific components. The staff noted that the SBF monitoring method tracks the stress, 

pressure, and temperature parameters for the components and uses the changes in these 

parameters to perform stress based updates of the CUF calculations. The staff finds this 

consistent with the recommendation in the “detection of aging effects” program element in the 

GALL Report Metal Fatigue AMP for performance of periodic CUF updates. 

The staff noted that in LRA Section 4.3.2, the applicant had indicated that it would use SBF 

monitoring of one component with a high CUF value as a bounding SBF monitoring basis for 

other component locations that have high existing CUF values. The applicant did not explain in 

LRA Section 4.3.1.2 or Appendix B, Section B3.1 why it was valid to propose SBF monitoring on 
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a bounding basis. The staff noted that if a bounding basis was valid, the applicant did not 

explain how it would apply corrective actions to the non-monitored locations if the monitored 

location reaches the action limit. The staff determines that the applicant needs to address why 

it would be permissible to apply SBF on a bounding basis. 

By letter dated April 28, 2010, the applicant submitted Amendment 14, which stated that it no 

longer credits its SBF monitoring on a bounding basis. The applicant modified Commitment 

No. 39 to reflect the use of a fatigue monitoring software program and a methodology for SBF 

monitoring that will implement a three-dimensional, six-element tensor stress analysis method, 

and conform to the requirements of ASME Section III, Article NB-3200. The staff noted that this 

commitment has been placed on both the UFSAR supplement for this TLAA and the UFSAR 

supplement for the applicant’s enhanced Metal Fatigue AMP for purposes of addressing the 

technical issues raised and discussed in RIS 2008-30, “Fatigue Analysis of Nuclear Power Plant 

Components.” The staff finds that this revision resolves the staff’s concern because it is no 

longer using the monitoring methodology of concern to the staff as identified in RIS-2008-30. 

As stated in SER Section 4.3.1.2, the staff was concerned with the acceptance criteria for the 

applicant’s program and the corrective action options proposed by the applicant for cycle 

counting activities and CUF monitoring activities. 

The staff discussed these apparent inconsistencies with the applicant in a public meeting that 

was held at NRC Headquarters, Rockville, MD, on May 6, 2010 (meeting summary 

memorandum to the applicant dated June 25, 2010). 

The staff noted that in LRA Amendment 16, the applicant amended the LRA Appendix B, 

Section B3.1 such that the program description, the “operating experience” program element, 

and the enhancements are consistent with the conforming changes that the applicant had made 

to LRA Section 4.3.1 in LRA Amendment 14, dated April 28, 2010. The staff noted the applicant 

made the following changes in LRA Amendment 16: 

 amended the program description and enhancement 1 on the “scope of program” 

element to reflect the applicable TS tracking and counting requirements in TS 5.5.5 

 amended the program description to provide clear indication of the differences between 

the current program implemented at the facility and the enhanced version of the program 

that will be implemented during the period of extended operation 

 amended the program description, enhancement 1 for the “scope of program” element; 

enhancement 3 for the “parameters monitored or inspected” and “monitoring and 

trending” program elements; and enhancement 4 for the “detection of aging effects” 

program element to reflect use of appropriate monitoring software packages 

 amended enhancement 2 for the “preventative actions,” “acceptance criteria,” and 

“corrective actions,” program elements to reflect updated action limits and corrective 

actions for both CC and CUF monitoring activities 

 amended the “operating experience” program element to incorporate an administrative 

change to the previous operating experience discussion 

The staff finds the changes to the program descriptions for the program acceptable because 

they accounted for applicable TS tracking requirements. Also, the enhanced version of the 

program will implement appropriate monitoring software methods for both the CC and SBF 

methods. 

LRA Section B3.1 states that the calculated design lifetime CUF is defined by Subparagraph 

NB 3222.4 of the Section III of the ASME Boiler and Pressure Vessel (B&PV) Code, and an 

equivalent term is defined for valves in Paragraph NB-3552. The staff noted that, ASME B&PV 
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Code, Section III, Subsection NB-3552 defines “excluded cycles,” whereas Subsection NB-3553 

defines “fatigue usage.” By letter dated December 29, 2009, the staff issued RAI B3.1-1 asking 

the applicant to clarify which ASME Code section will be used in the calculation of the valve 

fatigue usage term. 

In its response dated February 19, 2010, the applicant stated it calculated the valve fatigue 

usage using ASME B&PV Code, Section III, 1974 edition, up to and including winter 1975, 

summer 1976, Subsection NB-3550, as shown on LRA Table 4.3-9. The applicant further 

stated the use of NB-3552 in Appendix B was a typographical error and has been corrected to 

NB-3550. 

Based on its review, the staff finds the applicant’s response to RAI B3.1-1 acceptable because 

the applicant clarified that this was a typographical error. In addition, the applicant calculated 

valve fatigue usage l(t) in accordance with ASME B&PV Code, Section III, Subsection NB-3550, 

which includes Subsection NB-3553 defines “Fatigue Usage,” and the use of ASME B&PV 

Code, Section III, 1974 edition is in accordance with 10 CFR 50.55a. The staff’s concern 

described in RAI B3.1-1 is resolved. 

During its audit, the staff reviewed the applicant’s program basis document and noted that the 

“acceptance criteria” program element will be enhanced with action limits that further ensure 

that fatigue usage factors for RCPB components are maintained below the CUF of 1.0, as 

established by Section III Subsection NB of the ASME B&PV Code, and that other limits 

assumed as the basis for safety determinations are maintained. The staff noted that the 

applicant did not define the term “other limits.” By letter dated December 29, 2009, the staff 

issued RAI B3.1-2 requesting the applicant to clarify what are the “other limits” that are assumed 

as the basis for safety determinations to be maintained, as described in the enhancement of the 

“acceptance criteria” program element. 

In its response dated February 19, 2010, the applicant stated the “other limits” are those 

considerations not addressed as ASME Section III fatigue analyses that depend on an assumed 

number of load cycles. The applicant further stated that these “other limits” are still within the 

bounds of the ASME Code, but are not directly related to fatigue (i.e. the monitoring of crack 

propagation of an embedded flaw and the determination of high energy line break locations). 

The applicant stated that it outlined the basis for the action limits required in each case in the 

“disposition” of each of these subsections of the LRA. The applicant further stated that the LRA 

identified the safety determinations listed below that are addressed as other limits in the Metal 

Fatigue Monitoring Program: 

 high energy line break locations in Class 1 RCP boundary piping (LRA 4.3.2.14) 

 linear elastic fracture mechanics fatigue crack growth analysis of indications in a Unit 2 

pressurizer support skirt forging weld (LRA 4.3.2.4) 

 fatigue crack growth and fracture mechanics stability analyses of half-nozzle repairs to 

alloy 600 material in reactor coolant hot legs (LRA 4.7.4) 

SER Section 4.3.2.14 documents the staff’s evaluation for high-energy line break (HELB) 

locations in Class 1 reactor coolant pump (RCP) boundary piping. SER Section 4.3.2.4 

documents the staff’s evaluation for the linear elastic fracture mechanics fatigue crack growth 

analysis of indications in a Unit 2 pressurizer support skirt-forging weld. SER Section 4.7.4 

documents the staff’s evaluation for the fatigue crack growth and fracture mechanics stability 

analyses of half-nozzle repairs to Alloy 600 material in reactor coolant hot legs. The staff noted 

that the applicant’s “other limits” are associated with an assumed number of load cycles, which 

is tracked by the applicant’s enhanced Metal Fatigue AMP. Furthermore, the staff noted these 

“other limits” are associated with ASME Section III fatigue analyses, but not directly related to 

fatigue; the use of the design limit of 1.0 for cumulative fatigue usage is not applicable. 
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Based on its review, the staff finds the applicant’s response to RAI B3.1-2 acceptable because, 

the applicant clarified the “other limits” as part of its “acceptance criteria” program element. In 

addition, the applicant will establish limits to ensure the analytical bases of ASME Section III 

fatigue analyses that are not directly related to cumulative fatigue usage and the applicant’s 

establishment of these limits is consistent with the recommendations of SRP-LR 

Section A.1.2.3.6. Further, SER Section 4.3 documents the staff’s evaluations of these ASME 

Section III fatigue analyses that are not directly related to cumulative fatigue usage. The staff’s 

concern described in RAI B3.1-2 is resolved. 

During its audit, the staff reviewed the applicant’s program basis document and noted that the 

FatiguePro® software, utilizes a one dimensional stress-intensity transfer function to calculate 

the fatigue effects of transient cycles used by the Metal Fatigue of RCPB Program. The staff 

noted that the applicant did not indicate consideration of RIS 2008-30 in its development of this 

program. By letter dated December 29, 2009, the staff issued RAI B3.1-3 requesting the 

applicant describe how it considered RIS 2008-30 in the development of the Metal Fatigue of 

RCPB Program and how it incorporated the results of this review into the enhanced Metal 

Fatigue AMP. 

In its response, dated February 19, 2010, the applicant stated that before the issuance of 

RIS 2008-30 on December 16, 2008, it was aware of staff concerns regarding the use of single 

element stress models to evaluate metal fatigue CUF using single element stress models similar 

to those in FatiguePro® to perform an evaluation of NUREG-6260 locations. The applicant 

stated that it performed an initial screening of the plant specific NUREG-6260 locations and 

selected three locations for further analysis. The applicant stated that an ASME III NB3200 

three-dimensional, six-element analysis evaluated these locations (charging nozzle safe end, 

shutdown cooling elbow, and pressurizer surge line elbow). The staff noted that the applicant 

reviewed RIS 2008-30 in August 2009 and determined that no additional actions were required. 

The applicant stated it determined that the staff concerns also applied to the FatiguePro® single 

element model being used in the SBF monitoring module of FatiguePro®. The staff noted that 

the applicant amended its LRA by letter dated February 19, 2010, to remove the text that states 

FatiguePro® will be used to monitor SBF locations. The staff also noted that LRA Sections A2.1 

and B3.1 and Commitment No. 39 have also been amended to reflect the use of a software 

monitoring program that incorporates a three-dimensional, six-element stress model. The staff 

noted that Commitment No. 39, as amended by letter dated May 27, 2010, specifically states, in 

part, the following: 

The SBF method will use a fatigue monitoring software program that incorporates 

a three-dimensional, six-component stress tensor method meeting ASME III 

NB-3200 requirements. 

Based on its review, the staff finds the applicant’s response to RAI B3.1-3 acceptable because, 

the applicant committed (Commitment No. 39) to using a software that incorporates a 

three-dimensional, six-component stress tensor method meeting ASME III NB-3200 

requirements. In addition, the applicant’s use of such software addresses the concerns in 

RIS 2008-30 of using a single element stress models. The staff’s concern described in 

RAI B3.1-3 is resolved. 

The staff noted that LRA Section 4.3 states that the Metal Fatigue AMP monitors and tracks the 

number of critical thermal and pressure transients for selected RCS components. The staff 

further noted that LRA Section 4.3.1.4, “Present and Projected Status of Monitored Locations,” 

states that a composite worst-case (composite-unit) envelope of operating transients was 

created, which included only the highest accumulation of each transient experienced among the 

three units from 1985–2005. The staff noted that the applicant did not provide individual plant 

data used for each unit to develop the composite-unit envelope. By letter dated 

December 29, 2009, the staff issued RAI B3.1-4 requesting the applicant provide the 
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accumulation of transients, for each of the three units, used to develop the composite-unit 

envelope for the period from 1985–2005. 

The applicant provided its response by letter dated February 19, 2010; however, the applicant 

amended its response to RAI B3.1-4 in its entirety and revised LRA Section 4.3.1 in 

Amendment 14, dated April 28, 2010. The applicant stated that it made the following changes: 

 revised Table 4.3-2 to clearly show correspondence between the LRA 

and UFSAR 

 revised Table 4.3-2 to identify transients that are tracked, provided 

justification for those transients that are not tracked, and clarified UFSAR 

limits 

 changed “global” monitoring to “cycle counting” 

 simplified the transient projection process and clarified that it is not 

intended to be used for action 

 revised the discussion on how the transient count data was recovered 

 revised Table 4.3-3 to be consistent with the UFSAR transients, replaced 

the worst case unit with actual totals for all three units, and provided the 

new simplified projections 

 revised the location-specific monitoring points (i.e. Table 4.3-4 now 

identifies the NUREG/CR-6260 locations and the pressurizer spray 

nozzle location) 

 Incorporated miscellaneous clarifications and editorial changes 

The staff noted that the applicant amended LRA Section 4.3.1.4 Subsection “Recount Method” 

to state the following, in part: 

Several APS employees and contractor personnel were designated based on 

their long-term familiarity with PVNGS to perform document reviews. The 

reviewers examined the microfilmed control room logs, NRC Monthly Operating 

Reports and LERs for the period prior to January 1996 for all three PVNGS units. 

The personal recollections and records of unit personnel were used to 

supplement the record review, and a best-source total was determined for each 

monitored transient. The best-source total was added to the actual count of 

events following 1995 to obtain a best-source total as of the end of 2005. 

The staff noted from LRA Section 4.3.1.4 that, before January 1996, the applicant’s CC 

procedure did not contain all transients listed in UFSAR Section 3.9.1.1. Therefore, the 

applicant reconstituted the number of cycles that occurred at all three units before January 1996 

in order to obtain the number of cycles for each transient that has occurred to date. The staff 

further noted that based on the applicant’s reconstitution of transient events, the applicant is no 

longer using the method of “composite worst-case unit accumulation of cycles.” 

Based on its review, the staff finds the applicant’s response to RAI B3.1-4, as amended, 

acceptable because the applicant revised LRA Section 4.3.1.4 to remove the use of its 

“composite worst-case unit accumulation of cycles” methodology and reconstituted the number 

of transient occurrences for each unit by reviewing control room logs, NRC Monthly Operating 

Reports, and LERs to obtain an accurate count of transients for each unit. The staff’s concern 

described in RAI B3.1-4 is resolved. 

The staff noted LRA Section B3.1 states that the locations in which fatigue effects are controlled 

by “a simple comparison” counting method are those with relatively low design fatigue usage 
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values. The staff required further information regarding the use of “a simple comparison” 

counting method. By letter dated December 29, 2009, the staff issued RAI B3.1-5 requesting 

the applicant to identify the locations selected for “a simple comparison” counting method, 

explain how it selected these locations, and define the criteria used to classify fatigue usage 

values as relatively low fatigue usage values. 

In its response, dated February 19, 2010, the applicant stated the locations listed in LRA 

Table 4.3-4 with “Fatigue Management Method” labeled “Global” are those locations monitored 

by the “simple comparison” counting method. The staff noted that by letter dated April 28, 2010, 

the applicant amended LRA Table 4.3-4 and revised the use of the term “Global” with “cycle 

counting.” The staff noted that the revision to the terminology was made to remove confusion 

from the LRA, but the applicant methodology did not change. 

The staff noted that the applicant reviewed all locations with a current design fatigue analysis 

and selected any locations with either low fatigue usage values or CUF bounded by a 

higher-usage location in the same plant system for the CC monitoring method. The applicant 

further described its criteria used to select these locations for the cycle counting method. The 

staff noted that Commitment No. 39 as amended by letter dated May 27, 2010, states the 

following, in part: 

The enhanced Metal Fatigue of Reactor Coolant Pressure Boundary program will 

provide action limits on cycles and on CUF that will initiate corrective actions 

before the licensing basis limits on fatigue effects at any location are exceeded. 

 In order to ensure sufficient cycle count margin to accommodate 

occurrence of a low-probability transient, corrective actions must be taken 

before the remaining number of allowable occurrences for any specified 

transient becomes less than 1. 

 CUF action limits will be established to require corrective action when the 

calculated CUF (from cycle-based or stress-based monitoring) for any 

monitored location is projected to reach 1.0 within the next 2 or 

3 operating cycles. In order to ensure sufficient margin to accommodate 

occurrence of a low probability transient, corrective actions will be taken 

while there is still sufficient margin to accommodate at least one 

occurrence of the worst-case design transient event (i.e., with the highest 

fatigue usage per event cycle). 

Based on its review, the staff finds the applicant’s response to RAI B3.1-5 acceptable because 

the applicant clarified its method and criteria for selecting locations that will be monitored by CC, 

it committed (Commitment No. 39) to establishing actions limits such that corrective actions will 

be taken prior to exceeding allowable cycles, and it will continue to monitor these transients to 

ensure allowable cycles are not exceeded. The staff’s concern described in RAI B3.1-5 is 

resolved. 

During its audit, the staff reviewed the applicant’s program basis document and Commitment 

No. 39 and noted that the program will be enhanced to include additional locations with high 

CUFs. However, the staff noted that the applicant did not identify the locations or provide 

justification for their use. By letter dated December 29, 2009 the staff issued RAI B3.1-6 

requesting the applicant provide additional information to explain which locations it included in 

the Metal Fatigue AMP as enhancements, explain how it selected these locations, and define 

the criteria it used to classify fatigue usage values as high fatigue usage values. 

In its response, dated February 19, 2010, the applicant stated that all locations in LRA 

Table 4.3-4, except the pressurizer spray nozzle, are being added as enhancements to the 

program. The staff noted that LRA Table 4.3-4, as amended, lists the pressurizer spray nozzle. 
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The applicant stated that the existing program includes a simplified cycle-based CUF calculation 

for the pressurizer spray nozzle in each unit, while fatigue in all other locations is currently 

managed by manual CC only, with current action levels at 90 percent of the number of cycles 

assumed by the design basis. 

The applicant stated that it reviewed all locations with a current design fatigue analysis and 

selected any locations that did not have low fatigue usage values or were identified in 

NUREG/CR-6260 for explicit monitoring, using either CBF or SBF methodologies. LRA 

Table 4.3-4, as amended, lists seven locations, associated with NUREG/CR-6260 and the 

pressurizer spray nozzle, as monitored by either CBF or SBF methodologies. The applicant 

further described its criteria used to select these locations for the CBF or SBF methodologies. 

The staff noted that in Commitment No. 39, as amended, the applicant will establish CUF action 

limits such that there will be two or three operating cycles to initiate and complete corrective 

actions. 

Based on its review, the staff finds the applicant’s response to RAI B3.1-6 acceptable because 

the applicant clarified the locations that will be added to the program as part of the 

enhancement. In addition, the applicant committed (Commitment No. 39) to establishing 

actions limits such that it will take corrective actions before exceeding the CUF design limit. 

Further, the applicant will continue to monitor these locations to ensure the design limit of 1.0 is 

not exceeded. The staff’s concern described in RAI B3.1-6 is resolved. 

During its review, the staff was unclear whether the applicant verified that the plant-specific 

locations listed in LRA Table 4.3-11 per NUREG/CR-6260 were bounding for the generic 

NUREG/CR-6260 components as well as for the plant. The staff requested the applicant to 

address this issue; the staff's evaluation of the applicant’s response is found in SER 

Section 4.3.4.2. 

During its audit, the staff reviewed the applicant’s program basis document and noted that 

Commitment No. 39 stated that the Metal Fatigue AMP will be enhanced with additional CC and 

fatigue usage action limits. However, the staff noted the applicant did not provide information 

on what additional CC and fatigue usage action limits will be included in the Metal Fatigue AMP. 

By letter dated December 29, 2009, the staff issued RAI B3.1-7 asking the applicant to provide 

the additional CC and fatigue usage action limit that will be included in the Metal Fatigue AMP 

as enhancements. 

In its response, dated February 19, 2010, the applicant stated that the current surveillance test 

procedure requires action when 90 percent of the allowable cycles are achieved for any 

monitored transient. The applicant further stated that during extended operation, projections 

indicate that certain allowable cycles and fatigue limits may be approached. Therefore, specific 

and targeted action limits are necessary to ensure actual fatigue limits are not exceeded. The 

applicant stated that it has not yet developed those action limits and, as it implements the 

transition to FatiguePro®, there are certain embedded administrative tools in FatiguePro® that 

will allow for specification of action limits based on projected fatigue usage at specific locations 

that account for actual cumulative fatigue. The applicant stated that the action limits can be 

based on the time required to implement expected or projected mitigating actions (such as 

component replacements or revisions to ASME Code Fatigue Analysis of Record) prior to 

exceeding actual fatigue limits. 

The staff noted that the applicant is required to maintain actual fatigue limits below the design 

limits. The staff further noted that the applicant may select actions limits to implement mitigating 

actions, such as component replacements or revisions to ASME Code Fatigue Analysis of 

Record, as the applicant deems appropriate. The staff noted that the applicant’s 

Commitment No. 39, as amended, will require the applicant to perform corrective actions before 

the remaining number of allowed occurrences for any specified transient becomes less than 1.0. 
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The staff also noted that the CUF action limits will be set so that there will be two or three 

operating cycles to initiate and complete corrective actions to ensure the design limit is not 

exceeded. 

Based on its review, the staff finds the applicant’s response to RAI B3.1-7 acceptable because, 

the applicant’s current action limits of 90 percent of the allowable cycles for any monitored 

transient provides time for corrective actions to be taken before exceeding design limits. In 

addition, the CC limits for the enhanced program provides for corrective actions to be taken 

prior exceeding the design allowable limits, and the CUF action limits for the enhanced program 

will provide two or three operating cycles so corrective actions are taken prior to exceeding the 

design limit. The staff’s concern described in RAI B3.1-7 is resolved. 

During its audit, the staff reviewed the applicant’s program basis document and noted that the 

scope of the Metal Fatigue AMP will be enhanced with a revised list of monitored plant 

transients that contribute to high usage factor as described for the “parameters monitored or 

inspected” and “monitoring and trending” program elements. The staff noted that the applicant 

did not describe this enhancement in Commitment No. 39 for the Metal Fatigue AMP. By letter 

dated December 29, 2009, the staff issued RAI B3.1-8 requesting the applicant provide 

additional information on how Commitment No. 39 will be revised to incorporate the 

enhancement to the Metal Fatigue AMP related to the revised list of monitored plant transients 

that contribute to high usage factor. The staff also asked that the applicant clarify the 

implementation schedule for the fatigue usage calculations described in Commitment No. 39. 

In its response, dated February 19, 2010, the applicant amended Commitment No. 39. 

Subsequently, by letter dated May 27, 2010, the applicant further modified LRA Section B3.1 in 

Amendment 16, removing the following enhancement: 

Parameters Monitored or Inspected – Element 3/Monitoring and Trending – 

Element 5 

The scope of the Metal Fatigue of Reactor Coolant Pressure Boundary program 

will be enhanced with a revised list of monitored plant transients that contribute to 

high usage factor, and with a revised list of monitored locations in Class 1 piping 

and vessels and in parts of the Class 2 steam generators that have a Class 1 

analysis. 

The staff noted that in Amendment 16, for the enhancement of the “scope of program” element, 

the applicant stated, in part: 

Metal Fatigue of Reactor Coolant Pressure Boundary program will monitor plant 

transients as required by PVNGS Technical Specification 5.5.5. 

The staff noted that the applicant will monitor those transients that are specified in TS 5.5.5, 

which refers to the transients listed in UFSAR Section 3.9.1.1. The staff finds this acceptable 

because the applicant will monitor its design transients consistent with its TS and CLB. The 

staff noted that the applicant’s implementation schedule of “no later than two years prior to the 

period of extended operation” is consistent with the SRP-LR Section 3.0.1. 

Based on its review, the staff finds the applicant’s response to RAI B3.1-8 acceptable because, 

the applicant clarified that its enhanced program will monitor plant transients as required by 

TS 5.5.5 and CLB, and the applicant’s implementation of the enhancement will be before the 

period of extended operation, consistent with the SRP-LR. The staff’s concern described in 

RAI B3.1-8 is resolved. 

The staff also reviewed the portions of the program elements associated with the enhancements 

to determine if the program will be adequate to manage the aging effects for which it is credited. 

The staff’s evaluation of these enhancements follows. 
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Enhancement 1. In LRA Section B3.1, as amended, the applicant identifies an enhancement to 

the “scope of program” element for implementation of the following activities: 

 CUF tracking for environmental component locations (NUREG/CR-6260 locations) that 

are not monitored using the applicant’s CC monitoring method 

 use of FatiguePro® software as the CC and CBF monitoring method basis and use of a 

six-component stress tensor, three-dimensional software program for implementation of 

the applicant’s SBF monitoring methodology 

 tracking of plant transients required by TS 5.5.5 

The staff's review determined that this enhancement has been appropriately accounted for in 

the changes to Commitment No. 39, as submitted to the staff in a letter dated May 27, 2010. 

The staff also determined that the enhancement ensures that the “scope of program” element 

will be consistent with the GALL Report Metal Fatigue AMP when the enhanced program is 

implemented before the period of extended operation. 

The staff's review included applicable resolution of RAI 4.3-2, and RAIs 4.3-7 through 

RAI 4.3-10, associated with the scope of the applicant’s program (see SER Section 4.3.2.1 for a 

detailed discussion of these RAIs). On the basis of its review, the staff finds this enhancement 

acceptable because, when implemented prior to the period of extended operation, it will make 

the program consistent with the recommendations in the GALL Report Metal Fatigue AMP.

Enhancement 2. LRA Section B3.1, as amended, identifies an enhancement to the 

“preventative actions,” “acceptance criteria,” and “corrective actions” program elements of the 

Metal Fatigue AMP. This enhancement updates the summary descriptions to reflect the 

applicable changes made to the action limits and corrective actions for CC and CUF activities. 

The staff’s review determined that this enhancement has been appropriately accounted for in 

the changes to Commitment No. 39. Further, the staff verified that the enhancement program 

elements for this AMP will be consistent with the corresponding program elements in the GALL 

Report Metal Fatigue AMP when the enhanced program is implemented during the period of 

extended operation. 

The staff noted that GALL Report Metal Fatigue AMP acceptance criteria maintains the fatigue 

usage below the design code limit of 1.0, considering environmental fatigue effects and 

corrective actions that prevent the usage factor from exceeding the design code limit during the 

period of extended operation. The staff noted that the applicant’s program when enhanced also 

will contain action limits that ensure timely corrective actions such that the CUF of a particular 

component does not exceed the design limit of 1.0. 

The review included applicable resolution of RAIs 4.3-11 and RAI 4.3-12, which are associated 

with the “acceptance criteria” and “corrective actions” program elements for the applicant’s 

program as documented in SER Section 4.3.1. The staff’s evaluation of 

environmentally-assisted fatigue is documented in SER Section 4.3.4.2. On the basis of its 

review and responses to RAIs 4.3-11 and RAI 4.3-12, the staff finds this enhancement 

acceptable because when it is implemented prior to the period of extended operation and it will 

make the program consistent with the recommendations in the GALL Report AMP. 

Enhancement 3 and 4. LRA Section B3.1, as amended, identifies an enhancement to the 

“parameters monitored or inspected,” “detection of aging effects,” and “monitoring and trending” 

program elements. The staff noted that these enhancements reflect the applicant’s proposed 

use of FatiguePro® software and use of a three-dimensional, six-element stress tensor software 

program. 

The staff noted that the applicant modified Commitment No. 39 to reflect the use of a fatigue 

monitoring software program and a methodology for SBF monitoring that will implement a 
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three-dimensional, six-element stress tensor analysis method and will conform to the 

requirements of ASME Section III Article NB-3200. This resolves the staff’s concern because 

the applicant is no longer using the monitoring methodology that was of concern in 

RIS-2008-30. The staff also noted that the use of this software allows the applicant to monitor 

cycles and the CUF to ensure that the design limit of 1.0 is not exceeded consistent with the 

recommendations in the GALL Report AMP. 

The staff’s review determines this enhancement is appropriately accounted for in the changes to 

Commitment No. 39, and the enhancement in the commitment ensures that the “parameters 

monitored or inspected,” “detection of aging effects,” and “monitoring and trending” program 

elements will be consistent with the corresponding program elements in the GALL Report Metal 

Fatigue AMP when the enhanced program is implemented during the period of extended 

operation. 

Based on its audit and review of the applicant’s responses to RAIs, the staff finds that elements 

one through six of the applicant’s Metal Fatigue of Reactor Coolant Pressure Boundary 

Program, with enhancements 1 through 4, are consistent with the corresponding program 

elements of the GALL Report Metal Fatigue AMP and are, therefore, acceptable. 

Operating Experience. LRA Section B3.1 summarizes operating experience related to the Metal 

Fatigue AMP. The staff noted that this section discusses the operating experience that led to 

the industry’s development of the FatiguePro® software. The applicant provided the following 

examples where it had implemented corrective actions based on the existing program’s CC and 

CUF monitoring bases: 

 implementation of weld overlays on pressurizer surge line and spray line nozzles and hot 

leg surge nozzles in order to address the potential for thermal stratification 

 replacements of the auxiliary spray line and main spray line components to address 

concerns raised in Bulletin 88-08 

 implementation of linear elastic fracture mechanics evaluations for fatigue flaws detected 

in the Unit 2 pressurizer support skirt forging weld during an ISI 

 actions to address CE Owners Group recommendations and initiatives on fatigue 

induced surge line microcracking 

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicant reviewed the applicable aging effects and industry and plant-specific 

operating experience. As discussed in the Audit Report, the staff conducted an independent 

search of the plant operating experience information to determine if the applicant had 

adequately incorporated and evaluated operating experience related to this program. The staff 

found that the applicant had adequately identified and incorporated industry and applicable 

plant-specific operating experience. 

Based on its audit and review of the application, including LRA amendments, the staff finds that 

operating experience related to the applicant’s program demonstrates that it can adequately 

manage the detrimental effects of aging on SSCs within the scope of the program and that it 

satisfies the criterion in SRP-LR Section A.1.2.3.10. 

UFSAR Supplement. LRA Section A2.1 provides the UFSAR supplement for the Metal Fatigue 

AMP, as amended by LRA Amendment 16 (May 27, 2010). The staff reviewed this UFSAR 

supplement description of the program against the recommended description for this type of 

program, as described in SRP-LR Table 4.3-2. 

Amendment 16 modifies LRA Appendix A, Section A2.1 in order to make it consistent with the 

changes made in LRA Appendix B, Section B3.1. The staff noted the applicant’s changes 

included updates of the summary description to reflect: 
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 applicable TS 5.5.5 cycle tracking requirements 

 applicable changes to the action limits and corrective actions on CC monitoring activities 

 applicable changes to the action limits and corrective actions on CUF monitoring 

activities 

 proposed use of FatiguePro® for the program’s CC and CBF monitoring bases and of a 

three-dimensional, six-component stress tensor software methodology for the program’s 

SBF monitoring basis 

The staff also noted that the amendment included changes to Commitment No. 39 in order to 

reflect the changes to the four enhancements for the program. The staff determines that the 

information in the UFSAR supplement is an adequate summary description of the program, as 

required by 10 CFR 54.21(d). 

Conclusion. On the basis of its audit, review of the applicant’s Metal Fatigue of Reactor Coolant 

Pressure Boundary Program, and responses to the staff's RAIs, the staff determines that those 

program elements for which the applicant claimed consistency with the GALL Report are 

consistent. Also, the staff reviewed the enhancements and confirmed that their implementation 

through Commitment No. 39 prior to the period of extended operation would make the existing 

AMP consistent with the GALL Report AMP to which it was compared. The staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended functions will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

3.0.3.2.23 Concrete Containment Tendon Prestress Program 

Summary of Technical Information in the Application. LRA Section B3.3 describes the existing 

Concrete Containment Tendon Prestress Program with enhancements that are consistent with 

the program elements in GALL Report AMP X.S1, “Concrete Containment Tendon Prestress.” 

The applicant states that the Concrete Containment Tendon Prestress Program and is within 

the ASME Section XI Subsection IWL Program. The program manages the loss of tendon 

prestress aging effect in the post-tensioning system and is consistent with supplemental 

requirements of 10 CFR 50.55a. 

The applicant stated that prior to September 1996, the tendon examinations were controlled by 

RG 1.35, “Inservice Inspection of Ungrouted Tendons in Prestressed Concrete Containments.” 

Since 2001, ASME XI Subsection IWL, 1992 edition with 1992 addenda controls this program. 

The beginning of the second 10-year inspection interval will be August 1, 2011, for all 

three units, and the program will be updated for subsequent intervals as required by 

10 CFR 50.55a(b)(2)(vi) and (viii), and 10 CFR 50.55a(g)(4)(ii). 

The applicant further stated that tendon lift-off surveillances were performed for Units 1 and 3 at 

one, three and five year intervals following the post-structural-integrity test, then at 5-year 

intervals. Unit 2 tendons were examined using visual and other methods, but that the lift-off test 

surveillances were encompassed within the Unit 1 tests under rules applicable at that time to 

two unit plants with virtually-identical containments. A licensing change under RR-4 imposed 

similar lift-off testing on Unit 2, beginning with its 20th year, but it extended the surveillance 

interval to 10 years. 

The applicant went on to state the following: 

The PVNGS post-tensioning system consists of inverted-U-shaped vertical 

tendons, extending up through the basemat, through the full height of the 

cylindrical walls and over the dome; and horizontal circumferential (hoop) 
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tendons, at intervals from the basemat to about the 45-degree elevation of the 

dome. The tendons are ungrouted, in grease-filled ducts. 

The design basis of the containment system requires that the average 

prestresses of the tendons in the horizontal dome and cylinder hoop tendon 

subgroups, and in the vertical tendon group, remain above their respective 

minimum required values (MRVs). The MRVs are from the original design bases 

and assumptions. 

In order to ensure that the design basis continues to be met, the acceptance 

criteria require that the prestress in each tendon remain above, or within a stated 

tolerance below, the predicted force. The predicted lower limit (PLL) described in 

NUREG-1801 is functionally equivalent to the first action level of the PVNGS and 

IWL 3221.1 acceptance criteria, at 95 percent of the predicted force line. The 

surveillance program predicted mean prestress force lines and their 

tolerance-band upper and lower limit lines, and the predicted forces for each 

surveillance tendon, were developed from the loss of prestress model used for 

the original design, and are consistent with Regulatory Guide 1.35.1, Proposed 

Revision 0. 

The LRA states that the first set of regression analyses of tendon lift-off data were performed in 

support of this LRA. The applicant asserts that the regression analyses of surveillance data are 

consistent with IN 99-10, “Degradation of Prestressing Tendon Systems in Prestressed 

Concrete Containments, Attachment 3” and that the program will be enhanced to continue to 

compare regression analysis trend lines. The comparisons will include the individual lift-off 

values of tendons surveyed to date in each of the vertical and hoop tendon groups, with the 

MRV and PLL for each tendon group to the end of the licensed operating period. The applicant 

will take appropriate corrective action if future values indicated by the regression analysis trend 

line drop below the PLL or MRV. The applicant will updated regression analyses for tendons of 

the affected unit and for a combined data set of all three units following each inspection. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed and confirmed that the plant’s conditions are bounded by 

the conditions for which the GALL Report was evaluated. The staff compared elements one 

through six of the applicant’s program to the corresponding elements of the GALL Report AMP. 

As discussed in the Audit Report, the staff confirmed that elements “scope of program,” 

“preventive actions,” “parameters monitored or inspected,” and “detection of aging effects” of the 

LRA AMP were consistent with the corresponding elements of the GALL Report AMP. 

Enhancement. The applicant has committed (Commitment No. 41) to enhancing the AMP 

program elements “monitoring and trending” and “acceptance criteria.” These enhancements 

expand on the existing program elements, and require an update of the plant procedures for the 

regression analysis methods, including the use of individual tendon data in accordance with 

IN 99-10, “Degradation of Prestressing Tendon Systems in Prestressed Concrete 

Containments.” The staff has determined that these enhancements are acceptable because the 

program description section of the GALL Report Concrete Containment Tendon Prestress AMP 

recommends the use of IN 99-10 for constructing the trend lines (regression analysis). 

Operating Experience. LRA Section B3.3 summarizes operating experience related to the 

Concrete Containment Tendon Prestress Program. The applicant stated that qualified 

personnel, familiar with the tendon performance history and with current issues and practices, 

conduct the tendon surveillance and lift-off tests. The program employs examination 

procedures which invoke, and are developed from, the design criteria (MRVs), inspection 

acceptance criteria (predicted force lines and their tolerance band upper and lower limit lines 
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and their application to action levels and corrective actions), inspection schedule, sample 

selection, and effective stress calculation methods. 

The applicant further stated that the tendon inspections to date have shown the following: 

 no evidence of significant corrosion or other effects that might damage wires 

 minimum wire breakage (after initial installation) 

 no accelerated loss of prestress due to high temperatures or other causes 

The only significant findings were pinhole grease leaks in Units 2 and 3, which were evaluated 

as having no detrimental effects on the containment structure. 

The applicant also stated that the most recent results of the Concrete Containment Tendon 

Prestress Program demonstrated that average prestress in both the vertical tendon group and 

the horizontal cylinder and horizontal dome tendon subgroups should remain above the 

applicable MRVs for at least 60 years of operation. Therefore, all tendons should maintain their 

design basis function for the extended period of operation. The material condition of other 

components (e.g., concrete, bearing surfaces, grease, buttonheads, etc.) showed only minor 

degradation in a few areas; none indicating a need for significant corrective action. 

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicant reviewed the applicable aging effects and industry and plant-specific 

operating experience. As discussed in the Audit Report, the staff conducted an independent 

search of the plant operating experience information to determine if the applicant had 

adequately incorporated and evaluated operating experience related to this program. 

The GALL Report Concrete Containment Tendon Prestress AMP states that IN 99-10 provides 

guidance for constructing the trend line. However, the LRA Concrete Containment Tendon 

Prestress Program, “monitoring and trending” element states that the program will be enhanced 

to require a regression analysis for each tendon group after every surveillance. The applicant 

performed tendon surveillance for Units 1, 2, and 3 during 2008, 2006, and 2002, respectively. 

However, according to the LRA AMP, the applicant has not revised the Concrete Containment 

Tendon Prestress Program document until now. Therefore, the staff requested, in RAI B3.3-1 

issued in a letter dated December 27, 2009, that the applicant to provide the status and 

conclusions of the regression analysis performed in accordance with IN 99-10. 

In response to the RAI B3.3-1, in a letter dated February 19, 2010, the applicant stated that it 

performed regression analyses of tendon lift-off data in support of the LRA. The regression 

analyses of surveillance data are consistent with IN 99-10. The applicant will enhance the 

program to continue to compare regression analysis trend lines of the individual lift-off values of 

tendons surveyed to date. LRA Table A4-1, Commitment No. 41, documents this enhancement. 

The applicant further stated that it extended a regression analysis of the lift-off data of the most 

recent results to date to 60 years. This analysis demonstrated that the average prestress in 

tendons should remain above the applicable minimum required values for at least 60 years of 

operation and that all tendons should, therefore, maintain their design basis function for the 

extended period of operation. 

The staff finds the response to RAI B3.3-1 acceptable because the applicant has performed 

regression analysis using the individual tendon data to construct the lift-off trend lines in 

accordance with IN 99-10 for both the vertical tendon group and the horizontal cylinder and 

horizontal dome tendon subgroups. In addition, the applicant has committed to enhancing the 

tendon surveillance procedures prior to the period of extended operation. These procedures will 

require an update of the regression analysis for each tendon group of each unit. 

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 
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of aging on SSCs within the scope of the program and that implementation of the program has 

resulted in the applicant taking corrective actions. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10 and is, 

therefore, acceptable. 

UFSAR Supplement. LRA Section A2.3 provides the UFSAR supplement for the Concrete 

Containment Tendon Prestress Program. The staff reviewed this UFSAR supplement 

description of the program and notes that it conforms to the recommended description for this 

type of program, as described in SRP-LR Table 3.5-2. The staff also notes that the applicant 

committed (Commitment No. 41) to the ongoing implementation of the existing Concrete 

Containment Tendon Prestress Program with enhancements to manage the aging of the 

concrete containment and post-tensioning system during the period of extended operation. The 

staff determines that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d). 

Conclusion. On the basis of its review of the applicant’s Concrete Containment Tendon 

Prestress Program, the staff finds all program elements consistent with the GALL Report. Also, 

the staff reviewed the enhancement and confirmed that its implementation through Commitment 

No. 41 before the period of extended operation would make the existing AMP consistent with 

the GALL Report AMP to which it was compared. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

functions will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP, 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

3.0.3.3 Aging Management Programs Not Consistent with or Not Addressed in the 

Generic Aging Lessons Learned Report 

In LRA Appendix B, the applicant identified the following AMPs as plant-specific: 

 Nickel-Alloy AMP 

 Protective Coatings Monitoring and Maintenance Program 

For AMPs not consistent with or not addressed in the GALL Report, the staff performed a 

complete review to determine their adequacy to monitor or manage aging. The following 

section documents the staff’s review of these plant-specific AMPs. 

3.0.3.3.1 Nickel-Alloy Aging Management Program 

Summary of Technical Information in the Application. LRA Section B2.1.34 describes the 

existing Nickel-Alloy AMP as plant-specific. The applicant stated that the Nickel-Alloy AMP 

manages cracking due to SCC in most components fabricated from alloy 600 (including 

alloy 82/182 weld metal) in the RCS and engineering safety features (ESF) systems. The 

applicant also stated that the Nickel-Alloy AMP uses inspections, mitigation techniques, repair 

or replace activities and monitoring of operating experience to manage the aging of alloy 600. 

Staff Evaluation. The staff reviewed program elements 1–6 and 10 of the applicant’s program 

against the acceptance criteria for the corresponding elements, as stated in SRP-LR 

Section A.1.2.3. The staff’s review focused on how the applicant’s program manages aging 

effects through the effective incorporation of these program elements. The staff’s evaluation of 

each of these elements follows. 

Prior to that evaluation, it may prove helpful to consider the manner in which this AMP is used to 

manage aging. This AMP appears only in LRA Table 2 items, which are subordinate to LRA 

Table 1, items 3.1.1.31 and 3.1.1.34. These table 1 items are subject to further evaluation in 

LRA paragraphs 3.1.2.2.13 and 3.1.2.2.16.1. 
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For LRA Table 1, items 3.1.1.31 and 3.1.1.34 (see GALL Report, Table 3.1-1, items 31 and 34), 

the GALL Report recommends that aging management be accomplished using the ASME 

Section XI ISIs IWB, IWC, and IWD AMP and the Water Chemistry AMP. For Nickel Alloys, the 

GALL Report further recommends that applicants comply with all NRC orders, and provide a 

commitment in the UFSAR supplement to implement applicable bulletins, GLs, and 

staff-accepted industry guidelines. 

For each LRA Table 2 item that cites the Nickel-Alloy AMP, it also includes the applicant’s 

ASME Section XI ISI IWB, IWC, and IWD AMP; Water Chemistry AMP; and commitment to 

comply with NRC orders, bulletins, GLs, and staff-accepted industry guidelines. That is, the 

approach to aging management for these components offered by the applicant, contains all 

aspects recommended by the GALL Report, in addition to the Nickel-Alloy AMP. 

The staff’s review of the ASME Section XI ISI IWB, IWC, and IWD AMP is in SER 

Section 3.0.3.1.1 and the Water Chemistry AMP is in SER Section 3.0.3.2.1. Given that other 

sections of this SER evaluate these LRA AMPs, and have found them consistent with the GALL 

Report, the staff finds that the use of this AMP is beneficial, but not essential, for the applicant to 

achieve consistency with the GALL Report. 

Based on this finding, the remainder of this evaluation is based on the consistency of the AMP 

with the SRP-LR and the sufficiency of the AMP to accomplish its stated objectives. 

Scope of the Program. LRA Section B2.1.34 states that the Nickel-Alloy AMP is an existing 

program that manages the effects of aging in alloy 600 components (including alloy 82/182 weld 

metal) found in the RCS and the ESF system. The scope of the program element contains a 

specific list of components, which are included within the scope, as well as a general 

specification of components that are excluded. 

The staff reviewed the applicant’s “scope of the program” program element against the criteria 

in SRP-LR Section A.1.2.3.1, which states that the program should include the specific SCs for 

which the program manages aging. 

Based on the list provided, which addresses materials and components included within the 

scope of the AMP, the staff confirmed that the “scope of the program” program element satisfies 

the criterion defined in SRP-LR Section A.1.2.3.1 and is, therefore, acceptable. 

Preventive Actions. LRA Section B2.1.34 states that several techniques are available to 

mitigate cracking due to PWSCC. These techniques remove one or more of the conditions 

necessary to cause cracking (i.e., susceptible material, tensile stress, specific environment). 

The section provides a specific list of components and potential preventive actions. 

LRA Section B2.1.34 also states that the “Water Chemistry Program (B2.1.2) provides 

preventive actions for monitoring and control of the supporting environment for PWSCC.” 

The staff reviewed the applicant’s “preventive actions” program element against the criteria in 

SRP-LR Section A.1.2.3.2, which states that the applicant should describe activities for 

prevention and mitigation programs. 

Based on the LRA description of the available mitigative techniques and the description of 

where these techniques may be employed, the staff confirmed that the “preventive actions” 

program element satisfies the criterion defined in SRP-LR Section A.1.2.3.2 and is, therefore, 

acceptable. 

Parameters Monitored or Inspected. LRA Section B2.1.34 states that the program monitors for 

cracking due to PWSCC through a combination of visual, surface, and volumetric exams. 

These exams directly detect cracking or detect the presence of boric acid, which may be 

deposited on visible surfaces as a result of a through-wall crack. 
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The staff reviewed the applicant’s “parameters monitored or inspected” program element 

against the criteria in SRP-LR Section A.1.2.3.3. This section states that the applicant should 

identify the parameters to be monitored or inspected and link them to the degradation of the 

particular SC intended function. The parameter monitored or inspected, in a condition 

monitoring program, should detect the presence and extent of aging effects. 

The staff finds that, for the components under consideration, cracking is the degradation 

mechanism that will affect the intended function and that a combination of visual, surface, and 

volumetric exams will directly detect cracks or secondary evidence of cracks (e.g., boric acid). 

Based on this finding, the staff confirmed that the “parameters monitored or inspected” program 

element satisfies the criterion defined in SRP-LR Section A.1.2.3.3 and is, therefore, 

acceptable. 

Detection of Aging Effects. LRA Section B2.1.34 states that the applicant uses visual, surface, 

and volumetric exams to detect cracking due to PWSCC in alloy 600 components. In this 

element, the applicant also provides a list of components to be inspected, the inspection 

methods to be used, and the reference documents containing the inspection requirement (e.g., 

CFR, ASME Code, ASME Code Case). These documents contain procedures for conducting 

the inspection as well as allowable inspection intervals. 

The staff reviewed the applicant’s “detection of aging effects” program element against the 

criteria in SRP-LR Section A.1.2.3.4, which states that detection of aging effects should occur 

before there is a loss of the SC intended function(s). The criteria also states that parameters to 

be monitored or inspected should be appropriate to ensure that the SC intended function will be 

adequately maintained for license renewal under all CLB design conditions. The criteria further 

state that a program based solely on detecting SC failure should not be considered as an 

effective AMP for license renewal. The criteria states that this program element describes 

“when,” “where,” and “how” program data are collected (i.e., all aspects of activities to collect 

data as part of the program). The criteria continue by stating that the method or technique and 

frequency may be linked to plant-specific or industry-wide operating experience. 

In its review, the staff determined that cracking is an appropriate parameter to monitor to ensure 

the maintenance of intended function of the components under consideration. The staff also 

determined that a combination of visual, surface, and volumetric test methods were capable of 

detecting aging prior to loss of intended function. The staff further determined that, while 

observation of boric acid or other secondary evidence of cracking was not fully consistent with 

detection of aging prior to loss of function (pressure boundary in this case), it was an effective 

method of identifying aging prior to loss of actual function of the component (failure of a piping 

system to supply adequate water to cool the reactor core). The staff additionally determined 

that this element of the AMP refers to the CFR, ASME Code, and various code cases and that 

these documents contain the specifications (how, where, when) for these inspections. The staff 

finally determined that there is no industry or plant-specific operating experience, which 

necessitates deviating from the inspections proposed in this program element. 

Based on the above evaluation, the staff confirmed that the “detection of aging effects” program 

element satisfies the criterion defined in SRP-LR Section A.1.2.3.4 and is, therefore, 

acceptable. 

Monitoring and Trending. LRA Section B2.1.34 provides a detailed list of inspections to be 

conducted and, in conjunction with program element 4, frequencies of those inspections. The 

list of inspections refers to governing documents (CFR, ASME, ASME Code Cases). These 

documents provide guidance regarding the evaluation of inspection data against acceptance 

criteria and the timing of subsequent inspections to ensure that component intended function is 

not lost before the next inspection. 
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The staff reviewed the applicant’s “monitoring and trending” program element against the 

criteria in SRP-LR Section A.1.2.3.5, which state that the applicant should describe monitoring 

and trending activities, which should provide predictability of the extent of degradation and, thus, 

ensure timely corrective or mitigative actions. The criteria also state that plant-specific or 

industry-wide operating experience may be considered in evaluating the appropriateness of the 

technique and frequency. The criteria further state that this program element describes “how” 

the applicant evaluates data collected. It may also include trending for a forward look, including 

an evaluation of the results against the acceptance criteria and a prediction of the rate of 

degradation, in order to confirm that timing of the next scheduled inspection will occur before a 

loss of SC intended function. 

In this review, the staff determined that this program element adequately describes the 

monitoring and trending proposed. The staff also determined that the governing documents for 

the inspections to be monitored and trended provide sufficient guidance concerning inspection 

frequency and the modification of that frequency based on past inspections or other 

plant-specific or industry operating experience to provide timely corrective action or mitigation or 

additional inspections prior to loss of intended function. The staff further determined that the 

program element and the governing documents provided sufficient guidance to allow the 

applicant to compare collected data to applicable acceptance standards. 

Based on the above evaluation, the staff confirmed that the “monitoring and trending” program 

element satisfies the criterion defined in SRP-LR Section A.1.2.3.5 and is, therefore, 

acceptable. 

Acceptance Criteria. LRA Section B2.1.34 states that acceptance criteria for this program are 

contained in governing documents (Materials Reliability Program (MRP) 139, CFR, ASME 

Code, and ASME Code Cases). 

The staff reviewed the applicant’s “acceptance criteria” program element against the criteria in 

SRP-LR Section A.1.2.3.6, which states the acceptance criteria of the program and its basis 

should be described, including ensuring that the SC intended function(s) are maintained under 

all CLB design conditions during the period of extended operation. Acceptance criteria could be 

specific numerical values or could consist of a discussion of the process for calculating specific 

numerical values of conditional acceptance criteria to ensure that the SC intended function(s) 

will be maintained under all CLB design conditions. The applicant may cite information from 

available references. The acceptance criteria, which permit some degradation, are based on 

maintaining the intended function under all CLB design loads. The criteria further state that the 

applicant should conduct qualitative inspections to the same predetermined criteria as 

quantitative inspections by personnel, in accordance with ASME Code and through approved 

site-specific programs. 

In its review, the staff determined that the acceptance criteria for these inspections are clearly 

defined in the program element or in the governing documents. The staff also has no reason to 

believe that these values, many of which carry the force of regulation, would not allow for the 

intended function of the components under consideration to be maintained during the period of 

extended operation under all CLB design loads. 

Based on the above review, the staff confirmed that the “acceptance criteria” program element 

satisfies the criterion defined in SRP-LR Section A.1.2.3.6 and is, therefore, acceptable. 

Operating Experience. LRA Section B2.1.34 summarizes operating experience related to the 

Nickel-Alloy AMP. In this program element, the applicant provided a detailed list of components 

that had been inspected and had shown no failures, components that had been inspected and 

had shown failures, and components that had shown no failures but had been proactively 

replaced or mitigated based solely on the potential for cracking. 
Aging Management Review Results 

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The staff reviewed this information against the acceptance criteria in SRP-LR 

Section A.1.2.3.10, which states that the operating experience information provided should 

present objective evidence that the applicant will adequately manage the effects of aging so that 

the intended function(s) of the in-scope components and structures are maintained during the 

period of extended operation. 

In this review, the staff found very few instances in which the inspections performed showed 

significant indications. In each of these cases, the applicant took actions indicating that this 

AMP was effective in addressing adverse inspection findings. Also during this review, the staff 

identified numerous instances where the applicant made proactive repairs or replacements. 

The staff views these activities as indications that the AMP is effective in indicating the potential 

for degradation and the need for preventive action. The staff considers the replacement of the 

RV heads to be significant evidence of the applicant’s commitment to adequate aging 

management of nickel-alloy components. 

Based on this review, the staff finds that operating experience related to the applicant’s program 

demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the 

scope of the program and that implementation of the program has resulted in the applicant 

taking corrective actions. The staff confirmed that the “operating experience” program element 

satisfies the criterion in SRP-LR Section A.1.2.3.10 and is, therefore, acceptable. 

UFSAR Supplement. LRA Section A1.34 provides the UFSAR supplement for the Nickel-Alloy 

AMP. The staff reviewed this UFSAR supplement description of the program and notes that it 

conforms to the recommended description for this type of program, as described in SRP-LR 

Table 3.1-2. The staff also notes that the applicant committed (Commitment Nos. 7 and 36) to 

the ongoing implementation of the existing Nickel-Alloy Penetration Nozzles Welded to the 

Upper RV Closure Heads of PWRs Program and Nickel-Alloy AMP, to manage the aging of the 

RV head and penetrations nozzles during the period of extended operation. The staff 

determines that the information in the UFSAR supplement is an adequate summary description 

of the program, as required by 10 CFR 54.21(d). 

Conclusion. The staff concludes that, based on the AMR items present in the application and 

the scope of other AMPs, the use of this AMP is not necessary to obtain consistency with the 

GALL Report. The staff also concludes that this AMP contains valuable information, which will 

help in the management of aging of nickel alloys. 

On the basis of its technical review of the applicant’s Nickel-Alloy AMP, the staff concludes that 

the applicant has demonstrated that, through the use of this AMP, the effects of aging of nickel 

alloys may be adequately managed so that the intended functions of the components under 

consideration will be maintained consistent with the CLB for the period of extended operation, 

as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this 

AMP, and concludes that it provides an adequate summary description of the program, as 

required by 10 CFR 54.21(d). 

3.0.3.3.2 Protective Coatings Monitoring and Maintenance Program 

Summary of Technical Information in the Application. LRA Section 2.1.6.4 describes the 

generic safety issue (GSI)-191, “Assessment of Debris Accumulation on PWR Sump 

Performance,” and states the following: 

By letter no. 102-05336, dated September 1, 2005, APS submitted to the NRC a 

response to Generic Letter (GL) 2004-02, “Potential Impact of Debris Blockage 

on Emergency Recirculation During Design Basis Accidents at Pressurized 

Water Reactors”. The issues identified in GSI-191 and Generic Letter 2004-02 

are not aging-related issues. Also, the issues are not related to the 40-year term 

of the current operating license, and, therefore, are not time-limited aging 
Aging Management Review Results 

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analyses. The containment sumps are evaluated in Section 2.[4].1, Containment 

Building. 

In LRA, Appendix B, Section B2.1.32, “Structures Monitoring Program,” the applicant states that 

it takes no credit for coatings in the determination of aging effects for the underlying materials. 

Although the coatings are not credited for aging management, the staff believes their failure 

could impact the functioning of safety systems. 

Staff Evaluation. The staff reviewed LRA Section 2.1.6.4 and Table B2, line item XI.S.8, 

“Protective Coating Monitoring and Maintenance Program,” using GALL XI.S8 as guidance. As 

the applicant did not credit the Protective Coatings Monitoring and Maintenance Program for 

aging management, the staff was unable to review the program elements against the 

acceptance criteria, as stated in SRP-LR Section A.1.2.3. As a result, the staff determined the 

need for additional clarification, which resulted in issuance of RAI B2.1.32-1. 

In RAI B2.1.32-1, dated August 11, 2009, the staff requested that the applicant provide details 

of the Coatings Assessment Program, referenced in the supplemental response to GL 2004-02, 

dated February 29, 2008. These details were needed to provide adequate assurance that 

protective coatings in containment would be properly maintained and not become a debris 

source that might challenge the ECCS. 

In its response, by letter dated September 10, 2009, the applicant provided the following 

information: 

As noted in the RAI, the coatings program is not credited for Palo Verde Nuclear 

Generating Station (PVNGS) license renewal aging management and, as such, 

this program has not been included within the scope of license renewal. 

However, Arizona Public Service Company (APS) agrees that the coatings 

program is important for the Emergency Core Cooling System (ECCS) 

performance. 

The Palo Verde Containment Coatings Condition Assessment procedure defines 

the inservice monitoring program for containment coatings to include service 

level I coatings and unqualified coatings. Inspection results are used to maintain 

coating system integrity and as an input into the mechanical design of the ECCS 

sump and input into the Mechanical Design/Nuclear Fuel Management Design 

Basis Accident (DBA) Loss-of-Coolant Accident (LOCA) Analysis. The 

procedure directs visual inspections of accessible coated surfaces of each area 

or room of containment to look for defects such as: 

 Blistering 

 Cracking 

 Flaking/Peeling delamination 

 Rusting 

 Mechanical or physical damage 

Inspections are performed every operating cycle. Coatings identified as being 

degraded are documented in the corrective action process. The coating 

specialist reviews newly identified defects or damage to determine if further 

testing is required to identify the extent of the defect or damage and to answer 

any operability questions. Possible corrective actions include: 

 Recoating 

 Coating removal 
Aging Management Review Results 

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 Repair at a future date (bare substrate addressed) 

 Monitor and trend (coatings that are not added to unqualified coatings 

log) 

Coatings inspectors are qualified to a certified coatings inspection program or are 

ANSI N45.2.6 certified. 

The staff reviewed the response to RAI B2.1.32-1 and, during a follow-up discussion with the 

applicant, confirmed that the applicant was going to submit a letter to the NRC, with a 

commitment to incorporate the coating inspections described in the GL 2004-02 response into 

the UFSAR. This commitment would require coating inspections to continue into the period of 

extended operation. By letter dated May 7, 2010, the licensee submitted the commitment 

described in their response to RAI B2.1.32-1. 

The staff finds the inspection frequency of the containment coatings to be acceptable since, at 

the frequencies stated above, it will provide adequate assurance that there is proper 

maintenance of the protective coatings so that they will not degrade and become a debris 

source that may challenge the ECCS. The staff also finds the scope of the program acceptable 

since it includes all accessible coated areas inside containment. The acceptance criterion is 

found to be acceptable since the staff has accepted and confirmed the acceptability of the 

ASTM standards proposed above using RG 1.54, Revision 1. The method of performing the 

coatings inspection is acceptable since the staff has confirmed that the ASTM standard 

proposed is acceptable using RG 1.54, Revision 1. The qualification of personnel who perform 

the inspection is acceptable since the staff has confirmed that the ANSI standard proposed is 

found to be acceptable using RG 1.54, Revision 1. Therefore, the staff’s concern in RAI 

B2.1.32-1 is resolved. 

The commitment, discussed under GSI-191 above, is a regulatory commitment under PVNGS 

CLB, and it is not captured in license renewal; however, since this commitment incorporates 

actions into the UFSAR, this will ensure GSI-191 related inspections continue into the period of 

extended operation. 

Conclusion. On the basis of its technical review of the applicant’s Protective Coating Monitoring 

and Maintenance Program, the staff concludes that the applicant has demonstrated that effects 

of aging will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB for the period of extended operation, as required by 10 CFR 

54.21(a)(1). 

3.0.4 Quality Assurance Program Attributes Integral to Aging Management Programs 

3.0.4.1 Summary of Technical Information in the Application 

In Appendix A, “Updated Final Safety Analysis Report Supplement,” Section A1, “Summary 

Descriptions of Aging Management Programs,” and Appendix B, “Aging Management 

Programs,” Section B1.3, “Quality Assurance Program and Administrative Controls,” of the LRA, 

the applicant described the elements of “corrective action,” “confirmation process,” and 

“administrative controls” that are applied to the AMPs for both safety-related and 

nonsafety-related components. Appendix A, Section A1 and Appendix B, Section B1.3 of the 

LRA state that the QA Program implements the requirements of 10 CFR Part 50, Appendix B, 

“Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants,” and is 

consistent with the SRP-LR. 

3.0.4.2 Staff Evaluation 

Under 10 CFR 54.21(a)(3), an 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 
Aging Management Review Results 

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maintained consistent with the CLB for the period of extended operation. The SRP-LR, branch 

technical position (BTP) RLSB-1, “Aging Management Review - Generic,” describes 

ten attributes of an acceptable AMP. Three of these ten attributes are associated with the QA 

activities of corrective action (element 7), confirmation process (element 8), and administrative 

controls (element 9). Table A.1-1, “Elements of an Aging Management Program for License 

Renewal,” of BTP RLSB-1 provides the following description of these quality attributes: 

Corrective Actions – Corrective actions, including root cause determination and 

prevention of recurrence, should be timely. 

Confirmation Process – Confirmation process should ensure that preventive 

actions are adequate and that appropriate corrective actions have been 

completed and are effective. 

Administrative Controls – Administrative controls should provide a formal 

review and approval process. 

The SRP-LR, BTP IQMB-1, “Quality Assurance for Aging Management Programs,” states that 

those aspects of the AMP that affect quality of safety-related SSCs are subject to the QA 

requirements of 10 CFR Part 50, Appendix B. Additionally, for nonsafety-related SCs subject to 

an AMR, the applicant's existing 10 CFR Part 50, Appendix B, QA Program may address the 

elements of corrective action, confirmation process, and administrative control. BTP IQMB-1 

provides the following guidance with regard to the QA attributes of AMPs: 

Safety-related structures and components are subject to 10 CFR Part 50 

Appendix B requirements, which are adequate to address all quality-related 

aspects of an aging management program consistent with the CLB of the facility 

for the period of extended operation. 

The SRP-LR, Appendix A.2, BTP IQMB-1 states that for nonsafety-related SCs that are subject 

to an AMR for license renewal, an applicant has an option to expand the scope of its Appendix 

B to 10 CFR Part 50 Program to include these SCs to address corrective action, confirmation 

process, and administrative control for aging management during the period of extended 

operation. In this case, the applicant should document such a commitment in the UFSAR 

supplement, in accordance with 10 CFR 54.21(d). 

The staff reviewed the applicant’s AMPs described in Appendix A and Appendix B of the LRA as 

well as the associated implementing procedures. The purpose of this review was to ensure that 

the QA attributes (e.g., corrective action, confirmation process, and administrative controls) 

were consistent with the staff’s guidance described in BTP IQMB-1. The staff also audited 

these attributes and reported the results in an Audit Report dated April 7, 2010. Based on the 

staff’s evaluation and audit, the descriptions of the AMPs and their associated quality attributes 

provided in Appendix A, Section A1, and Appendix B, Section B1.3, of the LRA are consistent 

with the staff’s position regarding QA for aging management. 

3.0.4.3 Conclusion 

On the basis of the NRC staff’s evaluation, the descriptions and applicability of the PVNGS 

AMPs and their associated quality attributes provided in Appendix A, Section A1, and 

Appendix B, Section B1.3, of the LRA, were determined to be consistent with the staff’s position 

regarding QA for aging management. The staff concludes that the QA attributes (corrective 

action, confirmation process, and administrative control) of the applicant's AMPs are consistent 

with 10 CFR 54.21(a)(3). 
Aging Management Review Results 

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

This section of the SER documents the staff’s review of the applicant’s AMR results for the RV, 

internals, and RCS components and component groups for the following: 

 RV and internals 

 Reactor coolant system pressurizer 

 Steam generators 

3.1.1 Summary of Technical Information in the Application 

LRA Section 3.1 provides AMR results for the RV, RV internals, and RCS components and 

component groups. LRA Table 3.1.1, “Summary of Aging Management Evaluations in Chapter 

IV of NUREG-1801 [GALL Report] for the RV, Internals, and Reactor Coolant System,” is a 

summary comparison of the applicant’s AMRs with those evaluated in the GALL Report for the 

RV, RV internals, and RCS components and component groups. 

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry 

operating experience in the determination of AERMs. The plant-specific evaluation included 

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 provided sufficient information 

to demonstrate that it will adequately manage the effects of aging for the RV, RV internals, and 

RCS components, within the scope of license renewal and subject to an AMR, 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 reviewed AMRs to ensure the applicant’s claim that certain 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 identified the appropriate GALL Report AMRs. SER Section 3.0.3 documents 

the staff’s evaluations of the AMPs, and SER Section 3.1.2.1 documents the staff’s evaluations. 

The staff also reviewed AMRs 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 SRP-LR Section 3.1.2.2 acceptance criteria. SER Section 3.1.2.2 documents the 

staff’s evaluations. 

The staff also conducted a technical review of the remaining AMRs not consistent with, or not 

addressed in, the GALL Report. The technical review evaluated whether the applicant noted all 

plausible aging effects and whether the aging effects listed were appropriate for the 

material-environment combinations specified. SER Section 3.1.2.3 documents the staff’s 

evaluations. 

For SSCs that the applicant claimed were not applicable or required no aging management, the 

staff reviewed the AMR items and the plant’s operating experience to verify the applicant’s 

claims. 

Table 3.1-1 summarizes the staff’s evaluation of components, aging effects or mechanisms, and 

AMPs listed in LRA Section 3.1 and addressed in the GALL Report. 
Aging Management Review Results 

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

Reactor Coolant System Components in the GALL Report 

Component Group 

(GALL Report Item No.) 

Aging 

Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Steel pressure vessel 

support skirt and 

attachment welds 

(3.1.1-1) 

Cumulative 

fatigue damage 

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c) 

Yes Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.1.2.1.1. 

Steel; stainless steel; steel 

with nickel-alloy or 

stainless steel cladding; 

nickel-alloy RV 

components: flanges; 

nozzles; penetrations; safe 

ends; thermal sleeves; 

vessel shells, heads and 

welds 

(3.1.1-2) 

Cumulative 

fatigue damage 

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c) and 

environmental effects 

are to be addressed 

for Class 1 

components 

Yes Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.1.2.1.1. 

Steel; stainless steel; steel 

with nickel-alloy or 

stainless steel cladding; 

nickel-alloy RCPB piping, 

piping components, and 

piping elements exposed 

to reactor coolant 

(3.1.1-3) 

Cumulative 

fatigue damage 

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c) and 

environmental effects 

are to be addressed 

for Class 1 

components 

Yes Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.1.2.1.1. 

Steel pump and valve 

closure bolting 

(3.1.1-4) 

Cumulative 

fatigue damage 

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c) 

check Code limits for 

allowable cycles (less 

than 7000 cycles) of 

thermal stress range 

Yes Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.1.2.1.1. 

Stainless steel and nickelalloy RV internals 

components 

(3.1.1-5) 

Cumulative 

fatigue damage 

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c) 

Yes TLAA Consistent 

with GALL 

Report. See 

SER Section 

3.1.2.2.1. 

Nickel-alloy tubes and 

sleeves in a reactor 

coolant and secondary 

feedwater/steam 

environment 

(3.1.1-6) 

Cumulative 

fatigue damage 

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c) 

Yes TLAA Consistent 

with GALL 

Report. See 

SER Section 

3.1.2.2.1. 
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Component Group 

(GALL Report Item No.) 

Aging 

Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Steel and stainless steel 

RCPB closure bolting, 

head closure studs, 

support skirts and 

attachment welds, 

pressurizer relief tank 

components, SG 

components, piping and 

components external 

surfaces and bolting 

(3.1.1-7) 

Cumulative 

fatigue damage 

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c) 

Yes TLAA Consistent 

with GALL 

Report. See 

SER Section 

3.1.2.2.1. 

Steel; stainless steel; and 

nickel-alloy RCPB piping, 

piping components, piping 

elements; flanges; nozzles 

and safe ends; pressurizer 

vessel shell heads and 

welds; heater sheaths and 

sleeves; penetrations; and 

thermal sleeves 

(3.1.1-8) 

Cumulative 

fatigue damage 

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c) and 

environmental effects 

are to be addressed 

for Class 1 

components 

Yes TLAA Consistent 

with GALL 

Report. See 

SER Section 

3.1.2.2.1. 

Steel; stainless steel; steel 

with nickel-alloy or 

stainless steel cladding; 

nickel-alloy RV 

components: flanges; 

nozzles; penetrations; 

pressure housings; safe 

ends; thermal sleeves; 

vessel shells, heads and 

welds 

(3.1.1-9) 

Cumulative 

fatigue damage 

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c) and 

environmental effects 

are to be addressed 

for Class 1 

components 

Yes TLAA Consistent 

with GALL 

Report. See 

SER Section 

3.1.2.2.1. 

Steel; stainless steel; steel 

with nickel-alloy or 

stainless steel cladding; 

nickel-alloy SG 

components (flanges; 

penetrations; nozzles; safe 

ends, lower heads and 

welds) 

(3.1.1-10) 

Cumulative 

fatigue damage 

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c) and 

environmental effects 

are to be addressed 

for Class 1 

components 

Yes TLAA Consistent 

with GALL 

Report. See 

SER Section 

3.1.2.2.1. 

Steel top head enclosure 

(without cladding) top head 

nozzles (vent, top head 

spray or reactor core 

isolation cooling, and 

spare) exposed to reactor 

coolant 

(3.1.1-11) 

Loss of material 

due to general, 

pitting and 

crevice corrosion 

Water Chemistry and 

One-Time Inspection 

Yes Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.1.2.2.2(1). 
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Component Group 

(GALL Report Item No.) 

Aging 

Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Steel SG shell assembly 

exposed to secondary 

feedwater and steam 

(3.1.1-12) 

Loss of material 

due to general, 

pitting and 

crevice corrosion 

Water Chemistry and 

One-Time Inspection 

Yes Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.1.2.2.2(1). 

Steel and stainless steel 

isolation condenser 

components exposed to 

reactor coolant 

(3.1.1-13) 

Loss of material 

due to general 

(steel only), 

pitting and 

crevice corrosion 

Water Chemistry and 

One-Time Inspection 

Yes Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.1.2.2.2(2). 

Stainless steel, nickel 

alloy, and steel with nickelalloy or stainless steel 

cladding RV flanges, 

nozzles, penetrations, safe 

ends, vessel shells, heads 

and welds 

(3.1.1-14) 

Loss of material 

due to pitting and 

crevice corrosion 

Water Chemistry and 

One-Time Inspection 

Yes Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.1.2.2.2(3). 

Stainless steel; steel with 

nickel-alloy or stainless 

steel cladding; and nickelalloy RCPB components 

exposed to reactor coolant 

(3.1.1-15) 

Loss of material 

due to pitting and 

crevice corrosion 

Water Chemistry and 

One-Time Inspection 

Yes Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.1.2.2.2(3). 

Steel SG upper and lower 

shell and transition cone 

exposed to secondary 

feedwater and steam 

(3.1.1-16) 

Loss of material 

due to general, 

pitting and 

crevice corrosion 

ISI (IWB, IWC, and 

IWD), and Water 

Chemistry and, for 

Westinghouse 

Model 44 and 

51 S/G, if general 

and pitting corrosion 

of the shell is known 

to exist, additional 

inspection 

procedures are to be 

developed. 

Yes ISI and Water 

Chemistry 

Consistent 

with GALL 

Report. See 

SER Section 

3.1.2.2.2(4). 

Steel (with or without 

stainless steel cladding) 

RV beltline shell, nozzles, 

and welds 

(3.1.1-17) 

Loss of fracture 

toughness due to 

neutron 

irradiation 

embrittlement 

TLAA, evaluated in 

accordance with 

10 CFR 50, 

Appendix G, and 

RG 1.99. The 

applicant may 

choose to 

demonstrate that the 

materials of the 

nozzles are not 

controlling for the 

TLAA evaluations. 

Yes TLAA Consistent 

with GALL 

Report. See 

SER Section 

3.1.2.2.3(1). 
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Component Group 

(GALL Report Item No.) 

Aging 

Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Steel (with or without 

stainless steel cladding) 

RV beltline shell, nozzles, 

and welds; safety injection 

nozzles 

(3.1.1-18) 

Loss of fracture 

toughness due to 

neutron 

irradiation 

embrittlement 

RV Surveillance Yes RV

Surveillance 

Consistent 

with GALL 

Report. See 

SER Section 

3.1.2.2.3(2). 

Stainless steel and nickelalloy top head enclosure 

vessel flange leak 

detection line 

(3.1.1-19) 

Cracking due to 

SCC and IGSS 

A plant-specific AMP

is to be evaluated. 

Yes Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.1.2.2.4(1). 

Stainless steel isolation 

condenser components 

exposed to reactor coolant 

(3.1.1-20) 

Cracking due to 

SCC and IGSCC 

ISI (IWB, IWC, and 

IWD), Water 

Chemistry, and plantspecific verification 

program 

Yes Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.1.2.2.4(2). 

RV shell fabricated of 

SA508-Cl 2 forgings clad 

with stainless steel using a 

high-heat-input welding 

process 

(3.1.1-21) 

Crack growth due 

to cyclic loading 

TLAA Yes Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.1.2.2.5. 

Stainless steel and nickelalloy RV internals 

components exposed to 

reactor coolant and 

neutron flux 

(3.1.1-22) 

Loss of fracture 

toughness due to 

neutron 

irradiation 

embrittlement, 

void swelling 

FSAR supplement 

commitment to 

(1) participate in 

industry RV internals 

aging programs 

(2) implement 

applicable results (3) 

submit for NRC 

approval > 24 months 

before the extended 

period an RV 

internals inspection 

plan based on 

industry 

recommendation. 

No, but 

licensee 

commitment 

needs to be 

confirmed 

Commitment 

and RCS 

Consistent 

with GALL 

Report. See 

SER Section 

3.1.2.2.6. 

Stainless steel RV closure 

head flange leak detection 

line and bottom-mounted 

instrument guide tubes 

(3.1.1-23) 

Cracking due to 

SCC 

A plant-specific AMP

is to be evaluated. 

Yes ISI and Water 

Chemistry 

Consistent 

with GALL 

Report. See 

SER Section 

3.1.2.2.7(1). 

Class 1 CASS piping, 

piping components, and 

piping elements exposed 

to reactor coolant 

(3.1.1-24) 

Cracking due to 

SCC 

Water Chemistry and, 

for CASS 

components that do 

not meet the 

NUREG-0313 

guidelines, a plantspecific AMP 

Yes Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.1.2.2.7(2). 
Aging Management Review Results 

 3-141 

Component Group 

(GALL Report Item No.) 

Aging 

Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Stainless steel jet pump 

sensing line 

(3.1.1-25) 

Cracking due to 

cyclic loading 

A plant-specific AMP 

is to be evaluated. 

Yes Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.1.2.2.8(1). 

Steel and stainless steel 

isolation condenser 

components exposed to 

reactor coolant 

(3.1.1-26) 

Cracking due to 

cyclic loading 

ISI (IWB, IWC, and 

IWD) and plantspecific verification 

program 

Yes Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.1.2.2.8(2). 

Stainless steel and nickelalloy RV internals screws, 

bolts, tie rods, and holddown springs 

(3.1.1-27) 

Loss of preload 

due to stress 

relaxation 

FSAR supplement 

commitment to 

(1) participate in 

industry RV internals 

aging programs 

(2) implement 

applicable results (3) 

submit for NRC 

approval > 24 months 

before the extended 

period an RV 

internals inspection 

plan based on 

industry 

recommendation. 

No, but 

licensee 

commitment 

needs to be 

confirmed 

Commitment 

and Reactor 

Coolant 

Supplement 

Consistent 

with GALL 

Report. See 

SER Section 

3.1.2.2.9. 

Steel SG feedwater 

impingement plate and 

support exposed to 

secondary feedwater 

(3.1.1-28) 

Loss of material 

due to erosion 

A plant-specific AMP

is to be evaluated. 

Yes Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.1.2.2.10. 

Stainless steel steam 

dryers exposed to reactor 

coolant 

(3.1.1-29) 

Cracking due to 

flow-induced 

vibration 

A plant-specific AMP 

is to be evaluated. 

Yes Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.1.2.2.11. 
Aging Management Review Results 

 3-142 

Component Group 

(GALL Report Item No.) 

Aging 

Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Stainless steel RV 

internals components 

(e.g., upper internals 

assembly, rod cluster 

control assembly, guide 

tube assemblies, 

baffle/former assembly, 

lower internal assembly, 

shroud assemblies, 

plenum cover and plenum 

cylinder, upper grid 

assembly, control rod 

guide tube assembly, core 

support shield assembly, 

core barrel assembly, 

lower grid assembly, flow 

distributor assembly, 

thermal shield, 

instrumentation support 

structures) 

(3.1.1-30) 

Cracking due to 

SCC, IASCC 

Water Chemistry and 

FSAR supplement 

commitment to 

(1) participate in 

industry RV internals 

aging programs 

(2) implement 

applicable results 

(3) submit for NRC 

approval > 24 months 

before the extended 

period an RV 

internals inspection 

plan based on 

industry 

recommendation. 

No, but 

licensee 

commitment 

needs to be 

confirmed 

Water 

Chemistry, 

Commitment, 

and Reactor 

Coolant 

Supplement 

Consistent 

with GALL 

Report. See 

SER Section 

3.1.2.2.12. 

Nickel alloy and steel with 

nickel-alloy cladding 

piping, piping component, 

piping elements, 

penetrations, nozzles, safe 

ends, and welds (other 

than RV head); pressurizer 

heater sheaths, sleeves, 

diaphragm plate, manways 

and flanges; core support 

pads/core guide lugs 

(3.1.1-31) 

Cracking due to 

PWSCC 

ISI (IWB, IWC, and 

IWD) and Water 

Chemistry and FSAR 

supplement 

commitment to 

implement applicable 

plant commitments to 

(1) NRC Orders, 

Bulletins, and 

Generic Letters 

associated with 

nickel- alloys and 

(2) staff-accepted 

industry guidelines. 

No, but 

licensee 

commitment 

needs to be 

confirmed 

ISI, Water 

Chemistry, 

and NickelAlloy Aging 

Management 

Programs, 

Commitment, 

and Reactor 

Coolant 

Supplement 

Consistent 

with GALL 

Report. See 

SER Section 

3.1.2.2.13. 

Steel SG feedwater inlet 

ring and supports 

(3.1.1-32) 

Wall thinning due 

to FAC 

A plant-specific AMP

is to be evaluated. 

Yes SG Tubing 

Integrity and 

Water 

Chemistry 

Consistent 

with GALL 

Report. See 

SER Section 

3.1.2.2.14. 

Stainless steel and nickelalloy RV internals 

components 

(3.1.1-33) 

Changes in 

dimensions due 

to void swelling 

FSAR supplement 

commitment to 

(1) participate in 

industry RV internals 

aging programs 

(2) implement 

applicable results 

(3) submit for NRC 

approval > 24 months 

before the extended 

period an RV 

internals inspection 

plan based on 

industry 

recommendation. 

No, but 

licensee 

commitment 

needs to be 

confirmed 

Commitment 

and Reactor 

Coolant 

Supplement 

Consistent 

with GALL 

Report. See 

SER Section 

3.1.2.2.15. 
Aging Management Review Results 

 3-143 

Component Group 

(GALL Report Item No.) 

Aging 

Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Stainless steel and nickelalloy reactor control rod 

drive head penetration 

pressure housings 

(3.1.1-34) 

Cracking due to 

SCC and 

PWSCC 

ISI (IWB, IWC, and 

IWD) and Water 

Chemistry and for 

nickel alloy, comply 

with applicable NRC 

Orders and provide a 

commitment in the 

FSAR supplement to 

implement applicable 

(1) Bulletins and 

Generic Letters and 

(2) staff-accepted 

industry guidelines. 

No, but 

licensee 

commitment 

needs to be 

confirmed 

ISI, Water 

Chemistry, 

and NickelAlloy 

Management 

Programs, 

Commitment, 

and Reactor 

Coolant 

Supplement 

Consistent 

with GALL 

Report. See 

SER Section 

3.1.2.2.16(1). 

Steel with stainless steel 

or nickel-alloy cladding 

primary side components; 

SG upper and lower 

heads, tubesheets and 

tube-to-tube sheet welds 

(3.1.1-35) 

Cracking due to 

SCC and 

PWSCC 

ISI (IWB, IWC, and 

IWD) and Water 

Chemistry and for 

nickel alloy, comply 

with applicable NRC 

Orders and provide a 

commitment in the 

FSAR supplement to 

implement applicable 

(1) Bulletins and 

Generic Letters and 

(2) staff-accepted 

industry guidelines. 

No, but 

licensee 

commitment 

needs to be 

confirmed 

Plant-specific 

Commitment 

. See SER 

Section 

3.1.2.2.16(1). 

Nickel-alloy, stainless steel 

pressurizer spray head 

(3.1.1-36) 

Cracking due to 

SCC and 

PWSCC 

Water Chemistry and 

One-Time Inspection 

and, for nickel-alloy 

welded spray heads, 

comply with 

applicable NRC 

Orders and provide a 

commitment in the 

FSAR supplement to 

implement applicable 

(1) Bulletins and 

Generic Letters and 

(2) staff-accepted 

industry guidelines. 

No, but 

licensee 

commitment 

needs to be 

confirmed 

Water 

Chemistry, 

One-Time 

Inspection, 

and Reactor 

Coolant 

Supplement 

Consistent 

with GALL 

Report. See 

SER Section 

3.1.2.2.16(2). 

Stainless steel and nickelalloy RV internals 

components (e.g., upper 

internals assembly, rod 

cluster control assembly, 

guide tube assemblies, 

lower internal assembly, 

CEA shroud assemblies, 

core shroud assembly, 

core support shield 

assembly, core barrel 

assembly, lower grid 

assembly, flow distributor 

assembly) 

(3.1.1-37) 

Cracking due to 

SCC, PWSCC, 

IASCC 

Water Chemistry and 

FSAR supplement 

commitment to 

(1) participate in 

industry RV internals 

aging programs 

(2) implement 

applicable results 

(3) submit for NRC 

approval > 24 months 

before the extended 

period an RV 

internals inspection 

plan based on 

industry 

recommendation. 

No, but 

licensee 

commitment 

needs to be 

confirmed 

Water 

Chemistry, 

Commitment, 

and Reactor 

Coolant 

Supplement 

Consistent 

with GALL 

Report. See 

SER Section 

3.1.2.2.17. 
Aging Management Review Results 

 3-144 

Component Group 

(GALL Report Item No.) 

Aging 

Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Steel (with or without 

stainless steel cladding) 

control rod drive return line 

nozzles exposed to reactor 

coolant 

(3.1.1-38) 

Cracking due to 

cyclic loading 

BWR Control Rod 

Drive Return Line 

Nozzle 

No Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.1.2.1.1. 

Steel (with or without 

stainless steel cladding) 

feedwater nozzles 

exposed to reactor coolant 

(3.1.1-39) 

Cracking due to 

cyclic loading 

BWR Feedwater 

Nozzle 

No Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.1.2.1.1. 

Stainless steel and nickelalloy penetrations for 

control rod drive stub 

tubes instrumentation, jet 

pump instrumentation, 

standby liquid control, flux 

monitor, and drain line 

exposed to reactor coolant 

(3.1.1-40) 

Cracking due to 

SCC, IGSCC, 

cyclic loading 

BWR Penetrations 

and Water Chemistry 

No Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.1.2.1.1. 

Stainless steel and nickelalloy piping, piping 

components, and piping 

elements greater than or 

equal to 4 NPS; nozzle 

safe ends and associated 

welds 

(3.1.1-41) 

Cracking due to 

SCC and IGSCC 

BWR SCC and Water 

Chemistry 

No Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.1.2.1.1. 

Stainless steel and nickelalloy vessel shell 

attachment welds exposed 

to reactor coolant 

(3.1.1-42) 

Cracking due to 

SCC and IGSCC 

BWR Vessel ID 

Attachment Welds 

and Water Chemistry 

No Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.1.2.1.1. 

Stainless steel fuel 

supports and control rod 

drive assemblies control 

rod drive housing exposed 

to reactor coolant 

(3.1.1-43) 

Cracking due to 

SCC and IGSCC 

BWR Vessel 

Internals and Water 

Chemistry 

No Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.1.2.1.1. 

Stainless steel and nickelalloy core shroud, core 

plate, core plate bolts, 

support structure, top 

guide, core spray lines, 

spargers, jet pump 

assemblies, control rod 

drive housing, nuclear 

instrumentation guide 

tubes 

(3.1.1-44) 

Cracking due to 

SCC, IGSCC, 

IASCC 

BWR Vessel 

Internals and Water 

Chemistry 

No Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.1.2.1.1. 
Aging Management Review Results 

 3-145 

Component Group 

(GALL Report Item No.) 

Aging 

Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Steel piping, piping 

components, and piping 

elements exposed to 

reactor coolant 

(3.1.1-45) 

Wall thinning due 

to FAC 

FAC No Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.1.2.1.1. 

Nickel-alloy core shroud 

and core plate access hole 

cover (mechanical covers) 

(3.1.1-46) 

Cracking due to 

SCC, IGSCC, 

IASCC 

ISI (IWB, IWC, and 

IWD), and Water 

Chemistry 

No Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.1.2.1.1. 

Stainless steel and nickelalloy RV internals exposed 

to reactor coolant 

(3.1.1-47) 

Loss of material 

due to pitting and 

crevice corrosion 

ISI (IWB, IWC, and 

IWD), and Water 

Chemistry 

No Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.1.2.1.1. 

Steel and stainless steel 

Class 1 piping, fittings and 

branch connections 

< NPS 4 exposed to 

reactor coolant 

(3.1.1-48) 

Cracking due to 

SCC, IGSCC (for 

stainless steel 

only), and thermal 

and mechanical 

loading 

ISI (IWB, IWC, and 

IWD), Water 

chemistry, and OneTime Inspection of 

ASME Code Class 1 

Small-bore Piping 

No Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.1.2.1.1. 

Nickel-alloy core shroud 

and core plate access hole 

cover (welded covers) 

(3.1.1-49) 

Cracking due to 

SCC, IGSCC, 

IASCC 

ISI (IWB, IWC, and 

IWD), Water 

Chemistry, and, for 

BWRs with a crevice 

in the access hole 

covers, augmented 

inspection using UT 

or other 

demonstrated 

acceptable inspection 

of the access hole 

cover welds 

No Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.1.2.1.1. 

High-strength low alloy 

steel top head closure 

studs and nuts exposed to 

air with reactor coolant 

leakage 

(3.1.1-50) 

Cracking due to 

SCC and IGSCC 

Reactor Head 

Closure Studs 

No Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.1.2.1.1. 

CASS jet pump assembly 

castings; orificed fuel 

support 

(3.1.1-51) 

Loss of fracture 

toughness due to 

thermal aging and 

neutron 

irradiation 

embrittlement 

Thermal Aging and 

Neutron Irradiation 

Embrittlement of 

CASS 

No Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.1.2.1.1. 
Aging Management Review Results 

 3-146 

Component Group 

(GALL Report Item No.) 

Aging 

Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Steel and stainless steel 

reactor coolant pressure 

boundary (RCPB) pump 

and valve closure bolting, 

manway and holding 

bolting, flange bolting, and 

closure bolting in highpressure and hightemperature systems 

(3.1.1-52) 

Cracking due to 

SCC, loss of 

material due to 

wear, loss of 

preload due to 

thermal effects, 

gasket creep, and 

self-loosening 

Bolting Integrity No Bolting 

Integrity 

Consistent 

with GALL 

Report. 

Steel piping, piping 

components, and piping 

elements exposed to 

closed cycle cooling water 

(3.1.1-53) 

Loss of material 

due to general, 

pitting and 

crevice corrosion 

Closed-Cycle Cooling 

Water System 

No Closed-Cycle 

Cooling Water 

System 

Consistent 

with GALL 

Report. 

Copper alloy piping, piping 

components, and piping 

elements exposed to 

closed cycle cooling water 

(3.1.1-54) 

Loss of material 

due to pitting, 

crevice, and 

galvanic 

corrosion 

Closed-Cycle Cooling 

Water System 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.1.2.1.1. 

CASS Class 1 pump 

casings, and valve bodies 

and bonnets exposed to 

reactor coolant > 250°C 

(> 482°F) 

(3.1.1-55) 

Loss of fracture 

toughness due to 

thermal aging 

embrittlement 

ISI (IWB, IWC, and 

IWD). Thermal aging 

susceptibility 

screening is not 

necessary, ISI 

requirements are 

sufficient for 

managing these 

aging effects. ASME 

Code Case N-481 

also provides an 

alternative for pump 

casings. 

No ISI Consistent 

with GALL 

Report. 

Copper alloy > 15% Zn 

piping, piping components, 

and piping elements 

exposed to closed cycle 

cooling water 

(3.1.1-56) 

Loss of material 

due to selective 

leaching 

Selective Leaching of 

Materials 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.1.2.1.1. 

Cast austenitic stainless 

steel Class 1 piping, piping 

component, and piping 

elements and control rod 

drive pressure housings 

exposed to reactor coolant 

> 250°C (> 482°F) 

(3.1.1-57) 

Loss of fracture 

toughness due to 

thermal aging 

embrittlement 

Thermal Aging 

Embrittlement of 

CASS 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.1.2.1.1. 

Steel RCPB external 

surfaces exposed to air 

with borated water leakage 

(3.1.1-58) 

Loss of material 

due to boric acid 

corrosion 

Boric Acid Corrosion No Boric Acid 

Corrosion 

Consistent 

with GALL 

Report. 
Aging Management Review Results 

 3-147 

Component Group 

(GALL Report Item No.) 

Aging 

Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Steel SG steam nozzle 

and safe end, feedwater 

nozzle and safe end, AFW 

nozzles and safe ends 

exposed to secondary 

feedwater/steam 

(3.1.1-59) 

Wall thinning due 

to FAC 

FAC No FAC Consistent 

with GALL 

Report. 

Stainless steel flux thimble 

tubes (with or without 

chrome plating) 

(3.1.1-60) 

Loss of material 

due to wear 

Flux Thimble Tube 

Inspection 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.1.2.1.1. 

Stainless steel, steel 

pressurizer integral 

support exposed to air with 

metal temperature up to 

288°C (550°F) 

(3.1.1-61) 

Cracking due to 

cyclic loading 

ISI (IWB, IWC, and 

IWD) 

No ISI Consistent 

with GALL 

Report. 

Stainless steel, steel with 

stainless steel cladding 

RCS cold leg, hot leg, 

surge line, and spray line 

piping and fittings exposed 

to reactor coolant 

(3.1.1-62) 

Cracking due to 

cyclic loading 

ISI (IWB, IWC, and 

IWD) 

No ISI Consistent 

with GALL 

Report. See 

SER Section 

3.1.2.1.3. 

Steel RV flange, stainless 

steel and nickel-alloy RV 

internals exposed to 

reactor coolant (e.g., upper 

and lower internals 

assembly, CEA shroud 

assembly, core support 

barrel, upper grid 

assembly, core support 

shield assembly, lower grid 

assembly) 

(3.1.1-63) 

Loss of material 

due to wear 

ISI (IWB, IWC, and 

IWD) 

No ISI Consistent 

with GALL 

Report. 

Stainless steel and steel 

with stainless steel or 

nickel-alloy cladding 

pressurizer components 

(3.1.1-64) 

Cracking due to 

SCC, PWSCC 

ISI (IWB, IWC, and 

IWD) and Water 

Chemistry 

No ISI and Water 

Chemistry 

Consistent 

with GALL 

Report. 
Aging Management Review Results 

 3-148 

Component Group 

(GALL Report Item No.) 

Aging 

Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Nickel-alloy RV upper 

head and control rod drive 

penetration nozzles, 

instrument tubes, head 

vent pipe (top head), and 

welds 

(3.1.1-65) 

Cracking due to 

PWSCC 

ISI (IWB, IWC, and 

IWD) and Water 

Chemistry and 

Nickel-Alloy 

Penetration Nozzles 

Welded to the Upper 

RV Closure Heads of 

PWRs 

No ISI, Water 

Chemistry, 

and NickelAlloy 

Penetration 

Nozzles 

Welded to the 

Upper RV 

Closure 

Heads of 

Pressurized 

Water 

Consistent

with GALL 

Report. 

Steel SG secondary 

manways and handholds 

(cover only) exposed to air 

with leaking secondaryside water or steam 

(3.1.1-66) 

Loss of material 

due to erosion 

ISI (IWB, IWC, and 

IWD) for Class 2 

components 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.1.2.1.1. 

Steel with stainless steel 

or nickel-alloy cladding; or 

stainless steel pressurizer 

components exposed to 

reactor coolant 

(3.1.1-67) 

Cracking due to 

cyclic loading 

ISI (IWB, IWC, and 

IWD), and Water 

Chemistry 

No ISI and Water 

Chemistry 

Consistent 

with GALL 

Report. 

Stainless steel, steel with 

stainless steel cladding 

Class 1 piping, fittings, 

pump casings, valve 

bodies, nozzles, safe 

ends, manways, flanges, 

CRD housing; pressurizer 

heater sheaths, sleeves, 

diaphragm plate; 

pressurizer relief tank 

components, RCS cold 

leg, hot leg, surge line, and 

spray line piping and 

fittings 

(3.1.1-68) 

Cracking due to 

SCC 

ISI (IWB, IWC, and 

IWD), and Water 

Chemistry 

No ISI and Water 

Chemistry 

Consistent 

with GALL 

Report. 

Stainless steel, nickel-alloy

safety injection nozzles, 

safe ends, and associated 

welds and buttering 

exposed to reactor coolant 

(3.1.1-69) 

Cracking due to 

SCC, PWSCC 

ISI (IWB, IWC, and 

IWD), and Water 

Chemistry 

No ISI and Water 

Chemistry 

Consistent 

with GALL 

Report. 

Stainless steel; steel with 

stainless steel cladding 

Class 1 piping, fittings and 

branch connections 

< NPS 4 exposed to 

reactor coolant 

(3.1.1-70) 

Cracking due to 

SCC, thermal and 

mechanical 

loading 

ISI (IWB, IWC, and 

IWD), Water 

chemistry, and OneTime Inspection of 

ASME Code Class 1 

Small-bore Piping 

No ISI, Water 

Chemistry and 

One Time 

Inspection of 

ASME Code 

Class 1 SmallBore Piping 

Consistent 

with GALL 

Report. 
Aging Management Review Results 

 3-149 

Component Group 

(GALL Report Item No.) 

Aging 

Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

High-strength low alloy 

steel closure head stud 

assembly exposed to air 

with reactor coolant 

leakage 

(3.1.1-71) 

Cracking due to 

SCC; loss of 

material due to 

wear 

Reactor Head 

Closure Studs 

No Reactor Head 

Closure Studs 

Consistent 

with GALL 

Report. 

Nickel-alloy SG tubes and 

sleeves exposed to 

secondary 

feedwater/steam 

(3.1.1-72) 

Cracking due to 

outerdiameter SCC 

and intergranular 

attack, loss of 

material due to 

fretting and wear 

SG Tube Integrity 

and Water Chemistry 

No SG Integrity 

and Water 

Chemistry 

Consistent 

with GALL 

Report. 

Nickel-alloy SG tubes, 

repair sleeves, and tube 

plugs exposed to reactor 

coolant 

(3.1.1-73) 

Cracking due to 

PWSCC 

SG Tube Integrity 

and Water Chemistry 

No SG Integrity 

and Water 

Chemistry 

Consistent 

with GALL 

Report. 

Chrome plated steel, 

stainless steel, nickel-alloy 

SG anti-vibration bars 

exposed to secondary 

feedwater/steam 

(3.1.1-74) 

Cracking due to 

SCC, loss of 

material due to 

crevice corrosion 

and fretting 

SG Tube Integrity 

and Water Chemistry 

No SG Integrity 

and Water 

Chemistry 

Consistent 

with GALL 

Report. 

Nickel-alloy once-through 

SG tubes exposed to 

secondary 

feedwater/steam 

(3.1.1-75) 

Denting due to 

corrosion of 

carbon steel tube 

support plate 

SG Tube Integrity 

and Water Chemistry 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.1.2.1.1. 

Steel SG tube support 

plate, tube bundle wrapper 

exposed to secondary 

feedwater/steam 

(3.1.1-76) 

Loss of material 

due to erosion, 

general, pitting, 

and crevice 

corrosion, 

ligament cracking 

due to corrosion 

SG Tube Integrity 

and Water Chemistry 

No SG Integrity 

and Water 

Chemistry 

Consistent 

with GALL 

Report. 

Nickel-alloy SG tubes and 

sleeves exposed to 

phosphate chemistry in 

secondary 

feedwater/steam 

(3.1.1-77) 

Loss of material 

due to wastage 

and pitting 

corrosion 

SG Tube Integrity 

and Water Chemistry 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.1.2.1.1. 

Steel SG tube support 

lattice bars exposed to 

secondary 

feedwater/steam 

(3.1.1-78) 

Wall thinning due 

to FAC 

SG Tube Integrity 

and Water Chemistry 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.1.2.1.1. 
Aging Management Review Results 

 3-150 

Component Group 

(GALL Report Item No.) 

Aging 

Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Nickel-alloy SG tubes 

exposed to secondary 

feedwater/steam 

(3.1.1-79) 

Denting due to 

corrosion of steel 

tube support plate

SG Tube Integrity; 

Water Chemistry and, 

for plants that could 

experience denting at 

the upper support 

plates, evaluate 

potential for rapidly 

propagating cracks 

and then develop and 

take corrective 

actions consistent 

with NRC 

Bulletin 88-02. 

No SG Tube 

Integrity and 

Water 

Chemistry 

Not applicable 

to PVNGS. 

See SER 

Section 

3.1.2.1.1. 

CASS RV internals 

(e.g., upper internals 

assembly, lower internal 

assembly, CEA shroud 

assemblies, control rod 

guide tube assembly, core 

support shield assembly, 

lower grid assembly) 

(3.1.1-80) 

Loss of fracture 

toughness due to 

thermal aging and 

neutron 

irradiation 

embrittlement 

Thermal Aging and 

Neutron Irradiation 

Embrittlement of 

CASS 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.1.2.1.1. 

Nickel-alloy or nickel-alloy 

clad SG divider plate 

exposed to reactor coolant 

(3.1.1-81) 

Cracking due to 

PWSCC 

Water Chemistry No Water 

Chemistry and 

Plant-specific 

Commitment 

Consistent 

with GALL 

Report. See 

SER Section 

3.1.2.1.2. 

Stainless steel SG primary 

side divider plate exposed 

to reactor coolant 

(3.1.1-82) 

Cracking due to 

SCC 

Water Chemistry No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.1.2.1.1. 

Stainless steel; steel with 

nickel-alloy or stainless 

steel cladding; and nickelalloy RV internals and 

RCPB components 

exposed to reactor coolant 

(3.1.1-83) 

Loss of material 

due to pitting and 

crevice corrosion 

Water Chemistry No Water 

Chemistry 

Consistent 

with GALL 

Report. 

Nickel-alloy SG 

components such as, 

secondary side nozzles 

(vent, drain, and 

instrumentation) exposed 

to secondary 

feedwater/steam 

(3.1.1-84) 

Cracking due to 

SCC 

Water Chemistry and 

One-Time Inspection 

or ISI (IWB, IWC, and 

IWD). 

No Water 

Chemistry, 

One-Time 

Inspection, or 

ISI 

Consistent 

with GALL 

Report. 

Nickel-alloy piping, piping 

components, and piping 

elements exposed to airindoor uncontrolled 

(external) 

(3.1.1-85) 

None None NA None Consistent 

with GALL 

Report. 
Aging Management Review Results 

 3-151 

Component Group 

(GALL Report Item No.) 

Aging 

Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Stainless steel piping, 

piping components, and 

piping elements exposed 

to air-indoor uncontrolled 

(External); air with borated 

water leakage; concrete; 

gas 

(3.1.1-86) 

None None NA None Consistent 

with GALL 

Report. 

Steel piping, piping 

components, and piping 

elements in concrete 

(3.1.1-87) 

None None NA Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.1.2.1.1. 

 

The staff’s review of the RV, RV internals, and RCS component groups followed one of three 

categories. One category, documented in SER Section 3.1.2.1, reviewed AMR results for 

components that the applicant indicated are consistent with the GALL Report and require no 

further evaluation. Another category, documented in SER Section 3.1.2.2, reviewed AMR 

results for components that the applicant indicated are consistent with the GALL Report and for 

which further evaluation is recommended. The third category, documented in SER Section 

3.1.2.3, reviewed AMR results for components that the applicant indicated are not consistent 

with, or not addressed in, the GALL Report. SER Section 3.0.3 documents the staff’s review of 

AMPs credited to manage or monitor aging effects of the RV, RV internals, and RCS. 

3.1.2.1 Aging Management Review Results Consistent with the Generic Aging Lessons 

Learned Report 

LRA Section 3.1.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the RV, RV internals, and RCS components: 

 ASME Section XI ISI, Subsections IWB, IWC, and IWD 

 Bolting Integrity 

 Boric Acid Corrosion 

 Closed-Cycle Cooling Water System 

 External Surfaces Monitoring Program 

 Flow-Accelerated Corrosion 

 Lubricating Oil Analysis 

 Nickel-Alloy Aging Management Program 

 Nickel-Alloy Penetration Nozzles Welded to the Upper RV Closure Heads of PWRs 

 One-Time Inspection 

 One-Time Inspection of ASME Code Class 1 Small-Bore Piping 

 Reactor Coolant System Supplement 

 Reactor Head Closure Studs 
Aging Management Review Results 

 3-152 

 RV Surveillance 

 Steam Generator Tube Integrity 

 Water Chemistry 

LRA Tables 3.1.2-1– 3.1.2-4 summarize AMRs for the RV, RV internals, and RCS components 

and indicate AMRs claimed to be consistent with the GALL Report. 

The staff reviewed the LRA to confirm that the applicant: (a) provided a brief description of the 

system, components, materials, and environments; (b) stated that the applicable aging effects 

were reviewed and evaluated in the GALL Report; and (c) identified those aging effects for the 

RV, RV internals, and RCS components that are subject to an AMR. Based on its audit and 

review, the staff determines that, for AMRs not requiring further evaluation, as identified in LRA 

Table 3.1.1, the applicant’s references to the GALL Report are acceptable and no further staff 

review is required. 

3.1.2.1.1 Aging Management Review Results Identified as Not Applicable 

LRA Table 3.1.1, item 3.1.1.01 states that this is a CE vessel with no support skirt, so the 

applicable GALL Report line was not used. The staff noted that according to the SRP-LR and 

the GALL Report, this item is applicable to boiling water reactors (BWRs) only. Because the 

PVNGS is a PWR design, this item is not applicable. 

LRA Table 3.1.1, items 3.1.1.02–3.1.1.04 and 3.1.1.38–3.1.1.51 state that these items are 

applicable only to BWRs. The staff verified that these items do not apply because the units are 

a PWR design. Based on this determination, the staff finds that the applicant has provided an 

acceptable basis for concluding AMR items 3.1.1.02–3.1.1.04 and 3.1.1.38–3.1.1.51 are not 

applicable. 

LRA Table 3.1.1, item 3.1.1.54 addresses copper alloy piping, piping components, and piping 

elements exposed to closed-cycle cooling water subject to loss of material due to pitting, 

crevice, and galvanic corrosion for this component group. The applicant stated that this item is 

not applicable because it has no in-scope copper alloy piping, piping components, or piping 

elements exposed to closed-cycle cooling water in the RCS, so the applicable GALL Report line 

was not used. The staff reviewed LRA Sections 2.3.1 and 3.1 and confirmed that the 

applicant’s LRA does not have any AMR results for the RCS that include copper alloy piping, 

piping components, and piping elements exposed to closed-cycle cooling water. The staff 

reviewed the applicant’s UFSAR and confirmed that no in-scope copper alloy piping, piping 

components, and piping elements exposed to closed-cycle cooling water are present in these 

systems and, therefore, finds the applicant’s determination acceptable. 

LRA Table 3.1.1, item 3.1.1.56 addresses copper alloy greater than 15-percent zinc piping, 

piping components, and piping elements exposed to closed-cycle cooling water subject to loss 

of material due to selective leaching for this component group. The applicant stated that this 

item is not applicable because it has no in-scope copper alloy greater than 15-percent zinc 

components exposed to closed-cycle cooling water in the RCS, so the applicable GALL Report 

item was not used. The staff reviewed LRA Sections 2.3.1 and 3.1 and confirmed that the 

applicant’s LRA does not have any AMR results for the RCS that include copper alloy greater 

than 15-percent zinc piping, piping components, and piping elements exposed to closed-cycle 

cooling water. The staff reviewed the applicant’s UFSAR and confirmed that no in-scope 

copper alloy greater than 15-percent zinc piping, piping components, and piping elements 

exposed to closed-cycle cooling water are present in these systems and, therefore, finds the 

applicant’s determination acceptable. 

LRA Table 3.1.1, item 3.1.1.57 addresses cast austenitic stainless steel (CASS) Class 1 piping, 

piping component, and piping elements and control rod drive pressure housings exposed to 
Aging Management Review Results 

 3-153 

reactor coolant greater than 250 degrees C (greater than 482 degrees F) subject to loss of 

fracture toughness due to thermal aging embrittlement for this component group. The applicant 

stated that this item is not applicable because the RCS does not have CASS piping, piping 

components, or piping elements exposed to reactor coolant, and the control rod drive pressure 

housings are made of stainless steel and nickel alloy, so that the applicable GALL Report items 

were not used. The staff reviewed LRA Sections 2.3.1 and 3.1 and confirmed that the 

applicant’s LRA does not have any AMR results for the RCS that include CASS Class 1 piping, 

piping component, and piping elements and control rod drive pressure housings exposed to 

reactor coolant greater than 250 degrees C (greater than 482 degrees F). The staff reviewed 

the applicant’s UFSAR and confirmed that no in-scope CASS Class 1 piping, piping component, 

and piping elements and control rod drive pressure housings exposed to reactor coolant greater 

than 250 degrees C (greater than 482 degrees F) are present in these systems; therefore, it 

finds the applicant’s determination acceptable. The staff also confirmed that the applicant 

addresses the control rod drive pressure housings, which are fabricated of stainless steel and 

nickel alloy, in LRA Table 3.1.1, item 3.1.1.34, for cracking due to SCC and PWSCC and 

stainless steel; steel with nickel-alloy or stainless steel cladding; and nickel-alloy RV internals 

and RCPB components exposed to reactor coolant in LRA Table 3.1.1, item 3.1.1.83, for loss of 

material due to pitting and crevice corrosion. SER Section 3.1.2.2.16(1) documents the staff’s 

review and its evaluation of LRA Table 3.1.1, item 3.1.1.34. The staff noted that for the control 

rod drive pressure housings that referenced LRA Table 3.1.1, item 3.1.1.83, the applicant 

proposes to manage loss of material due to pitting and crevice corrosion with its Water 

Chemistry Program, which is consistent with the recommendations of the GALL Report and is, 

therefore, acceptable. 

LRA Table 3.1.1, item 3.1.1.60 addresses stainless steel flux thimble tubes (with or without 

chrome plating) exposed to reactor coolant subject to loss of material due to wear for this 

component group. The applicant stated that this item is not applicable because it has a 

CE-design RV and internals, and the subject GALL Report line is applicable to 

Westinghouse-design RV and internals only. The staff reviewed the applicant’s UFSAR and 

confirmed that its RV is a CE design. The staff reviewed the GALL Report and confirmed that 

LRA Table 3.1.1, item 3.1.1.60 and GALL Report, AMR item IV.B2-13 is specifically applicable 

to Westinghouse-design RV and internals and, therefore, finds the applicant’s determination 

acceptable. 

LRA Table 3.1.1, item 3.1.1.66 addresses steel SG secondary manways and handholds (cover 

only) exposed to air with leaking secondary-side water or steam subject to loss of material due 

to erosion for this component group. The applicant stated that this item is not applicable 

because it has recirculating SGs, so the applicable GALL Report line was not used. The staff 

noted that LRA Table 3.1.1, item 3.1.1.66 references GALL Report, item IV.D2-5, which is 

applicable to once-through SGs. The staff reviewed the applicant’s UFSAR Section 5.1, 

Figures 5.4-8A and 5D-1B and confirmed that the applicant’s SGs are recirculating-type SGs, 

therefore, finds the applicant’s determination acceptable. 

LRA Table 3.1.1, item 3.1.1.75 addresses nickel-alloy once-through SG tubes exposed to 

secondary feedwater and steam subject to denting due to corrosion of carbon steel tube support 

plate for this component group. The applicant stated that this item is not applicable because it 

has recirculating SGs, so the applicable GALL Report line was not used. The staff noted that 

LRA Table 3.1.1, item 3.1.1.75 references GALL Report, AMR item IV.D2-13, which is 

applicable to once-through SGs. The staff reviewed the applicant’s UFSAR Section 5.1, 

Figures 5.4-8A and 5D-1B and confirmed that the applicant’s SGs are recirculating-type SGs, 

therefore, finds the applicant’s determination acceptable. 

LRA Table 3.1.1, item 3.1.1.77 addresses nickel-alloy SG tubes and sleeves exposed to 

phosphate chemistry in secondary feedwater and steam subject to loss of material due to 
Aging Management Review Results 

 3-154 

wastage and pitting corrosion for this component group. The applicant stated that this item is 

not applicable because it does not operate on phosphate chemistry in secondary feedwater or 

steam with the replacement SGs, so the applicable GALL Report line was not used. The staff 

noted that the applicant’s Water Chemistry Program is consistent with the guidelines provided in 

EPRI TR-1008224, "PWR Secondary Water Chemistry Guidelines," Revision 6. The staff noted 

that this is a later revision to EPRI TR-102134 and that its use is acceptable because it is 

consistent with GALL AMP XI.M2. The staff reviewed EPRI TR-1008224 and UFSAR 

Section 10.3.5 and confirmed that the applicant does not operate on phosphate chemistry in the 

secondary side, therefore, finds the applicant’s determination acceptable. 

LRA Table 3.1.1, item 3.1.1.78 addresses steel SG tube support lattice bars exposed to 

secondary feedwater and steam subject to wall thinning due to FAC for this component group. 

The applicant stated that this item is not applicable because its SGs do not contain steel tube 

support lattice bars, so the applicable GALL Report line was not used. The staff noted that in 

LRA Section B2.1.8, the applicant stated its design is a two-loop CE plant with two identical 

replacement SGs designed by Asea Brown Boveri-CE, considered a modified CE System 80 

design. The applicant further stated that it replaced the original SGs in Units 1, 2, and 3 during 

the fall of 2005, 2003, and 2007, respectively. The applicant stated that the tube support 

system is fabricated of Type 409 ferritic stainless steel. The staff’s safety evaluation of the 

applicant’s amendment for replacement SGs and uprated power operations for Unit 2 is 

documented in a letter dated September 23, 2003 (ADAMS No. ML032720538) and for Units 1 

and 3 is documented in a letter dated November 16, 2005 (ADAMS No. ML053130275). The 

staff confirmed that the applicant’s tube support system is fabricated of Type 409 ferritic 

stainless steel in the above mentioned safety evaluations; therefore, it finds the applicant’s 

determination acceptable. 

LRA Table 3.1.1, item 3.1.1.79 addresses denting due to corrosion of carbon steel tube support 

plate in nickel-alloy SG tubes exposed to secondary feedwater and steam. The applicant stated 

that this item is not applicable. 

However, the staff noted that LRA Table 3.1.2-4 did not include the item addressing the GALL 

Report, item IV.D1-17, corresponding to ligament cracking due to corrosion in steel tube support 

plates, whereas in this same table, the applicant addressed the GALL Report, item IV.D1-19, 

corresponding to SG tube denting due to corrosion of carbon steel tube support plates. The 

staff also noted that in LRA Section B2.1.8, the applicant stated that the tube support system is 

similar to the original design and, like the original design, is fabricated from 409 ferritic stainless 

steel. The staff noted that this type of stainless steel is not susceptible to the general corrosion 

that affects carbon steel tube support plates, which induces SG tube denting because of the 

buildup and expansion of corrosion products in the annulus between the SG tubes external 

surface and the tube support plates. The staff requested the applicant to explain this apparent 

inconsistency in a conference call on October 28, 2010. 

In a letter dated November 10, 2010, the applicant revised LRA Section 3.1.2.1.4, Tables 3.1.1 

and 3.1.2-4, and Sections A1.8 and B2.1.8, to correct the aging effect for SG tubes to be 

consistent with the GALL Report line IV.D1-19. The applicant stated that LRA Table 3.1.1, item 

3.1.1.79 is not applicable because its SGs do not have a carbon steel tube support system. The 

applicant further stated that its steam generator tube support system is fabricated from 409 

ferritic stainless steel, so denting is not an applicable aging effect. Accordingly, the applicant 

deleted the denting aging effect from LRA Section 3.1.2.1.4, and the LRA AMR item 

corresponding to the GALL Report line IV.D1-19 from LRA Table 3.1.2.1-4, and revised the 

description of the Steam Generator Tube Integrity Program in LRA Section B2.1.8 and UFSAR 

Supplement A1.8. 

The staff reviewed the applicant’s clarification about SG tube support plates and the subsequent 

LRA modifications, and finds it acceptable that the applicant concluded that LRA Table 3.1.1, 
Aging Management Review Results 

 3-155 

item 3.1.1.79 is not applicable, consistent with GALL Report item IV.D1-19, because the 

applicant’s SGs contain 409 ferritic stainless steel SG tube support plates, which does not 

induce SG tube denting, as described above. 

LRA Table 3.1.1, item 3.3.1.80 addresses loss of fracture toughness due to thermal aging and 

neutron irradiation embrittlement in CASS RV internals (e.g., upper internals assembly, lower 

internal assembly, control element assembly (CEA) shroud assemblies, control rod guide tube 

assembly, core support shield assembly, and lower grid assembly). The applicant stated that 

LRA Table 3.1.1, item 3.3.1.80 is not applicable and that its RV internals do not contain CASS, 

so it did not use the applicable GALL Report items. The staff reviewed the applicant’s UFSAR 

and noted that UFSAR Section 4.5.2.1, “Reactor Internals Materials,” Subsection B, states that 

the upper guide structure (UGS) assembly contains “ASTM A-351, Grade CF8,” which is a 

CASS material. The staff noted that there is a discrepancy between the applicant’s UFSAR and 

LRA as to whether the RV internals contain CASS. By letter dated March 2, 2010, the staff 

issued RAI 3.1.1-1 requesting the applicant to resolve the discrepancy between UFSAR 

Section 4.5.2.1, which states the UGS assembly contains CASS components and LRA 

Table 3.1.1, which states the RV internals do not contain CASS components. The staff also 

asked that the applicant provide the necessary revisions to the LRA if the RV internals contain 

CASS components. 

In its response, dated April 1, 2010, the applicant stated that UFSAR Section 4.5.2.1 

incorporated sections from the CE Standard Safety Analysis Report and reflected initial design 

information that was not incorporated into the as-built design. The applicant stated that it 

performed a review of the as-built Reactor Internals Bill of Materials and confirmed that no 

CASS material was used in the UGS assembly. The applicant clarified that it used the Reactor 

Internals Bill of Materials during the license renewal aging evaluations. The applicant further 

stated that it is tracking the discrepancy within its corrective actions program. 

Based on its review, the staff finds the applicant’s response to RAI 3.1.1-1, and the applicant’s 

claim that the RV internals does not contain CASS, acceptable because the applicant confirmed 

in the as-built Reactor Internals Bill of Materials that CASS was not used in the UGS assembly, 

and the applicant entered this discrepancy in the UFSAR into its corrective actions program. 

The staff’s concern described in RAI 3.1.1-1 is resolved. 

LRA Table 3.1.1, item 3.1.1.82 addresses stainless steel SG primary side divider plate exposed 

to reactor coolant subject to cracking due to SCC for this component group. The applicant 

stated that this item is not applicable because its SG primary channel dividers are made of 

nickel alloy, so it did not use the applicable GALL Report line. The staff reviewed UFSAR 

Section 5.2 and confirmed the applicant’s divider plate is fabricated of nickel alloy. The staff 

also noted that, in LRA Table 3.1.2-4, the applicant stated that its SG primary head divider plate 

is fabricated of nickel alloy and is managed for cracking with its Water Chemistry Program, 

consistent with the recommendations of the GALL Report AMR, item IV.D1-6. Based on its 

review as described above, the staff finds the applicant’s determination acceptable. 

LRA Table 3.1.1, item 3.1.1.87 addresses steel piping, piping components, and piping elements 

in concrete. The GALL Report states that there is no AERM. The applicant stated that this item 

is not applicable because its RV, internals, and RCS have no in-scope steel piping, piping 

components, or piping elements embedded in concrete, so it did not use the applicable GALL 

Report line. The staff reviewed LRA Sections 2.3.1 and 3.1 and confirmed that the applicant’s 

LRA does not have any AMR results for the RCS that include steel piping, piping components, 

and piping elements in concrete. The staff reviewed the applicant’s UFSAR and confirmed that 

no in-scope steel piping, piping components, and piping elements in concrete are present in the 

systems; therefore, it finds the applicant’s determination acceptable. 
Aging Management Review Results 

 3-156 

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 aging effects. Based on its review, the staff concludes that the 

AMR results, which the applicant claimed to be consistent with the GALL Report, are indeed 

consistent. 

3.1.2.1.2 Cracking Due to Primary Water Stress Corrosion Cracking 

LRA Table 3.1.1, item 3.1.1-81 addresses cracking due to PWSCC for nickel-alloy or 

nickel-alloy clad SG divider plates exposed to reactor coolant. The LRA states that the SG 

primary channel dividers are made of nickel alloy. The applicant credited its Water Chemistry 

Program to manage the cracking due to PWSCC, consistent with the GALL Report. 

The staff noted that, from international operating experience in SGs, extensive cracking due to 

PWSCC has been identified in SG divider plates fabricated from Alloy 600, even with proper 

primary water chemistry. The staff noted that cracks have been detected very close to the 

tubesheet and with depths of almost a quarter of the divider plate thickness. Therefore, the staff 

noted that the Primary Water Chemistry Program alone may not be effective in managing the 

aging effect of cracking due to PWSCC in SG divider plate assembly components fabricated 

from Alloy 600 and its associated weld metals. 

The staff noted that these SG divider plate cracks could impact adjacent items such as the 

tubesheet and the channel head if they propagate to the boundary with these items. The staff 

further noted that for the tubesheet, PWSCC cracks in the divider plate assembly components 

fabricated from Alloy 600 and its associated weld metals could propagate to the tubesheet 

cladding with possible consequences to the integrity of the tube-to-tubesheet welds. 

Furthermore, for the channel head, the PWSCC cracks in the divider plate could propagate to 

the SG triple point and potentially affect the pressure boundary of the SG channel head. 

UFSAR, Section 1.2.3.3, states that a vertical divider plate separates the inlet and outlet 

plenums in the lower head of the SGs, but the staff did not find information about the materials 

of the divider plate assembly nor its junction to the lower head and to the tubesheet in the 

UFSAR or the LRA. 

The staff held conference calls on October 22, November 3 and 19, 2010, with the applicant to 

discuss and clarify the staff's concerns. The staff asked the applicant to clarify how the SG 

divider plate is assembled to the lower head and to the tubesheet and to identify the materials of 

the divider plate and associated welds. During the discussion, the staff also asked the applicant 

to provide information on how it will manage the possible effects of PWSCC on these welds if 

the compositions of the SG divider plate divider bar welds (all areas) are susceptible to 

PWSCC, thereby potentially compromising the RCS pressure boundary. The staff also 

requested information concerning the inspection method since it should be capable of detecting 

PWSCC. The applicant agreed to provide information on its management of this aging effect in 

these components. 

By letter dated November 23, 2010, the applicant described how the SG primary side divider 

plates are attached to the channel head, stay cylinder, and tubesheet via a tongue-in-groove 

connection. The applicant stated that all components are manufactured from Alloy 690 material, 

and the SG specifications show the divider plate bars welded to the channel head, stay cylinder, 

and tubesheet cladding using Alloy 52, 82, 152, and 182 filler materials, but not all detailed 

information of SG specifications, especially about filler materials, was included in the UFSAR. 

The applicant further stated that there is no routine inspection requirement for the divider bar 

welds because (a) these welds do not provide a reactor coolant system pressure boundary; 

(b) these welds do not provide structural support to the SGs; (c) the divider plate “floats” in the 

tongue and groove, and the force on the divider plate transferred to the divider plate bar welds 

is the relatively low differential pressure between the SG inlet and outlet (compared with RCS 
Aging Management Review Results 

 3-157 

pressure); and (d) a crack in the divider bar weld due to PWSCC would need to propagate from 

the divider bar weld through the channel head cladding to get to the base metal. 

However, in response to the staff’s concern regarding potential failure of the RCS pressure 

boundary due to possible PWSCC of SG divider plate bar welds, the applicant committed 

(Commitment No. 61) to one of the following: 

1. Perform an inspection of each PVNGS SG to assess the condition of the 

divider plate bar welds. The examination technique(s) will be capable of 

detecting PWSCC in the divider plate bar welds. 

2. Perform an analytical evaluation of the SG divider plate bar welds in order to 

establish a technical basis which concludes that the SG RCS pressure boundary 

is adequately maintained with the presence of SG divider plate bar weld 

cracking. 

3. If results of industry and NRC studies and operating experience document 

that potential failure of the SG RCS pressure boundary due to PWSCC cracking 

of SG divider plate bar welds is not a credible concern, the commitment will be 

revised to reflect that conclusion. 

Moreover, the applicant stated that if the first option were selected, it would be completed for 

each SG in each unit during a SG tube eddy-current inspection outage. This inspection would 

be conducted between 20 and 25 calendar years of SG operation, according to the dates of 

SGs replacement for Units 1, 2 and 3 (fall of 2005, 2003, and 2007 respectively). The applicant 

clarified that for Units 1 and 3, this would approximately correspond to the first 5 years after 

entering the period of extended operation (i.e., for Unit 1, between September 1, 2025, and 

December 1, 2030; and for Unit 3, between September 1, 2027, and December 1, 2032). For 

Unit 2, this would correspond to a time period between 3 years prior to and 2 years after 

entering the period of extended operation (i.e., September 1, 2023, and December 1, 2028). 

The applicant further stated that if the second or third option were selected, it would be 

completed prior to September 1, 2023, when the first replaced SGs (Unit 2) would reach 

20 years of operation. 

By letter dated February 25, 2011, the applicant corrected information in the 

November 23, 2010, letter by stating that it determined, from reviewing each unit’s SG as-built 

documentation, that the divider plate bars in Unit 2 were made of Alloy 600 as a result of a 

change report issued during fabrication. The applicant further stated that it had reviewed the 

as-built documentation to determine if there were other differences in SG primary-side materials 

between the units, and no other differences were found. However, the applicant also identified 

that the divider bar set screws and the divider patch plate cap screws in the SGs are made of 

materials other than Alloy 690. 

In order to address potential PWSCC of the Unit 2 Alloy 600 SG divider plate bars, in its letter 

dated February 25, 2011, the applicant expanded Commitment No. 61 to include the Unit 2 SG 

divider plate bars within the scope of the committed analyses. The applicant also committed to 

include the exposed portions of the Unit 2 SG divider plate bars within the scope of the 

committed inspections. The applicant stated that inspection or analysis of the screws is not 

being included in this commitment because any possible PWSCC that may occur in the screws 

would not be expected to propagate to the reactor coolant pressure boundary material. 

By letter dated March 17, 2011, the applicant modified Commitment No. 61 from inspecting the 

“exposed portions” of the divider plate bars to inspecting “accessible surfaces” of the divider 

plate bars in order to clarify the inspection of the divider plate bars in the Unit 2 SGs. This 

change was intended to use standard industry terminology to refer to surfaces that can be 

accessed for examination. The applicant also clarified its letter dated February 25, 2011, stating 
Aging Management Review Results 

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that the installed divider patch plate cap screws in all SGs were made of Alloy 690. The 

applicant also clarified that the divider bar set screws were made of stainless steel and, since 

they are under a compressive stress, are not susceptible to PWSCC. Further, the set screws 

are welded in place. 

In the final version of Commitment No. 61, the applicant commits to perform one of the following 

options: 

1. Perform an inspection of each Palo Verde Unit 1, 2, and 3 steam generator to 

assess the condition of the divider plate bar welds in all units, and the accessible 

surfaces of the divider plate bars in Unit 2. The examination technique(s) will be 

capable of detecting PWSCC in the divider plate bar welds in all units, and in the 

accessible surfaces of the divider plate bars in Unit 2. 

2. Perform an analytical evaluation of the steam generator divider plate bar 

welds in all units, and the divider plate bars in Unit 2, in order to establish a 

technical basis which concludes that the SG reactor coolant system pressure 

boundary is adequately maintained with the presence of steam generator divider 

plate bar weld cracking. 

3. If results of industry and NRC studies and operating experience document 

that potential failure of the SG reactor coolant system pressure boundary due to 

PWSCC cracking of SG divider plate bar welds and the divider plate bars in Unit 

2 is not a credible concern, this commitment will be revised to reflect that 

conclusion. 

Based on its review, the staff finds the applicant‘s options and associated revised Commitment 

No. 61 acceptable because the applicant identified which parts of the divider plates were made 

of Alloy 600 or associated weld materials. Further, the applicant will assess the condition of the 

divider plate bar welds in all units and the accessible surfaces of the divider plate bars in Unit 2 

using an appropriate option. If the applicant inspects each SG divider plate bar weld, it will do 

so with appropriate examination technique and in a time period consistent with the detection of 

potential PWSCC. The staff finds that the timing of this inspection for each unit is acceptable 

because the proposed implementation schedule allows operation of the SGs for between 20 

and 25 years, and it is unlikely that significant detrimental PWSCC cracking will have initiated 

before this time. The staff also noted that the applicant could alternatively perform an 

evaluation of the welds or use the results of NRC and industry operating experience to rule out 

this aging effect. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 10 CFR 

54.21(a)(3). 

3.1.2.2 Aging Management Review Results Consistent with the Generic Aging Lessons 

Learned Report for Which Further Evaluation Is Recommended 

In LRA Section 3.1.2.2, the applicant further evaluates aging management, as recommended by 

the GALL Report, for the RV, internals, and RCS components and provides 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 fracture toughness due to neutron irradiation embrittlement 

 cracking due to SCC and IGSCC 

 crack growth due to cyclic loading 
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 loss of fracture toughness due to neutron irradiation embrittlement and void swelling 

 cracking due to SCC 

 cracking due to cyclic loading 

 loss of preload due to stress relaxation 

 loss of material due to erosion 

 cracking due to flow-induced vibration 

 cracking due to SCC and IASCC 

 cracking due to PWSCC 

 wall thinning due to FAC 

 changes in dimensions due to void swelling 

 cracking due to SCC and PWSCC 

 cracking due to SCC, PWSCC, and IASCC 

 QA for aging management of nonsafety-related components 

For component groups evaluated in the GALL Report, for which the applicant claimed 

consistency with the report and for which the report recommends further evaluation, the staff 

reviewed the applicant’s evaluation to determine if it adequately addressed the issues further 

evaluated. In addition, the staff reviewed the applicant’s further evaluations against the criteria 

contained in SRP-LR Section 3.1.2.2. The staff’s review of the applicant’s further evaluation 

follows. 

3.1.2.2.1 Cumulative Fatigue Damage 

In LRA Section 3.1.2.2.1, the applicant stated that the analysis of cumulative fatigue damage in 

the RPV pressure boundary piping, valves, and other components; and of those SG secondary 

side components with a fatigue analysis are TLAAs as defined in 10 CFR 54.3 and are 

evaluated in accordance with 10 CFR 54.21(c)(1). 

The applicant identified that the following AMRs in LRA Table 3.1.1 are applicable and stated 

the following for each applicable item: 

Item 3.1.1.5, PVNGS RV internals are designed to ASME III Subsection NG, 

some with a fatigue analysis, LRA Section 4.3.3 describes the evaluation of 

these TLAAs 

Item 3.1.1.06, Cumulative fatigue damage of SG tubes is not a TLAA as defined 

in 10 CFR 54.3, see LRA Section 4.3.2.5. 

Item 3.1.1.07, Reactor coolant pressure boundary closure bolting (reactor 

pressure vessel [RPV] head studs, pump, valve, and pressurizer and SG 

manway and port bolting) and pressurizer vessel support skirts and attachment 

welds are designed to ASME III Class 1, with a fatigue analysis. Both the SG 

primary and secondary shells, integral supports, nozzles, and bolting have a 

Class 1 fatigue analysis; the pressurizer relief tank is not an ASME III Class 1 

component, nor is it designed to other fatigue or cyclic design rules, and 

therefore has no fatigue TLAA 

 LRA Section 4.3.2.1 describes the evaluation of these TLAAs for RV 

closure bolting and welded attachments 

 LRA Section 4.3.2.3 describes the evaluation of these TLAAs for the 

reactor coolant pump, its closure bolting, and its integral supports 

 LRA Section 4.3.2.4 describes the evaluation of these TLAAs for 

pressurizer closure bolting, its support skirt, and welded attachments 
Aging Management Review Results 

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 LRA Section 4.3.2.5 describes the evaluation of these TLAAs for SG 

primary and secondary-side pressure boundaries, feedwater nozzles, 

closure bolting and welded attachments 

 LRA Section 4.3.2.6 describes the evaluation of these TLAAs for Class 1 

valves, including their bolting 

 LRA Section 4.3.2.7 describes the evaluation of these TLAAs for piping 

and piping components 

Item 3.1.1.08, Reactor coolant pressure boundary piping and the pressurizer are 

designed to ASME III Class 1, with fatigue analyses 

 LRA Section 4.3.2.7 describes the evaluation of these TLAAs for piping 

and other piping components. 

Item 3.1.1.09, The RV pressure boundary is designed to ASME III Class 1, with 

fatigue analyses 

 LRA Section 4.3.2.1 describes the evaluation of these TLAAs for the RV, 

including the shell, heads, flanges, penetrations, welds, nozzles, and safe 

end butters 

 LRA Section 4.3.2.2 describes the evaluation of these TLAAs for the 

control element assembly (CEA) housings 

Item 3.1.1.10, The SG primary and secondary pressure boundaries are designed 

respectively to ASME III Class 1 and 2, but both the SG primary and secondary 

shells and nozzles have a Class 1 fatigue analysis. 

 LRA Section 4.3.2.5 describes the evaluation of these TLAAs for SG 

primary and secondary-side pressure boundaries including the heads, 

feedwater nozzles, other nozzles and safe end butters, and closures 

The staff reviewed LRA Section 3.1.2.2.1 against the criteria in SRP-LR Section 3.1.2.2.1, which 

states that fatigue is a TLAA, as defined in 10 CFR 54.3. Under 10 CFR 54.21(c)(1), TLAAs 

must be evaluated. Section 4.3, “Metal Fatigue Analysis,” of the SRP-LR addresses this TLAA 

separately. The staff finds that the applicant’s AMR results are consistent with the 

recommendations of the GALL Report and SRP-LR except for those areas identified below. 

The staff noted that for LRA Table 3.1.1, item 3.1.1.6, for the recirculating SG tubes, the GALL 

Report identifies cumulative fatigue damage as an applicable aging effect for Class 1 tubes and 

sleeves and recommends that an applicant’s metal fatigue analysis be used to manage this 

aging effect during the period of extended operation. The staff verified that in LRA 

Table 3.1.2-4, the applicant credited its SG Tubing Integrity Program, as the condition 

monitoring program to manage cracking in these tubes. 

However, the staff noted that the applicant performed a CUF calculation of the replacement SG 

tubes because the tubes are ASME Code Class 1 components, designed to ASME Section III. 

The staff noted that the various degradation mechanisms reference SG tube cracking, induced 

either by SCC or by any other mechanisms. Cracking induced by these mechanisms has no 

relationship to cracking induced by high-cycle or low-cycle fatigue mechanisms. The staff noted 

that cracking of SG tubes has been induced by IGSCC, PWSCC, outer-diameter SCC, or 

intergranular attack mechanisms and that the ISI of the tubes required by plant TS have largely 

been implemented to detect cracking induced by these mechanisms. The staff also noted that 

these mechanisms do not have a relationship to the use of CUF calculations to qualify the tubes 

for cracking by fatigue and do not constitute a valid basis for concluding the CUF values do not 

qualify the tubes for fatigue-induced cracking during their design life. It is not clear to the staff 
Aging Management Review Results 

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why the CUF value for the SG tubes is zero. By letter dated July 21, 2010, the staff issued 

RAI 4.3-13, requesting that the applicant justify its basis for concluding that the CUF calculation 

for the SG tubes does not need to be identified as a TLAA. Additionally, the staff asked the 

applicant to provide its basis for the CUF value of zero for the SG tubes. The staff previously 

identified this as part of Open Item 4.3-1. 

The staff noted that in LRA Section 3.1.2.2.1, the applicant stated that the pressurizer support 

skirts and attachment welds were designed to ASME Section III requirements and had received 

an applicable ASME Section III CUF analysis. The staff determined that neither LRA 

Table 3.1.2-2 nor LRA Table 3.1.2-3 include any applicable items for management of cumulative 

fatigue damage in the pressurizer support skirts and attachment welds. By letter July 21, 2010, 

the staff issued RAI 4.3-13, asking that the applicant justify its basis for omitting applicable AMR 

items for cumulative fatigue damage of the pressurizer support skirts and pressurizer 

attachment weld components. The staff previously identified this as part of Open Item 4.3-1. 

In its response dated August 12, 2010, the applicant stated that the SG tube CUF value was 

taken from the applicable design report for each unit. The applicant further clarified that the 

zero value for the SG tube CUF, included in the design reports, is based on the cyclic stress 

range being below the endurance limit. The staff noted that the applicant amended LRA 

Section 4.3.2.5 to identify the SG tube fatigue analysis as a TLAA and to disposition the TLAA 

for the SG tubes in accordance with 10 CFR 54.21(c)(1)(i). The staff also noted that the 

applicant amended LRA Table 3.1.2-4 to include the associated AMR item consistent with GALL 

Report AMR, item IV.D1-21. Furthermore, the staff noted that LRA Table 3.1.2-3 was amended 

to include the associated AMR line items for the pressurizer support skirt and attachment weld 

consistent with GALL Report AMR, item IV.C2-10. The staff confirmed that these additional 

AMR items are consistent with the associated GALL Report AMR items. The staff’s evaluation 

of the pressurizer support skirt and SG tubes is documented in SER Sections 4.3.2.4.2 and 

4.3.2.5.2, respectively. 

Based on its review of the amended LRA Tables 3.1.2-3 and 3.1.2-4, the staff finds the 

applicant’s response to RAI 4.3-13, parts 1 and 2, and the additions of the AMR line items, 

acceptable because they are consistent with the associated GALL Report AMR items for the 

pressurizer support skirt and attachment weld and the SG tubes. The staff’s concern described 

in RAI 4.3-13 is resolved, and this portion of Open Item 4.3-1 is closed. 

Based on its review, the staff concludes that the applicant’s proposal to manage cumulative 

fatigue damage in ASME Code Class 1 components meets the SRP-LR Section 3.1.2.2.1 

criteria. For those items that apply to LRA Section 3.1.2.2.1, the staff determines that the LRA 

is consistent with the GALL Report. The staff also finds that the applicant has demonstrated 

that it will adequately manage the effects of aging so that the intended function(s) will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). SER Section 4.3 documents the staff’s review of the applicant’s evaluation 

of the TLAA for these components. 

3.1.2.2.2 Loss of Material Due to General, Pitting, and Crevice Corrosion 

The staff reviewed LRA Section 3.1.2.2.2 against the following criteria in SRP-LR 

Section 3.1.2.2.2: 

 LRA Section 3.1.2.2.2 states that PVNGS has a recirculating SG, not a once-through 

SG, so the applicant did not use the applicable GALL Report row. 

 SRP-LR Section 3.1.2.2.2 states that loss of material due to general, pitting, and crevice 

corrosion may occur in the steel PWR SG shell assembly exposed to secondary 

feedwater and steam. Loss of material due to general, pitting, and crevice corrosion 

also may occur in the steel top head enclosure (without cladding) top head nozzles 
Aging Management Review Results 

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(vent, top head spray or reactor core isolation cooling, and spare) exposed to reactor 

coolant. The existing program controls reactor water chemistry to mitigate corrosion. 

However, control of water chemistry does not preclude loss of material due to pitting and 

crevice corrosion at locations with stagnant flow conditions; therefore, the effectiveness 

of water chemistry control programs should be verified to ensure that corrosion does not 

occur. The GALL Report recommends further evaluation of programs to verify the 

effectiveness of water chemistry control programs. A one-time inspection of selected 

components at susceptible locations is an acceptable method to determine whether an 

aging effect is occurring or is slowly progressing such that the component’s intended 

functions will be maintained during the period of extended operation. 

 SRP-LR Section 3.1.2.2.2.1 does not define the scope of applicability for this aging 

effect. GALL Report Table IV.D1, “Steam Generator (Recirculating),” which is applicable 

to the PVNGS units shows that only GALL Report AMR, item IV.D1-12 for SG upper and 

lower shell and transition cone is applicable for this aging effect. SER 

Section 3.1.2.2.2(4) discusses this separately. GALL Report Table IV.D2, “Steam 

Generator (Once-Through),” which is not applicable to PVNGS, Units 1, 2, and 3, 

however, shows the identical component name—SG shell assembly—as GALL Report 

AMR, item IV.D2-8 for this aging effect. Since SER Section 3.1.2.2.2(4) separately 

discusses the only item for this aging effect in GALL Report Table IV.D1, and GALL 

Report Table IV.D2 is for a different type of SG, the staff agrees that this issue is not 

applicable to PVNGS units. 

 LRA Table 3.1.1, item 3.1.1.11, which also addresses loss of material due to general, 

pitting, and crevice corrosion in the steel top head enclosure (without cladding) top head 

nozzles (vent, top head spray or reactor core isolation cooling, and spare) exposed to 

reactor coolant is identified as not applicable because it applies to BWRs only. Because 

the PVNGS units are PWRs, the staff finds that this component and aging effect 

combination does not apply to PVNGS. 

 LRA Section 3.1.2.2.2.2 states that the aging effect is not applicable to PVNGS; it is 

applicable to BWRs only. SRP-LR Section 3.1.2.2.2, item 2 states that loss of material 

due to pitting and crevice corrosion may occur in stainless steel BWR isolation 

condenser components exposed to reactor coolant. Loss of material due to general, 

pitting, and crevice corrosion may occur in steel BWR isolation condenser components. 

The staff finds that SRP-LR Section 3.1.2.2.2, item 2 is not applicable to PVNGS 

because the PVNGS units are PWRs, and the staff guidance in this SRP-LR section is 

only applicable to BWRs with an isolation condenser. 

 LRA Section 3.1.2.2.2.3 states that the aging effect is not applicable to PVNGS; it is 

applicable to BWRs only. SRP-LR Section 3.1.2.2.2, item 3 states that loss of material 

due to pitting and crevice corrosion may occur in stainless steel, nickel alloy, and steel 

with stainless steel or nickel-alloy cladding flanges, nozzles, penetrations, pressure 

housings, safe ends, and vessel shells, heads, and welds exposed to reactor coolant. 

This section of the SRP-LR is cross-referenced to the GALL Report, Table IV.C1, which 

is for BWRs. The staff finds that SRP-LR Section 3.1.2.2.2, item 3 is not applicable to 

PVNGS because the PVNGS units are PWRs, and the staff guidance in this SRP-LR 

section is only applicable to BWRs. 

 LRA Section 3.1.2.2.2.4 addresses loss of material due to general, pitting, and crevice 

corrosion in the steel SG shell and transition cone exposed to secondary feedwater and 

steam, stating that augmented inspection is recommended for Westinghouse Model 44 

and 51 SGs, where a high stress region exists at the shell to transition cone weld, if 

general and pitting corrosion of the shell is known to exist. The SGs at PVNGS are 

CE-modified System 80, so the augmented inspection is not applicable. 
Aging Management Review Results 

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 SRP-LR Section 3.1.2.2.2.4 states that loss of material due to general, pitting, and 

crevice corrosion may occur in the steel PWR SG upper and lower shell and transition 

cone exposed to secondary feedwater and steam. The existing program controls 

chemistry to mitigate corrosion and ISI to detect loss of material. The extent and 

schedule of the existing SG inspections are designed to ensure that flaws cannot attain 

a depth sufficient to threaten the integrity of the welds; however, according to IN 90-04, 

the program may not be sufficient to detect pitting and crevice corrosion, if general and 

pitting corrosion of the shell is known to occur. The GALL Report recommends 

augmented inspection to manage this aging effect. Furthermore, the GALL Report 

clarifies that this issue is limited to Westinghouse Model 44 and 51 SGs with a 

high-stress region at the shell to transition cone weld. 

 Based on the clarification provided by the SRP-LR regarding the type of SGs that are 

affected by the subject degradation mechanisms, the staff agrees with the applicant that 

the augmented inspection is not applicable because they do not have Westinghouse 

Model 44 and 51 SGs. 

Based on the programs identified above, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.1.2.2.2 criteria. For those items that apply to LRA Section 3.1.2.2.2, the staff 

determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that it will adequately manage the effects of aging so that the intended function(s) 

will be maintained consistent with the CLB during the period of extended operation, as required 

by 10 CFR 54.21(a) (3). 

3.1.2.2.3 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement 

The staff reviewed LRA Section 3.1.2.2.3 against the following criteria in SRP-LR 

Section 3.1.2.2.3: 

 LRA Section 3.1.2.2.3.1 addresses loss of fracture toughness due to certain aspects of 

neutron irradiation embrittlement as an aging effect that the applicant will manage 

through conducting TLAAs, consistent with the SRP-LR. The applicant states that LRA 

Section 4.2 describes the evaluation of these neutron embrittlement TLAAs. 

 SRP-LR Section 3.1.2.2.3.1 states that certain aspects of neutron irradiation 

embrittlement are TLAAs, as defined in 10 CFR 54.3. TLAAs are required to be 

evaluated in accordance with 10 CFR 54.21(c)(1). 

 Loss of fracture toughness due to neutron irradiation embrittlement is limited to RPV 

materials having a neutron fluence greater than 1 x 1017 n/cm2

 (for energy values greater 

than 1.0 mega electron-volt (MeV)) at the end of the period of extended operation. SER 

Section 4.2 accepted the applicant’s evaluation of RPV neutron embrittlement in terms of 

USE, pressurized thermal shock, and P-T limits, which represent a complete set of 

analytical means for predicting and managing loss of fracture toughness due to neutron 

irradiation embrittlement. Therefore, the staff concludes that the applicant’s program 

meets the SRP-LR Section 3.1.2.2.3.1 criterion. The staff also confirmed that LRA Table 

3.1.2-1 correctly identified the GALL Report Table IV.A2 item under this aging 

mechanism (IV.A2-23 for RPV shell). LRA Table 3.1.2-1 did not, however, list GALL 

Report AMR, item IV.A2-16 for RPV nozzles under this aging mechanism. This is 

acceptable because the estimated neutron fluence at the end of the period of extended 

operation for PVNGS, Units 1, 2, and 3 RPV nozzles is less than 1 x 1017 n/cm2

 (for 

energy values greater than 1.0 MeV). 

 SER Section 4.2 documents the staff’s review of the applicant’s evaluation of this TLAA. 

 LRA Section 3.1.2.2.3.2 addresses loss of fracture toughness due to neutron irradiation 

embrittlement as an aging effect that the applicant will manage, consistent with the 
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SRP-LR, by the RV Surveillance Program. This LRA section stated that due primarily to 

low-leakage cores, the revised 54 EFPY fluence projections are less than the original 

32 EFPY projections. Further, it stated that PVNGS retains sufficient unexposed 

archived material to provide two additional sets of test specimens for each material, 

sufficient to support the program for the period of extended operation. 

 SRP-LR Section 3.1.2.2.3 states that loss of fracture toughness due to neutron 

irradiation embrittlement may occur in BWR and PWR RV beltline shell, nozzle, and 

welds exposed to reactor coolant and neutron flux. A RV Materials Surveillance 

Program monitors neutron irradiation embrittlement of the RV. RV surveillance 

programs are plant-specific, depending on matters such as the composition of limiting 

materials, availability of surveillance capsules, and projected fluence levels. In 

accordance with 10 CFR Part 50, Appendix H, an applicant is required to submit its 

proposed withdrawal schedule for approval before implementation. Untested capsules 

placed in storage must be maintained for future insertion. Thus, further staff evaluation 

is required for license renewal. GALL Report Chapter XI, Section M31 provides specific 

recommendations for an acceptable AMP. 

 The staff noted that the LRA Table 3.1.2-1 subcomponent that credits the RV 

Surveillance Program for managing its loss of fracture toughness aging effect is “RV 

Shell,” which is not consistent with the corresponding GALL Report, AMR item IV.A2-24, 

“Vessel shell...(including beltline welds).” The staff determined that the applicant’s 

subcomponent “RV Shell” meant to include beltline welds because its RV Surveillance 

Program meets the ASTM E185-82 requirements and contains weld specimens for 

monitoring their neutron irradiation embrittlement. The staff accepted the applicant’s RV 

Surveillance Program, as indicated in SER Section 3.0.3.2.10. Hence, the staff 

concludes that the applicant’s program meets SRP-LR Section 3.1.2.2.3.2 criteria. The 

staff also confirmed that LRA Table 3.1.2-1 identified all GALL Report Table IV.A2 AMR 

items under this aging mechanism (IV.A2-17 and IV.A2-24). 

 Based on the TLAA and the program identified above, the staff concludes that the 

applicant’s programs meet SRP-LR Section 3.1.2.2.3.1 and Section 3.1.2.2.3.2 criteria. 

For those AMR items that apply to LRA Section 3.1.2.2.3, the staff concludes that the 

LRA is consistent with the GALL Report. The staff also finds that the applicant has 

demonstrated that it will adequately manage the effects of aging so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

3.1.2.2.4 Cracking Due to Stress Corrosion Cracking and Intergranular Stress Corrosion 

Cracking 

The staff reviewed LRA Section 3.1.2.2.4 against the following criteria in SRP-LR 

Section 3.1.2.2.4: 

 LRA Section 3.1.2.2.4.1 states that this aging effect is not applicable PVNGS; it is 

applicable to BWRs only. SRP-LR Section 3.1.2.2.4, item 1 states that cracking due to 

SCC and IGSCC may occur in the stainless steel and nickel-alloy BWR top head 

enclosure vessel flange leak detection lines. The staff finds that SRP-LR 

Section 3.1.2.2.4, item 1 is not applicable to PVNGS because the PVNGS units are 

PWRs, and the staff guidance in this SRP-LR section is only applicable to BWRs. 

 LRA Section 3.1.2.2.4.2 states that this aging effect is not applicable PVNGS, that it is 

applicable to BWRs only. SRP-LR Section 3.1.2.2.4, item 2 states that cracking due to 

SCC and IGSCC may occur in stainless steel BWR isolation condenser components 

exposed to reactor coolant. The staff finds that SRP-LR Section 3.1.2.2.4, item 2 is not 
Aging Management Review Results 

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applicable to PVNGS because the PVNGS units are PWRs, and the staff guidance in 

this SRP-LR section is only applicable to BWRs with an isolation condenser. 

Based on the above, the staff concludes that SRP-LR Section 3.1.2.2.4 criteria do not apply. 

3.1.2.2.5 Crack Growth Due to Cyclic Loading 

LRA Section 3.1.2.2.5 addresses crack growth of underclad flaws in RPV forgings due to cyclic 

loading as a potential aging effect that may be managed through a TLAA, consistent with the 

SRP-LR. However, the applicant's evaluation concludes that underclad cracking is not a TLAA 

for PVNGS, Units 1, 2, and 3. 

SRP-LR Section 3.1.2.2.5 states that crack growth due to cyclic loading could occur in RV shell 

forgings clad with stainless steel using a high-heat-input welding process. Growth of 

intergranular separations (underclad cracks) in the heat-affected zone under austenitic stainless 

steel cladding is a TLAA to be evaluated for the period of extended operation for all the 

SA 508-Cl 2 forgings where the cladding was deposited with a high heat input welding process. 

The methodology for evaluating the underclad flaw should be consistent with the current 

well-established flaw evaluation procedure and criterion in the ASME Section Xl Code. 

As evaluated in SER Section 4.7.6, the staff agrees with the applicant’s conclusion that RPV 

underclad cracking is not a TLAA for PVNGS, Units 1, 2, and 3 because high-heat-input, 

submerged-arc-welding processes, which caused the underclad cracking, were not used for the 

fabrication of the PVNGS, Units 1, 2, and 3 cladding over the RPV nozzles and flange. This 

aging effect is not applicable to the PVNGS units. 

3.1.2.2.6 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement and Void 

Swelling 

The staff reviewed LRA Section 3.1.2.2.6 against the criteria in SRP-LR Section 3.1.2.2.6. 

LRA Section 3.1.2.2.6 addresses loss of fracture toughness due to neutron irradiation, 

embrittlement, and void swelling as an aging effect that the applicant will manage, consistent 

with the SRP-LR. It will manage this effect by participating in the industry programs for 

investigating and managing aging effects on reactor internals and evaluating and implementing 

the results of the industry programs as applicable to the reactor internals. Upon completion of 

these programs, but not less than 24 months before entering the period of extended operation, 

the applicant will submit an inspection plan for reactor internals to the NRC for review and 

approval. 

SRP-LR Section 3.1.2.2.6 states that loss of fracture toughness due to neutron irradiation 

embrittlement and void swelling may occur in stainless steel and nickel-alloy RV internals 

components exposed to reactor coolant and neutron flux. The GALL Report recommends no 

further AMR if the applicant commits in the Final Safety Analysis Report (FSAR) supplement to 

participate in industry programs for investigating and managing aging effects on reactor 

internals and to evaluate and implement the results of the industry programs as applicable to 

the reactor internals. In addition, upon completion of these programs, but not less than 

24 months before entering the period of extended operation, the applicant must commit to 

submitting an inspection plan for reactor internals for the staff's review and approval. 

As described in LRA Section 3.1.2.2.6, the applicant made a commitment to incorporate all 

three GALL Report recommendations, stated above, to manage this aging mechanism. The 

RCS Supplement (LRA, Appendix B, Section B2.1.21) contains this commitment (Commitment 

No. 23). Commitment No. 23 is also identified in the UFSAR Supplement A1.21. Therefore, the 

staff concludes that the applicant’s program meets the SRP-LR Section 3.1.2.2.6 criteria for 

managing the aging effects due to neutron irradiation embrittlement and void swelling. The staff 

also examined LRA Table 3.1.2-1 to determine if the RPV internals subjected to these aging 
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effects are consistent with those listed in GALL Report Table IV.B3. The staff confirmed that 

LRA Table 3.1.2-1 identified GALL Report AMR, items IV.B3-12, IV.B3-16, and IV.B3-20 under 

this aging mechanism. However, this LRA table did not specifically list core shroud assembly 

bolts (GALL Report AMR, item IV.B3-10) and tie rods (GALL Report AMR, item IV.B3-12) under 

this aging mechanism. In addition, this LRA table did not list core support plate, fuel alignment 

pins, and core support column bolts as part of the GALL Report AMR, item IV.B3-20 under this 

aging mechanism. Therefore, by letter dated January 28, 2010, the staff issued RAI 3.1.2.2.6-1 

asking that the applicant confirm that the unit core shroud assemblies are welded structures that 

do not have bolts and tie rods. The staff also asked the applicant to clarify why the LRA table 

did not specifically list core support plate, fuel alignment pins, and core support column bolts 

under this aging effect as part of the GALL Report, AMR item IV.B3-20. 

The staff reviewed the applicant’s response dated March 1, 2010, to RAI 3.1.2.2.6-1. The 

applicant confirmed in the response that the PVNGS unit core shroud assemblies are welded 

structures that do not have bolts and tie rods; therefore, the GALL Report, AMR item IV.B3-10 is 

not applicable to the PVNGS units. As to the core support plate and core support column bolts, 

the response states that the PVNGS units used, instead, the core shroud assembly and the 

core shroud end plate to position and support the reactor core and provide control of the reactor 

coolant flow into each fuel assembly. Further, fuel alignment pins are included in the RV 

internals core support structure lower support structure assembly. Hence, RAI 3.1.2.2.6-1 is 

resolved. Based on the RAI resolution and the staff’s evaluation presented earlier, the staff 

concludes that the applicant’s program meets the SRP-LR Section 3.1.2.2.6 criteria. The 

applicant has demonstrated that it will adequately manage the effects of aging so that the 

intended function(s) will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

3.1.2.2.7 Cracking Due to Stress Corrosion Cracking 

The staff reviewed LRA Section 3.1.2.2.7 against the following criteria in SRP-LR 

Section 3.1.2.2.7: 

 LRA Section 3.1.2.2.7.1 refers to LRA Table 3.1.1, item 3.1.1.23 and addresses 

stainless steel bottom-mounted instrument guide tubes exposed to reactor coolant, 

which are being managed for cracking due to SCC by the Water Chemistry Program 

augmented by the ASME Section XI ISI, Subsections IWB, IWC, and IWD Program. 

 The staff reviewed LRA Section 3.1.2.2.7.1 against the criteria in SRP-LR 

Section 3.1.2.2.7, item 1, which states that cracking due to SCC could occur in PWR 

stainless steel bottom-mounted instrument guide tubes exposed to reactor coolant. The 

SRP-LR also states that the GALL Report recommends that a plant-specific AMP be 

evaluated to ensure that this aging effect is adequately managed. BTP RLSB-1 

(Appendix A.1 of the SRP-LR) describes the acceptance criteria. 

 SER Sections 3.0.3.2.1 and 3.0.3.1.1 document the staff’s evaluation of the applicant’s 

Water Chemistry and ASME Section XI ISI, Subsections IWB, IWC, and IWD Programs, 

respectively. In its review of components associated with LRA Table 3.1.1, 

item 3.1.1.23, the staff finds the applicant’s proposal to manage aging using the Water 

Chemistry and ASME Section XI ISI Programs acceptable because the Water Chemistry 

Program will mitigate the potential development and progress of the aging effect, while 

the ASME Section XI ISI, Subsections IWB, IWC and IWD Program will verify the 

effectiveness of the Water Chemistry Program. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.1.2.2.7, item 1 criterion. For those items that apply to LRA 

Section 3.1.2.2.7.1, the staff determines that the LRA is consistent with the GALL 

Report. The staff also finds that the applicant has demonstrated that the effects of aging 
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will be adequately managed so that the intended function will be maintained consistent 

with the CLB during the period of extended operation, as required by 10 CFR 

54.21(a)(3). 

 LRA Section 3.1.2.2.7.2 refers to LRA Table 3.1.1, item 3.1.1.24 and addresses the 

aging management of cracking due to SCC of CASS reactor coolant piping and 

components exposed to reactor coolant. The applicant stated, in LRA 

Section 3.1.2.2.7.2, that the RCS does not have CASS piping, piping components, and 

piping elements exposed to reactor coolant; therefore, this item is not applicable. 

 The staff reviewed LRA Section 3.1.2.2.7.2 against the criteria in SRP-LR 

Section 3.1.2.2.7, item 2, which states that cracking due to SCC could occur Class 1 

PWR CASS RCS piping, piping components, and piping elements exposed to reactor 

coolant. The existing program relies on control of water chemistry to mitigate SCC; 

however, SCC could occur for CASS components that do not meet the NUREG-0313 

guidelines with regard to ferrite and carbon content. The GALL Report recommends 

further evaluation of a plant-specific program for these components to ensure that this 

aging effect is adequately managed. 

 The staff reviewed LRA Section 3.1.2.2.7.2 and compared it to GALL AMR, 

item IV.C2-3 (R-05) for CASS in the reactor vessel, internals, and RCS. The GALL 

Report recommends use of monitoring and control of primary water chemistry and 

material selection to manage the aging effect. SRP-LR Section 3.1.2.2.7.2 is not 

applicable, as the applicant does not have CASS material exposed to the reactor coolant 

in this system. The staff verified that the RCS does not contain CASS piping, piping 

components, and piping elements by reviewing LRA Table 3.1.1, items 3.1.1.24 

and 3.1.1.57 and LRA Table 3.1.2-2, which refer to the AMPs, materials, and 

components for the RCS. 

 The applicant stated that cracking due to SCC in CASS filters is addressed by LRA 

Table 3.1.1, item 3.1.1.68. The staff noted that LRA Table 3.1.1, item 3.1.1.24 relies on 

the control of water chemistry and a plant-specific program, and LRA Table 3.1.1, 

item 3.1.1.68 specifies the ASME Section XI ISI, Subsections IWB, IWC, and IWD 

Program and Water Chemistry Program. The staff reviewed the applicant’s ASME 

Section XI ISI, Subsections IWB, IWC, and IWD Program, and SER Section 3.0.3.1.1 

documents its evaluation. The staff determined that the applicant’s program performs 

periodic visual, volumetric, or surface examinations of Class 1, 2, and 3 

pressure-retaining components. This program is capable of detecting cracking due to 

SCC and is an acceptable plant-specific program for managing this aging effect. The 

staff finds it acceptable that the applicant addressed cracking due to SCC of these 

CASS filters under LRA Table 3.1.1, item 3.1.1.68 because the applicant proposed its 

ASME Section XI ISI, Subsections IWB, IWC, and IWD Program that is capable of 

detecting this aging effect and its Water Chemistry Program, that is consistent with the 

recommendations of the GALL Report. 

 Based on its review, the staff concludes that the SRP-LR Section 3.1.2.2.7, item 2 

criteria is not applicable to the PVNGS units because the RCS does not contain CASS 

piping, piping components, and piping elements exposed to reactor coolant, other than 

filters addressed by item 3.1.1.68. 

3.1.2.2.8 Cracking Due to Cyclic Loading 

The staff reviewed LRA Section 3.1.2.2.8 against the following criteria in SRP-LR 

Section 3.1.2.2.8: 
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 LRA Section 3.1.2.2.8.1 states that the aging effect is not applicable to PVNGS; it is 

applicable to BWRs only. SRP-LR Section 3.1.2.2.8, item 1 states that cracking due to 

cyclic loading may occur in the stainless steel BWR jet pump sensing lines. The staff 

finds that SRP-LR Section 3.1.2.2.8, item 1 is not applicable to PVNGS because the 

PVNGS units are PWRs, and the staff guidance in this SRP-LR section is only 

applicable to BWRs. 

 LRA Section 3.1.2.2.8.2 states that the aging effect is not applicable to PVNGS; it is 

applicable to BWRs only. SRP-LR Section 3.1.2.2.8, item 2 states that cracking due to 

cyclic loading may occur in steel and stainless steel BWR isolation condenser 

components exposed to reactor coolant. The staff finds that SRP-LR Section 3.1.2.2.8, 

item 1 is not applicable to PVNGS because the PVNGS units are PWRs, and the staff 

guidance in this SRP-LR section is only applicable to BWRs. 

Based on the above, the staff concludes that SRP-LR Section 3.1.2.2.8 criteria do not apply. 

3.1.2.2.9 Loss of Preload Due to Stress Relaxation 

The staff reviewed LRA Section 3.1.2.2.9 against the criteria in SRP-LR Section 3.1.2.2.9. 

LRA Section 3.1.2.2.9 addresses loss of preload due to stress relaxation for PVNGS stainless 

steel screws, bolts, and tie rods of the CEA shroud assembly components exposed to reactor 

coolant as an aging effect that the applicant will manage, consistent with the SRP-LR, by the 

commitment of PVNGS AMP B2.1.21. 

SRP-LR Section 3.1.2.2.9 states that loss of preload due to stress relaxation may occur in 

stainless steel and nickel-alloy PWR RV internals screws, bolts, tie rods, and hold-down springs 

exposed to reactor coolant. The GALL Report recommends no further AMR if the applicant 

commits in the FSAR supplement to participate in the industry programs for investigating and 

managing aging effects on reactor internals and to evaluate and implement the results of the 

industry programs as applicable to the reactor internals. In addition, upon completion of these 

programs, but not less than 24 months before entering the period of extended operation, the 

applicant must submit an inspection plan for reactor internals to the staff for review and 

approval. 

As described in LRA Section 3.1.2.2.9, the applicant made a commitment to incorporate all 

three GALL Report recommendations, stated above, to manage this aging mechanism. The 

RCS Supplement contains this commitment (Commitment No. 23) and it is also identified in the 

UFSAR Supplement A1.21. Therefore, the staff concludes that the applicant’s program meets 

the SRP-LR Section 3.1.2.2.9 criteria for managing the aging effects due to loss of preload due 

to stress relaxation. The staff also examined LRA Table 3.1.2-1 to determine if the RPV 

internals subjected to these aging effects are consistent with those listed in GALL Report 

Table IV.B3. The staff confirmed that LRA Table 3.1.2-1 identified GALL Report Table IV.B3, 

item IV.B3-6 under this aging mechanism. This LRA Table did not list core shroud assembly 

bolts and tie rods (GALL Report AMR, item IV.B3-7) under this aging mechanism because the 

PVNGS unit core shroud assemblies are welded structures, as confirmed by the applicant in its 

response to RAI 3.1.2.2.6-1. Therefore, the staff concludes that the LRA is consistent with the 

GALL Report, and that the applicant has demonstrated that it will adequately manage the 

effects of aging so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.1.2.2.10 Loss of Material Due to Erosion 

The staff reviewed LRA Section 3.1.2.2.10 against the criteria in SRP-LR Section 3.1.2.2.10. 

LRA Section 3.1.2.2.10 addresses loss of material due to erosion for PVNGS steel SG 

feedwater impingement plates and supports exposed to secondary feedwater. The applicant 
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stated that the PVNGS SGs do not have feedwater impingement plates. Hence, this aging 

mechanism is not applicable to PVNGS, Units 1, 2, and 3. 

SRP-LR Section 3.1.2.2.10 states that loss of material due to erosion could occur in steel SG 

feedwater impingement plates and supports exposed to secondary feedwater. 

Since the PVNGS SGs were designed with no feedwater impingement plates, the staff agrees 

with the applicant’s conclusion that this SRP-LR criterion does not apply to the PVNGS units. 

3.1.2.2.11 Cracking Due to Flow-Induced Vibration 

The staff reviewed LRA Section 3.1.2.2.11 against the criteria in SRP-LR Section 3.1.2.2.11. 

LRA Section 3.1.2.2.11 states that the aging effect is not applicable to PVNGS; it is applicable 

to BWRs only. SRP-LR Section 3.1.2.2.11 states that cracking due to flow-induced vibration 

could occur for the BWR stainless steel steam dryers exposed to reactor coolant. The staff 

finds that SRP-LR Section 3.1.2.2.11 is not applicable to PVNGS because the PVNGS units are 

PWRs, and the staff guidance in this SRP-LR section is only applicable to BWRs. 

3.1.2.2.12 Cracking Due to Stress Corrosion Cracking and Irradiation-Assisted Stress 

Corrosion Cracking 

The staff reviewed LRA Section 3.1.2.2.12 against the criteria in SRP-LR Section 3.1.2.2.12. 

LRA Section 3.1.2.2.12 addresses cracking due to SCC and IASCC of stainless steel RPV 

internals exposed to reactor coolant as an aging effect that the applicant will manage, consistent 

with the SRP-LR, through its Water Chemistry Program and the commitment in the RCS 

Supplement. 

SRP-LR Section 3.1.2.2.12 states that cracking due to SCC and IASCC may occur in PWR 

stainless steel reactor internals exposed to reactor coolant. The existing program controls water 

chemistry to mitigate these aging effects. The GALL Report recommends no further AMR if the 

applicant commits in the UFSAR supplement to participate in the industry programs for 

investigating and managing aging effects on reactor internals and to evaluate and implement 

the results of the industry programs as applicable to the reactor internals. In addition, upon 

completion of these programs, but not less than 24 months before entering the period of 

extended operation, the applicant must submit an inspection plan for reactor internals to the 

staff for review and approval. 

As indicated in SER Section 3.0.3.2.1, the staff accepts the Water Chemistry Program for 

mitigating the aging effects due to SCC and IASCC, meeting one of the requirements mentioned 

in SRP-LR Section 3.1.2.2.12. Further, as described in LRA Section 3.1.2.2.12, the applicant 

made a commitment to incorporate all three GALL Report recommendations, stated above, to 

manage this aging mechanism. The PVNGS RCS Supplement contains this commitment 

(Commitment No. 23). UFSAR Supplement A1.21 also identifies Commitment No. 23. 

Therefore, the staff concludes that the applicant’s program meets the SRP-LR Section 

3.1.2.2.12 criteria. The staff also confirmed that LRA Table 3.1.2-1 identified the following GALL 

Report Table IV.B3 AMR items under this aging mechanism: IV.B3-2, IV.B3-11, IV.B3-15, 

IV.B3-21, and IV.B3-28. However, this LRA table does not cover all RPV internals in GALL 

Report Table IV.B3 under this aging mechanism. Therefore, by letter dated January 28, 2010, 

the staff issued RAI 3.1.2.2.12-1 and asked the applicant to clarify the disposition of the core 

support plate and core support column of the lower internal assembly (IV.B3-21) and the fuel 

alignment plate, the fuel alignment plate guide lugs, and guide lug inserts of the upper internals 

assembly (IV.B3-28). 

The staff reviewed the applicant’s response to RAI 3.1.2.2.12-1, dated March 1, 2010. 

Consistent with the response to RAI 3.1.2.2.6-1, the applicant clarified that, instead of using the 

core support plate and core support column, the PVNGS units used the core shroud assembly 
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and the core shroud end plate to position and support the reactor core and provide control of the 

reactor coolant flow into each fuel assembly. For GALL Report, AMR item IV.B3-28 

components, this response provides a detailed component list, including two of the 

three components specified in the GALL Report (the UGS support plate and the fuel alignment 

plate). The applicant evaluates the listed components to ensure consistency with GALL Report, 

AMR item IV.B3-28 for the aging effect of cracking due to SCC and IASCC. The third GALL 

Report-specified component, fuel alignment plate guide lugs and guide lug inserts, is not in the 

list. However, the applicant identified them to be integral parts of the PVNGS unit core shroud 

assembly and added the fuel alignment plate guide lugs and guide lug inserts to this component 

under GALL Report, AMR item IV.B3-11. This is acceptable because the aging mechanism and 

recommended AMP for both GALL Report items are identical. Hence, RAI 3.1.2.2.12-1 is 

resolved. Based on this RAI response and the staff’s evaluation presented earlier, the staff 

concludes that the applicant’s program meets the SRP-LR Section 3.1.2.2.12 criteria. The 

applicant has demonstrated that it will adequately manage the effects of aging so that the 

intended function(s) will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

3.1.2.2.13 Cracking Due to Primary Water Stress Corrosion Cracking 

The staff reviewed LRA Section 3.1.2.2.13 against the criteria in SRP-LR Section 3.1.2.2.13. 

LRA Section 3.1.2.2.13 refers to LRA Table 3.1.1, item 3.1.1.31 and addresses nickel-alloy 

components, including RCPB components and penetrations inside the RCS. These 

components include pressurizer heater sheaths and sleeves, nozzles, and other internal 

components exposed to reactor coolant, which are being managed for cracking due to PWSCC 

by the Water Chemistry Program, ASME Section XI ISI, Subsections IWB, IWC, and IWD 

Program, and the Nickel-Alloy AMP. In addition, the applicant provides in the UFSAR 

Supplement a commitment (Commitment No. 23) to implement applicable NRC orders, 

bulletins, and GLs associated with nickel alloys as well as staff-accepted industry guidelines. 

Further, the applicant participates in industry initiatives, such as owners group programs and the 

EPRI Materials Reliability Program, to manage the aging effects associated with nickel alloys. 

Upon completion of these programs, but not less than 24 months before entering the period of 

extended operation, the applicant will submit an inspection plan for RCS nickel-alloy pressure 

boundary components for the staff 's review and approval. The applicant addressed the further 

evaluation requirements by stating that the management of cracking, due to PWSCC of 

nickel-alloy components exposed to reactor coolant, will be performed by water chemistry and 

ISI, augmented by a plant-specific Nickel-Alloy AMP. In addition to these programs, the 

applicant will implement applicable NRC orders, bulletins, and GLs associated with nickel alloys 

as well as staff-accepted industry guidelines. 

The staff reviewed LRA Section 3.1.2.2.13 against the criteria described in SRP–LR 

Section 3.1.2.2.13, which states that cracking due to PWSCC could occur in nickel alloy and 

steel with nickel-alloy cladding PWR components. These components include RCPB 

components and penetrations inside the RCS such as pressurizer heater sheathes and sleeves, 

nozzles, and other internal components exposed to reactor coolant. The SRP-LR also states 

that, with the exception of RV upper head nozzles and penetrations, the GALL Report 

recommends ASME Section XI ISI (for Class 1 components) and control of water chemistry. 

For nickel-alloy components, no further AMR is necessary if the applicant complies with 

applicable NRC orders and provides a commitment in the UFSAR supplement to implement 

applicable bulletins, GLs, and staff-accepted industry guidelines. 

SER Sections 3.0.3.2.1, 3.0.3.1.1, and 3.0.3.3.1 document the staff’s evaluations of the 

applicant’s Water Chemistry Program, ASME Section XI ISI, Subsections IWB, IWC, and IWD 

Program, and Nickel-Alloy AMP, respectively. The staff noted that the Water Chemistry 

Program controls the chemical environment to ensure that the aging effects due to 
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contaminants are limited by managing the primary and secondary water. The staff noted that 

this is accomplished by limiting the concentration of chemical species known to cause corrosion 

and adding chemical species known to inhibit degradation by their influence on pH and 

dissolved oxygen levels. The staff also noted that this program is effective in creating an 

environment that is not conducive for cracking to occur. The staff noted that the ASME Section 

XI ISI, Subsections IWB, IWC, and IWD Program includes requirements for scheduling of 

examinations and tests for Class 1, 2, and 3 components. The staff further noted that this 

program requires periodic visual, surface, volumetric examinations and leakage tests of Class 1, 

2, and 3 pressure-retaining components, provides measures for monitoring to detect aging 

effects before the loss of intended function, and provides measures for the repair and 

replacement of components with aging effects. The staff noted that the Nickel-Alloy AMP will 

augment the ASME Section XI ISI, Subsections IWB, IWC, and IWD Program for nickel-alloy 

components, which consists of inspections, mitigation techniques, repair or replace activities, 

and monitoring of operating experience to manage the aging of these components. 

The staff finds the applicant’s use of its Water Chemistry Program, ASME Section XI ISI, 

Subsections IWB, IWC, and IWD Program, and Nickel-Alloy AMP acceptable to manage this 

aging effect because by controlling water chemistry, the applicant will create an environment 

that is not conducive for cracking to occur. In addition, the applicant will conduct a combination 

of periodic visual, surface, and volumetric examinations that are proven capable of detecting 

cracking and are consistent with ASME Section XI, ASME Code Case N-729-1, subject to the 

conditions specified in 10 CFR 50.55a(g)(6)(ii)(D)(2)–(6), and ASME Code Case N-722, subject 

to the conditions listed in 10 CFR 50.55a(g)(6)(ii)(E)(2)–(4). Further, the applicant has credited 

programs consistent with the GALL Report in addition to crediting its plant-specific Nickel-Alloy 

AMP and has provided Commitment No. 23, consistent with the SRP-LR. 

Based on the program identified, the staff concludes that the applicant’s program meets 

SRP-LR Section 3.1.2.2.13 criteria. For those items that apply to LRA Section 3.1.2.2.13, the 

staff determines that the LRA is consistent with the GALL Report. The applicant has 

demonstrated that it will adequately manage the effects of aging for these components so that 

their intended function will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

3.1.2.2.14 Wall Thinning Due to Flow-Accelerated Corrosion 

LRA Table 3.1.1, item 3.1.1.32, addresses the steel SG feedwater inlet ring (feedring) and 

supports exposed to secondary feedwater or steam, which are being managed for wall thinning 

due to FAC by the SG Tube Integrity Program and Water Chemistry Program. The applicant 

addressed the further evaluation criteria of the SRP-LR by stating that feedring wall thinning, as 

addressed in IN 91-19, is not applicable to PVNGS due to the model of SGs in use, and that no 

action is required. However, the applicant stated that the Water Chemistry Program and the SG 

Tubing Integrity Program are conservatively credited to manage wall thinning due to FAC for the 

feedring. In LRA Table 3.1.2-4, plant-specific Note 1, the applicant states that feedring wall 

thinning, as described in IN 9-19, has been detected only in certain CE pre-System 80 SGs and 

that its SGs are CE modified System 80. The applicant further stated that because no operating 

experience at its plant or other units with CE modified System 80 SGs suggests that 

degradation of the feedrings is occurring, it has determined this condition is not applicable to its 

plant, and no action is required. 

The staff reviewed LRA Section 3.1.2.2.14 against criteria in SRP-LR Section 3.1.2.2.14, which 

states that wall thinning due to FAC could occur in steel feedrings and supports. The GALL 

Report references IN 91-19, "Steam Generator Feedwater Distribution Piping Damage," for 

evidence of FAC in SGs and recommends that a plant-specific AMP be evaluated because 

existing programs may not be capable of mitigating or detecting wall thinning due to FAC. 
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In its review of components associated with LRA item 3.1.1.32, the staff noted that the applicant 

assigned generic note E to the AMR item, indicating that the GALL Report recommends a 

plant-specific AMP be evaluated for this combination of component, material, environment, and 

aging effect combination. Because the GALL Report recommends that a plant-specific AMP be 

evaluated, and the applicant credits the Water Chemistry Program and the SG Tube Integrity 

Program to manage wall thinning in these components, the staff finds the applicant’s use of 

generic note E to be acceptable. 

The staff does not consider IN 91-19 to be limited to CE SGs, however, and the staff was 

unclear why the applicant stated no action was required for addressing FAC of the feedring. 

The applicant’s description of the SG design in LRA Sections 2.3.1.4 and B2.1.8 does not 

provide sufficient detail of the feedwater inlet ring and supports for the staff to determine if FAC 

could potentially occur in the replacement SG design. 

Moreover, the applicant stated that it conservatively credits its Water Chemistry Program and 

SG Tubing Integrity Program to manage wall thinning due to FAC. In LRA Section B2.1.8, the 

applicant stated that tube support degradation is monitored by the presence of normal support 

signals at expected tube locations and by visual inspection of the secondary side. It further 

stated that its SG management procedure specifies that it will visually inspect SGs, as required, 

on the secondary side at the accessible portions of the following locations: tubesheet region, 

both hot and cold leg, tube supports, flow distribution plate, and upper steam drum internals. 

The staff was not clear if the SG feedwater ring was included in the scope of the SG Tube 

Integrity Program. This was previously identified as Confirmatory Item 3.1.2.2.14-1. 

During a conference call on July 9, 2010, and in a letter dated July 30, 2010, the applicant 

clarified that the material of the SG feedring is fabricated from P11 steel and, therefore, is FAC 

resistant. The applicant also explained that the Steam Generator Tube Integrity Program 

considers wall thinning of the SG feedring and applicable operating experience as part of the 

secondary side SG Degradation Assessment, performed before every outage. The staff finds 

this information acceptable and Confirmatory Item 3.1.2.2.14-1 is closed. 

SER Sections 3.0.3.2.1 and 3.0.3.1.5 document the staff’s evaluation of the applicant’s Water 

Chemistry Program and SG Tube Integrity Program, respectively. The staff noted that the 

Water Chemistry Program manages wall thinning in the secondary water system, including 

maintaining appropriate chemical concentrations in the SG secondary side and the secondary 

systems, to limit aging effects associated with corrosion mechanisms. The staff further noted 

that the SG Tube Integrity Program addresses wall thinning due to FAC of the SG feedring 

through the SG degradation assessment. Since the SG feedring is fabricated from 

FAC-resistant material, the staff finds this aging effect unlikely to occur in this component. 

Therefore, the staff finds the applicant’s proposal to manage the aging effect of wall thinning 

due to FAC for the steel SG feedring and supports by using the Water Chemistry Program and 

the SG Tube Integrity Program acceptable because, 1) the Water Chemistry Program provides 

mitigation for this aging effect and its use is consistent with the recommendations of the GALL 

Report, and 2) the SG Tube Integrity Program is adequate for verifying the effectiveness of the 

Water Chemistry Program for the secondary side SG internals and for managing wall thinning 

due to FAC before tube integrity is compromised. 

The staff concludes that the applicant’s programs meet SRP-LR Section 3.1.2.2.14 criteria. For 

those items that apply to LRA Section 3.1.2.2.14, the staff determines the LRA is consistent with 

the GALL Report. The applicant has demonstrated that it will adequately manage the effects of 

aging so that the intended functions will be maintained consistent with the CLB during the period 

of extended operation, as required by 10 CFR 54.21(a)(3). 

3.1.2.2.15 Changes in Dimensions Due to Void Swelling 

The staff reviewed LRA Section 3.1.2.2.15 against the criteria in SRP-LR Section 3.1.2.2.15. 
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LRA Section 3.1.2.2.15 addresses changes in dimension due to void swelling for stainless steel 

and nickel-alloy reactor internal components exposed to reactor coolant as an aging effect that 

the applicant will manage, consistent with the SRP-LR, by the commitment of PVNGS RCS 

Supplement. 

SRP-LR Section 3.1.2.2.15 states that changes in dimensions due to void swelling may occur in 

stainless steel and nickel-alloy PWR internal components exposed to reactor coolant. The 

GALL Report recommends no further AMR if the applicant commits in the FSAR supplement to 

participate in the industry programs for investigating and managing aging effects on reactor 

internals and to evaluate and implement the results of the industry programs as applicable to 

the reactor internals. In addition, upon completion of these programs, but not less than 

24 months before entering the period of extended operation, the applicant must submit an 

inspection plan for reactor internals for the staff's review and approval. 

As described in LRA Section 3.1.2.2.15, the applicant made a commitment to incorporate all 

three GALL Report recommendations, stated above, to manage this aging mechanism. PVNGS 

AMP B2.1.21 contains this commitment (Commitment No. 23). UFSAR Supplement A1.21 also 

identifies Commitment No. 23. Therefore, the staff concludes that the applicant’s program 

meets the SRP-LR Section 3.1.2.2.15 criteria. The staff also confirmed that LRA Table 3.1.2-1 

identified the following GALL Report Table IV.B3 AMR items under this aging mechanism: 

IV.B3-4, IV.B3-13, IV.B3-14, IV.B3-19, and IV.B3-27. However, this LRA table does not cover 

all RPV internals in GALL Report Table IV.B3 under this aging mechanism. Therefore, by letter 

dated January 28, 2010, the staff issued RAI 3.1.2.2.15-1and asked the applicant to clarify the 

disposition of the core support plate, fuel alignment pins, and core support column bolts of the 

lower internal assembly (IV.B3-19) and the fuel alignment plate, the fuel alignment plate guide 

lugs, and guide lug inserts of the upper internals assembly (IV.B3-27). Additionally, the staff 

asked the applicant to discuss the relationship between RV internals in-core instrumentation 

support structures (identified in LRA Table 3.1.2-1) and the core support plate, fuel alignment 

pins, and core support column bolts of the lower internal assembly (listed in the GALL Report 

Table IV.B3). 

The staff reviewed the applicant’s response to RAI 3.1.2.2.15-1, dated March 1, 2010. For 

GALL Report-specified items IV.B3-19 and IV.B3-27 components, some do not exist and some 

take different names in the PVNGS units. The only PVNGS unit component that seems 

inconsistent with the GALL Report is the fuel alignment plate guide lugs and guide lug inserts. 

Instead of classifying it under AMR item IV.B3-27 as in the GALL Report, this component is 

placed under GALL Report, AMR item IV.B3-13 as part of the PVNGS unit core shroud 

assembly. This is acceptable because the aging mechanism and recommended AMP for both 

GALL Report AMR items are identical. The applicant further clarified that the RV internals 

in-core instrumentation support structures are evaluated as part of the lower support structure 

assembly. Hence, RAI 3.1.2.2.15-1 is resolved. Based on the applicant’s response to this RAI 

and the staff’s evaluation presented earlier, the staff concludes that the applicant’s program 

meets the SRP-LR Section 3.1.2.2.15 criteria. The applicant has demonstrated that it will 

adequately manage the effects of aging so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.1.2.2.16 Cracking Due to Stress Corrosion Cracking and Primary Water Stress Corrosion 

Cracking 

The staff reviewed LRA Section 3.1.2.2.16 against the following criteria in SRP-LR 

Section 3.1.2.2.16: 

 LRA Section 3.1.2.2.16, item 1 refers to LRA Table 3.1.1, item 3.1.1.34 and addresses 

stainless steel and nickel-alloy reactor control rod drive head penetration pressure 
Aging Management Review Results 

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housings exposed to reactor coolant (internal), which are being managed for cracking 

due to SCC and PWSCC. The applicant addressed the further evaluation criteria of the 

SRP-LR by stating that the nickel alloy portion of the RV control element drive 

mechanism housing (lower) credits the Water Chemistry Program and the ASME 

Section XI ISI, Subsections IWB, IWC, and IWD Program, which will be augmented by 

the Nickel-Alloy AMP. The applicant further stated that it will comply with applicable 

NRC orders and the UFSAR Commitment. The applicant also stated for the stainless 

steel RV control element drive mechanism housing (upper and lower) it credits the Water 

Chemistry Program and the ASME Section XI ISI, Subsections IWB, IWC, and IWD 

Program. LRA Section 3.1.2.2.16.1 also refers to LRA Table 3.1.1, item 3.1.1-35 and 

addresses steel with stainless steel or nickel-alloy cladding primary side components. 

These components include SG upper and lower heads, tubesheets, and tube-to-tube 

sheet welds exposed to reactor coolant (internal) subject to cracking due to SCC and 

PWSCC. The applicant stated that LRA Table 3.1.1, item 3.1.1-35 is not applicable 

because the SGs are the recirculating type. 

 The staff reviewed LRA Section 3.1.2.2.16.1 against the criteria in SRP-LR 

Section 3.1.2.2.16, item 1, which states that cracking due to PWSCC could occur on the 

nickel-alloy control rod drive head penetration pressure housings. The GALL Report 

recommends ASME Section XI ISI and control of water chemistry to manage this aging 

and recommends no further AMR for PWSCC of nickel alloy if the applicant complies 

with applicable NRC orders and provides a commitment in the FSAR supplement to 

implement applicable bulletins, GLs, and staff-accepted industry guidelines. 

 SER Sections 3.0.3.2.1, 3.0.3.1.1 and 3.0.3.3.1 document the staff’s evaluations of the 

applicant’s Water Chemistry Program, ASME Section XI ISI, Subsections IWB, IWC, and 

IWD Program and Nickel-Alloy AMP, respectively. The staff noted that the Water 

Chemistry Program controls the chemical environment to ensure that the aging effects 

due to contaminants are limited by managing the primary and secondary water. The 

staff noted that this is accomplished by limiting the concentration of chemical species 

known to cause corrosion and adding chemical species known to inhibit degradation by 

their influence on pH and dissolved oxygen levels. The staff also noted that this 

program is effective in creating an environment that is not conducive for cracking to 

occur. The staff noted that the ASME Section XI ISI, Subsections IWB, IWC, and IWD 

Program includes requirements for the scheduling of examinations and tests for Class 1, 

2, and 3 components. The staff further noted that this program requires periodic visual, 

surface, volumetric examinations, and leakage tests of Class 1, 2, and 3 

pressure-retaining components. This program also provides measures for monitoring to 

detect aging effects before the loss of intended function and provides measures for the 

repair and replacement of components with aging effects. The staff noted that the 

Nickel-Alloy AMP will augment the ASME Section XI ISI, Subsections IWB, IWC, and 

IWD Program for nickel-alloy components. Furthermore, the Nickel-Alloy AMP consists 

of inspections, mitigation techniques, repair or replace activities, and monitoring of 

operating experience to manage the aging. 

 The SRP-LR states that no further AMR for PWSCC of nickel alloy is necessary if the 

applicant complies with applicable NRC orders and provides a commitment in the 

UFSAR supplement to implement applicable bulletins, GLs, and staff-accepted industry 

guidelines. In addition, the applicant must credit its Water Chemistry Program and 

ASME Section XI ISI, Subsections IWB, IWC, and IWD Program for aging management. 

The staff noted that the applicant’s commitment (Commitment No. 23) in LRA Appendix 

A, Section A1.21 states that it will implement applicable NRC orders, bulletins, and GLs 

associated with nickel alloys as well as staff-accepted industry guidelines. In addition, 

the applicant will participate in the industry initiatives, such as owners group programs 
Aging Management Review Results 

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and the EPRI Materials Reliability Program, to manage the aging effects associated with 

nickel alloys. Upon completion of these programs, but not less than 24 months before 

entering the period of extended operation, the applicant will submit an inspection plan for 

RCS nickel-alloy pressure boundary components to the NRC for review and approval. 

The staff noted that the applicant’s commitment includes the aspects from the SRP-LR 

recommendations and finds that it is consistent with the commitment described in 

SRP-LR 3.1.2.2.16, item 1. The staff also notes that all of the nickel-alloy AMR results 

lines that refer to LRA Table 3.1.1, item 3.1.1.34 are aligned with the applicant’s 

commitment, as described in LRA Appendix A, Section A1.21. The staff finds the 

applicant’s proposal acceptable because the applicant credits its Water Chemistry 

Program and ASME Section XI ISI, Subsections IWB, IWC, and IWD Program, 

augmented by its Nickel-Alloy AMP for nickel-alloy components. The applicant has 

provided the appropriate commitment in the UFSAR Supplement, and the AMR results 

lines refer to the commitment, consistent with the recommendations in the GALL Report 

and SRP-LR. 

 The staff reviewed GALL Report, AMR item IV.D2-4, which is associated with LRA 

Table 3.1.1, item 3.1.1.35. The staff noted that LRA Table 3.1.1, item 3.1.1.35 and 

GALL Report, AMR item IV.D2-4 recommendations for aging management are specific 

to the primary side components—upper and lower heads and tube sheets and 

tube-to-tube sheet welds for once-through SGs. The LRA also states that this item is not 

applicable because the SGs are recirculating-type. UFSAR Table 5.1-2 states that the 

SG tubes are fabricated from Alloy 690TT and that the tubesheet in contact with the 

reactor coolant is clad with weld deposited NiCrFe alloy, which is described as Alloy 600 

cladding in LRA Section B2.1.34. 

 The staff noted that the components associated with SRP-LR Table 3.1.1, item 3.1.1-35, 

are applicable to the once-through type SGs that are found in Babcock & Wilcox PWRs 

as discussed in the following paragraphs. 

 SRP-LR Section 3.1.2.2.16.1 identifies that cracking due to PWSCC could occur on the 

primary coolant side of PWR steel SG tube-to-tube sheet welds made or clad with nickel 

alloy. The GALL Report recommends ASME Code, Section XI, ISI, Subsections IWB, 

IWC, and IWD, and Water Chemistry Programs to manage this aging effect. The 

SRP-LR also recommends no further AMR for PWSCC of nickel alloy if the applicant 

complies with applicable NRC Orders and provides a commitment in its UFSAR 

supplement to implement applicable NRC bulletins, generic letters, and staff-accepted 

industry guidelines. The GALL Report, revision 1 addresses this aging effect in 

item IV.D2-4, which is only applicable to once-through SGs and not applicable to 

recirculating SGs. 

 The staff noted that ASME Code, Section XI does not require inspection of the 

tube-to-tubesheet welds. In addition, no specific NRC orders or bulletins address 

inspection requirements for these welds. The staff is concerned that the region of the 

autogenous tube-to-tubesheet welds may have insufficient chromium content to prevent 

initiation of PWSCC if the tubesheet cladding or associated weld materials are Alloy 600. 

This may be the case even when the SG tubes are made from Alloy 690TT, which has 

been shown to have sufficient chromium content to prevent this aging effect. 

Consequently, a PWSCC crack initiated in the cladding region, close to a tube, may 

propagate into or through the weld, causing a failure of the weld and of the RCP 

boundary, even for recirculating SGs. For some plants, the RCP boundary in this area 

has been redefined by a license amendment such that the autogenous 

tube-to-tubesheet weld is no longer included in the RCP boundary. Since the staff has 

not approved such a redefinition of the RCP boundary for the PVNGS SGs, the staff 
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considers that the effectiveness of the Primary Water Chemistry Program should be 

verified to ensure PWSCC is not occurring and the RCP boundary is not breached. 

 The staff held conference calls with the applicant on October 22, November 3, and 

November 19, 2010, to discuss and clarify the staff's concerns. The staff asked the 

applicant how it managed PWSCC in SG tube-to-tubesheet welds if the tubesheet 

cladding is Alloy 600. The applicant agreed to provide information on its management of 

this aging mechanism. 

 By letter dated November 23, 2010, the applicant explained that the SGs tubes are 

manufactured from Alloy 690TT with a chromium content of 30 percent. The tubesheet 

cladding is composed of Alloy 82 with a chromium content of 18−20 percent and that the 

tube-to-tubesheet weld is an autogenous weld, which is created by melting the corner of 

the tubesheet clad to the tube end without adding filler metal. The applicant described 

statements from an industry review (MRP-115) that identified a threshold for PWSCC 

resistance for Alloys 600/82/182 with a chromium content of 22−30 percent. In 

comparison, the applicant stated it expected the chromium content of the 

tube-to-tubesheet welds to be 20−30 percent. The staff does not find this information to 

be a sufficient basis for precluding its concern about potential failure of the SG 

primary-to-secondary pressure boundary due to PWSCC of tube-to-tubesheet welds. 

 The applicant stated that the visual inspection performed every refueling outage on 

Alloy 82 repairs of several Alloy 600 high temperature components (half nozzle 

replacements using Alloy 690 nozzles welded with Alloy 82) have detected no leakage. 

However, the staff noted that the applicant did not provide information that would confirm 

the absence of cracking in these repaired areas. Further, the staff noted that differences 

in geometric configuration and fabrication do not allow for comparison of these repairs 

with the SG tube-to-tubesheet welds. 

 In response to the staff’s concern, the applicant committed (Commitment No. 62) to the 

following: 

 In response to the NRC staff concern regarding potential failure of the steam generator 

primary-to-secondary pressure boundary due to PWSCC cracking of tube-to-tubesheet 

welds, APS commits to perform one of the following two resolution options: 

1. Perform a one-time inspection of a representative number of 

tube-to-tubesheet welds in each steam generator to determine if 

PWSCC cracking is present. If weld cracking is identified: 

a. The condition will be resolved through repair or engineering 

evaluation to justify continued service, as appropriate. 

b. An ongoing monitoring program will be established to perform 

routine tube-to-tubesheet weld inspections for the remaining life of 

the steam generators. 

2. Perform an analytical evaluation of the steam generator 

tube-to-tubesheet welds in order to: 

a. Establish a technical basis which concludes that the structural 

integrity of the steam generator tube-to-tubesheet interface is 

adequately maintained with the presence of tube-to-tubesheet 

weld cracking. 

b. Establish a technical basis which concludes that the steam 

generator tube-to-tubesheet welds are not required to perform a 

reactor coolant pressure boundary function. 
Aging Management Review Results 

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 Moreover, the applicant stated that if the first option is selected, it would be completed 

for each SG in each unit during an eddy-current inspection outage This outage would be 

chosen such that it is between 20 and 25 calendar years of SG operation, according to 

the dates of SG replacement for Units 1, 2 and 3 (fall of 2005, 2003, and 2007, 

respectively). For Units 1 and 3, the applicant stated the inspection would 

approximately correspond to the first 5 years after entering the period of extended 

operation (i.e., September 1, 2025, to December 1, 2030, and September 1, 2027, to 

December 1, 2032, respectively). For Unit 2, this would approximately correspond to 

3 years prior to and 2 years after entering the period of extended operation (i.e., 

September 1, 2023, to December 1, 2028). The applicant further stated that if the 

second option is selected, it would be completed prior to September 1, 2023, the date 

when the first replaced SGs (Unit 2) will reach 20 years of operation. 

 Based on its review, the staff finds the applicant’s commitment (Commitment No. 62) 

acceptable because it will manage the aging effect of cracking due to PWSCC in the SG 

tube-to-tubesheet welds either by demonstrating that those welds do not have a 

structural integrity or pressure boundary function or by implementing a one-time 

inspection. This one-time inspection will be capable of detecting PWSCC cracking on a 

representative number of tube-to-tubesheet welds for each SG in a time period 

consistent with the detection of potential PWSCC. The staff finds the timing of these 

inspections to be acceptable because the proposed implementation schedule allows 

operation of the SGs for between 20 and 25 years, and it is unlikely that significant 

detrimental PWSCC cracking will have initiated before this time. The staff also noted 

that, if the aging effect is revealed, this one-time inspection is accompanied by corrective 

actions, including an evaluation of the degradation and the implementation of routine 

inspections of the tube-to-tubesheet welds for the remaining life of the SGs. 

 LRA Section 3.1.2.2.16.2 addresses nickel alloy and stainless steel pressurizer spray 

heads exposed to reactor coolant. The GALL Report recommends use of GALL 

AMP XI.M2 “Water Chemistry,” and GALL AMP XI.M32 “One-Time Inspection.” In 

addition, for nickel-alloy welded spray heads, the applicant must comply with applicable 

NRC orders and provide a commitment in the UFSAR supplement to implement 

applicable bulletins, GLs, and staff-accepted industry guidelines to manage cracking due 

to SCC and PWSCC for this component group. The applicant stated that this item is not 

applicable because it has determined that the pressurizer spray heads are not included 

in scope of license renewal; therefore, it did not use the applicable GALL Report line. 

 The staff reviewed LRA Section 3.1.2.2.16.2 against the criteria in SRP-LR 

Section 3.1.2.2.16, item 2, which states that cracking due to SCC could occur on 

stainless steel pressurizer spray heads, and cracking due to PWSCC could occur on 

nickel-alloy pressurizer spray heads when exposed to reactor coolant. The SRP-LR also 

states the existing program relies on control of water chemistry to mitigate this aging 

effect. The GALL Report recommends one-time inspection to confirm that cracking is 

not occurring. For nickel-alloy welded spray heads, the GALL Report recommends no 

further AMR if the applicant complies with applicable NRC orders and provides a 

commitment in the UFSAR supplement to implement applicable bulletins, GLs, and 

staff-accepted industry guidelines. 

 The staff reviewed the LRA scoping and screening results for the pressurizer, which 

indicate that the spray heads are not included in the scope of the license renewal. In 

addition, the staff reviewed the LRA aging management evaluation tables and did not 

identify the inclusion of the pressurizer spray heads. In its review, the staff further noted 

that LRA Section 3.1.2.2.16.2 indicates that the pressurizer spray heads are not included 

in the scope of the license renewal. However, the LRA section does not provide a 
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technical basis for why the pressurizer spray heads are not in the scope of the license 

renewal process and why this component is not managed by an AMP. 

 By letter dated April 1, 2010, the applicant stated that LRA Sections 3.1.2.1.3 and 

3.1.2.2.16.2 and Tables 2.3.1-3, 3.1.1, and 3.1.2-3 have been revised to add the 

pressurizer spray heads to the scope of license renewal. The applicant stated that the 

Water Chemistry Program and One-Time Inspection Program are credited to manage 

the aging effects of cracking due to SCC and PWSCC of the nickel-alloy components. 

The applicant also stated that since the pressurizer spray head is not a 

pressure-retaining component and is not part of the RCPB, it is not included in the 

Alloy 600 Management Program Plan. The applicant further stated that it complies with 

applicable NRC orders and provides a commitment in the UFSAR supplement to 

implement applicable bulletins, GLs, and staff-accepted industry guidelines. 

 SER Sections 3.0.3.2.1 and 3.0.3.1.6 document the staff’s evaluations of the applicant’s 

Water Chemistry Program and One-Time Inspection Program, respectively. Based on 

its review, the staff finds the LRA revision and the applicant’s proposal to manage the 

aging effect of the pressurizer spray head acceptable because (1) the Water Chemistry 

Program monitors the water chemistry control parameters against the established 

parameter limits and, if a parameter exceeds the limit, the program performs adequate 

actions such that the water chemistry control continues to mitigate the aging effect, (2) 

the One-Time Inspection Program includes a one-time inspection of selected 

components to verify the effectiveness of the Water Chemistry Program, (3) the use of 

the Water Chemistry Program and One-Time Inspection Program to manage the aging 

effect is consistent with the GALL Report and SRP-LR, (4) the applicant also committed 

to comply with applicable NRC orders and provided a commitment in the UFSAR 

supplement to implement applicable bulletins, GLs, and staff-accepted industry 

guidelines in accordance with the SRP-LR and GALL Report. Based on its review, the 

staff’s concern, described above, is resolved. 

Based on the programs identified, the staff concludes that the applicant’s programs and 

Commitment No. 23 meet SRP-LR Section 3.1.2.2.16 criteria. For those items that apply to 

LRA Section 3.1.2.2.16, the staff determines that the LRA is consistent with the GALL Report. 

In addition, the applicant has demonstrated that it will adequately manage the effects of aging 

so that the intended function(s) will be maintained consistent with the CLB during the period of 

extended operation as required by 10 CFR 54.21(a)(3). 

3.1.2.2.17 Cracking Due to Stress Corrosion Cracking, Primary Water Stress Corrosion 

Cracking, and Irradiation-Assisted Stress Corrosion Cracking 

The staff reviewed LRA Section 3.1.2.2.17 against criteria in SRP-LR 3.1.2.2.17 which states 

cracking due to SCC, PWSCC, and IASCC could occur in PWR stainless steel and nickel-alloy 

RV internals components. The SRP-LR also states the existing program relies on control of 

water chemistry to mitigate these effects. It further states that no further AMR is necessary if 

the applicant provides a commitment in the UFSAR Supplement to participate in the industry 

programs for investigating and managing aging effects on reactor internals as well as to 

evaluate and implement the results of the industry programs as applicable to the reactor 

internals. In addition, upon completion of these programs, but not less than 24 months before 

entering the period of extended operation, the applicant must submit an inspection plan for 

reactor internals for the staff's review and approval. The staff noted that the applicant’s 

commitment (Commitment No. 23) in LRA Appendix A, Section A1.21 is consistent with the 

commitment described in SRP-LR 3.1.2.2.17. The staff also notes that all of the AMR results 

lines that refer to Table 3.1.1, item 3.1.1-37 are aligned with the applicant’s commitment as 

described in LRA Appendix A, Section A1.21. The staff finds the applicant’s proposal 

acceptable because the applicant credits its Water Chemistry Program and has provided the 
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appropriate commitment in the UFSAR Supplement. In addition, the AMR results lines refer to 

the commitment, consistent with the recommendations in the GALL Report and SRP-LR. 

Based on the programs identified above, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.1.2.2.17 criteria. For those items that apply to LRA Section 3.1.2.2.17, the 

staff determines that the LRA is consistent with the GALL Report. In addition, the applicant has 

demonstrated that it will adequately manage the effects of aging so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

3.1.2.2.18 Quality Assurance for Aging Management of Nonsafety-Related Components 

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA program. 

3.1.2.3 Aging Management Review Results Not Consistent with or Not Addressed in 

the Generic Aging Lessons Learned Report 

In LRA Tables 3.1.2-1 through 3.1.2-4, the staff reviewed additional details of the AMR results 

for material, environment, AERM, and AMP combinations not consistent with, or not addressed 

in, the GALL Report. 

In LRA Tables 3.1.2-1 through 3.1.2-4, via notes F–J, the applicant indicated which 

combinations of component type, material, environment, and AERM do not correspond to an 

item in the GALL Report. The applicant provided further information about how it will manage 

the aging effects. Specifically, Note F states that the GALL Report does not evaluate the 

material for the AMR item component. Note G states that the GALL Report does not evaluate 

the environment for the AMR item component. Note H states that the GALL Report does not 

evaluate the aging effect for the AMR item component, material, and environment combination. 

Note I indicates that the aging effect identified in the GALL Report for the item component, 

material, and environment combination is not applicable. Note J indicates that the GALL Report 

does not evaluate either the component or the material and environment combination for the 

item. 

For component type, material, and environment combinations not evaluated in the GALL 

Report, the staff reviewed the applicant’s evaluation to determine if the applicant has 

demonstrated that it will adequately manage the effects of aging so that the intended function(s) 

will be maintained consistent with the CLB for the period of extended operation. The following 

sections document the staff’s evaluation. 

3.1.2.3.1 Reactor Vessel and Internals—Summary of Aging Management Review—License 

Renewal Application Table 3.1.2-1 

The staff reviewed LRA Table 3.1.2-1, which summarizes the results of AMR evaluations for the 

RV and internals component groups. 

In LRA Table 3.1.2-1, the applicant stated that for nickel-alloy RV control element drive 

mechanism housing (lower) and nozzles, RV flange leak monitoring tube, RV head vent 

penetration, and RV in-core instrumentation nozzle exposed to borated water leakage there is 

no aging effect and no AMP is proposed. In LRA Table 3.1.2-2, the applicant stated that for 

nickel-alloy piping and thermowells exposed to borated water leakage, there is no aging effect 

and no AMP is proposed. In LRA Table 3.1.2-3, the applicant stated that for nickel-alloy 

pressurizer heater sheaths and sleeves and pressurizer instrument penetrations exposed to 

borated water leakage, there is no aging effect and no AMP is proposed. In LRA Table 3.1.2-4, 

the applicant stated that for nickel-alloy SG primary nozzles and safe ends exposed to borated 

water leakage, there is no aging effect and no AMP is proposed. The AMR item cites generic 

note G. 
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The staff reviewed the associated items in the LRA and confirmed that no aging effect is 

applicable for this component, material, and environmental because austenitic materials such as 

nickel alloys are not subject to loss of material or cracking when exposed to this environment. 

In addition, these materials are used as corrosion-resistant replacement materials where other 

materials have degraded. The staff noted that according to EPRI NP-5769, "Degradation and 

Failure of Bolting in Nuclear Power Plants,” Volumes 1 and 2, April 1988, corrosion-resistant 

materials, such as austenitic and martensitic stainless steels and high strength nickel base 

alloys, offer good protection against loss of material due to boric acid corrosion. The staff also 

noted that the conditions required for cracking due to a variety of mechanisms (SCC, PWSCC, 

IASCC, and IGSCC) to occur, such as being exposed to an aqueous solution (reactor coolant or 

other corrosive solutions) and high temperatures, do not exist on the surfaces of these 

components when exposed to borated water leakage. Therefore, the staff finds no AMP is 

necessary for nickel alloys in a borated water leakage environment. 

Based on its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that it will adequately manage the 

effects 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). 

3.1.2.3.2 Reactor Coolant System—Summary of Aging Management Review—License 

Renewal Application Table 3.1.2-2 

The staff reviewed LRA Table 3.1.2-2, which summarizes the results of AMR evaluations for the 

RCS component groups. 

SER Section 3.1.2.3.1 documents the staff’s evaluation for nickel-alloy components, exposed to 

borated water leakage, that are not subject to an AERM, with generic note G. 

Based on its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that it will adequately manage the 

effects of aging so that the intended function(s) will be maintained consistent with the CLB for 

the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.1.2.3.3 Pressurizer—Summary of Aging Management Review—License Renewal 

Application Table 3.1.2-3 

The staff reviewed LRA Table 3.1.2-3, which summarizes the results of AMR evaluations for the 

pressurizer component groups. 

SER Section 3.1.2.3.1 documents the staff’s evaluation for nickel-alloy components, exposed to 

borated water leakage, that are not subject to an AERM, with generic note G. 

Based on its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that it will adequately manage the 

effects of aging so that the intended function(s) will be maintained consistent with the CLB for 

the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.1.2.3.4 Steam Generators—Summary of Aging Management Review—License Renewal 

Application Table 3.1.2-3 

The staff reviewed LRA Table 3.1.2-4, which summarizes the results of AMR evaluations for the 

SG component groups. 

SER Section 3.1.2.3.1 documents the staff’s evaluation for nickel-alloy components, exposed to 

borated water leakage, that are not subject to an AERM, with generic note G. 
Aging Management Review Results 

 3-181 

Based on its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that it will adequately manage the 

effects of aging so that the intended function(s) will be maintained consistent with the CLB for 

the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.1.3 Conclusion 

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the RV, internals, and RCS components 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). 

3.2 Aging Management of Engineered Safety Features Systems

This section of the SER documents the staff’s review of the applicant’s AMR results for the ESF 

systems components and the following component groups: 

 containment leak test system 

 containment purge system 

 containment hydrogen control system 

 safety injection and shutdown cooling system 

3.2.1 Summary of Technical Information in the Application 

LRA Section 3.2 provides AMR results for the ESF systems components and component 

groups. LRA Table 3.2.1, “Summary of Aging Management Evaluations in Chapter V of 

NUREG-1801 [the GALL Report] for Engineered Safety Features,” is a summary comparison of 

the applicant’s AMRs with those evaluated in the GALL Report for the ESF systems 

components and component groups. 

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry 

operating experience in the determination of AERMs. The plant-specific evaluation included 

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 if the applicant provided sufficient information 

to demonstrate that it would adequately manage the effects of aging for the ESF systems 

components within the scope of license renewal and subject to an AMR, 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 reviewed AMRs to ensure the applicant’s claim that certain 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 identified the appropriate GALL Report AMRs. SER Section 3.0.3 documents 

the staff’s evaluations of the AMPs. Details of the staff’s evaluations are documented in SER 

Section 3.2.2.1. 

The staff also reviewed AMRs consistent with the GALL Report and for which further evaluation 

is recommended. The staff confirmed that the applicant’s further evaluations were consistent 
Aging Management Review Results 

 3-182 

with the SRP-LR Section 3.2.2.2 acceptance criteria. SER Section 3.2.2.2 documents the 

staff’s evaluations. 

The staff also conducted a technical review of the remaining AMRs not consistent with, or not 

addressed in, the GALL Report. The technical review evaluated if the applicant identified all 

plausible aging effects and if the aging effects listed were appropriate for the 

material-environment combinations specified. SER Section 3.2.2.3 documents the staff’s 

evaluations. 

For SSCs that the applicant claimed were not applicable or required no aging management, the 

staff reviewed the AMR items and the plant’s operating experience to verify the applicant’s 

claims. 

Table 3.2-1 summarizes the staff’s evaluation of components, aging effects or mechanisms, and 

AMPs, listed in LRA Section 3.2 and addressed in the GALL Report. 

Table 3.2-1. Staff Evaluation for Engineered Safety Features Systems Components 

in the GALL Report 

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Steel and stainless steel 

piping, piping components, 

and piping elements in ECCS 

(3.2.1-1) 

Cumulative 

fatigue damage 

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c) 

Yes TLAA Consistent 

with GALL 

Report. See 

SER Section 

3.2.2.2.1. 

Steel with stainless steel 

cladding pump casing 

exposed to treated borated 

water 

(3.2.1-2) 

Loss of material 

due to cladding 

breach 

A plant-specific 

AMP is to be 

evaluated. 

Reference NRC 

IN 94-63, “Boric 

Acid Corrosion of 

Charging Pump 

Casings Caused by 

Cladding Cracks” 

Yes Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.2.2.2.2. 

Stainless steel containment 

isolation piping and 

components internal surfaces 

exposed to treated water 

(3.2.1-3) 

Loss of material 

due to pitting and 

crevice corrosion 

Water Chemistry 

and One-Time 

Inspection 

Yes Water 

Chemistry and 

One-Time 

Inspection 

Consistent 

with GALL 

Report. See 

SER Section 

3.2.2.2.3(1). 

Stainless steel piping, piping 

components, and piping 

elements exposed to soil 

(3.2.1-4) 

Loss of material 

due to pitting and 

crevice corrosion 

A plant-specific 

AMP is to be 

evaluated. 

Yes Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.2.2.2.3(2). 

Stainless steel and aluminum 

piping, piping components, 

and piping elements exposed 

to treated water 

(3.2.1-5) 

Loss of material 

due to pitting and 

crevice corrosion 

Water Chemistry 

and One-Time 

Inspection 

Yes Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.2.2.2.3(3). 
Aging Management Review Results 

 3-183 

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Stainless steel and copper 

alloy piping, piping 

components, and piping 

elements exposed to 

lubricating oil 

(3.2.1-6) 

Loss of material 

due to pitting and 

crevice corrosion 

Lubricating Oil 

Analysis and OneTime Inspection 

Yes Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.2.2.2.3(4). 

Partially encased stainless 

steel tanks with breached 

moisture barrier exposed to 

raw water 

(3.2.1-7) 

Loss of material 

due to pitting and 

crevice corrosion 

A plant-specific 

AMP is to be 

evaluated for 

pitting and crevice 

corrosion of tank 

bottoms because 

moisture and water 

can egress under 

the tank due to 

cracking of the 

perimeter seal from 

weathering. 

Yes Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.2.2.2.3(5). 

Stainless steel piping, piping 

components, piping elements, 

and tank internal surfaces 

exposed to condensation 

(internal) 

(3.2.1-8) 

Loss of material 

due to pitting and 

crevice corrosion 

A plant-specific 

AMP is to be 

evaluated. 

Yes Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Consistent 

with GALL 

Report. See 

SER Section 

3.2.2.2.3(6). 

Steel, stainless steel, and 

copper alloy heat exchanger 

tubes exposed to lubricating 

oil 

(3.2.1-9) 

Reduction of heat 

transfer due to 

fouling 

Lubricating Oil 

Analysis and OneTime Inspection 

Yes Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.2.2.2.4(1). 

Stainless steel heat 

exchanger tubes exposed to 

treated water 

(3.2.1-10) 

Reduction of heat 

transfer due to 

fouling 

Water Chemistry 

and One-Time 

Inspection 

Yes Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.2.2.2.4(2). 

Elastomer seals and 

components in standby gas 

treatment system exposed to 

air-indoor uncontrolled 

(3.2.1-11) 

Hardening and 

loss of strength 

due to elastomer 

degradation 

A plant-specific 

AMP is to be 

evaluated. 

Yes Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.2.2.2.5. 

Stainless steel HPSI 

(charging) pump miniflow 

orifice exposed to treated 

borated water 

(3.2.1-12) 

Loss of material 

due to erosion 

A plant-specific 

AMP is to be 

evaluated for 

erosion of the 

orifice due to 

extended use of 

the centrifugal 

HPSI pump for

normal charging. 

Yes Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.2.2.2.6. 
Aging Management Review Results 

 3-184 

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Steel drywell and suppression 

chamber spray system nozzle 

and flow orifice internal 

surfaces exposed to airindoor uncontrolled (internal) 

(3.2.1-13) 

Loss of material 

due to general 

corrosion and 

fouling 

A plant-specific 

AMP is to be 

evaluated. 

Yes Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.2.2.2.7. 

Steel piping, piping 

components, and piping 

elements exposed to treated 

water 

(3.2.1-14) 

Loss of material 

due to general, 

pitting, and 

crevice corrosion 

Water Chemistry 

and One-Time 

Inspection 

Yes Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.2.2.2.8(1). 

Steel containment isolation 

piping, piping components, 

and piping elements internal 

surfaces exposed to treated 

water 

(3.2.1-15) 

Loss of material 

due to general, 

pitting, and 

crevice corrosion 

Water Chemistry 

and One-Time 

Inspection 

Yes Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.2.2.2.8(2). 

Steel piping, piping 

components, and piping 

elements exposed to 

lubricating oil 

(3.2.1-16) 

Loss of material 

due to general, 

pitting, and 

crevice corrosion 

Lubricating Oil 

Analysis and OneTime Inspection 

Yes Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.2.2.2.8(3). 

Steel (with or without coating 

or wrapping) piping, piping 

components, and piping 

elements buried in soil 

(3.2.1-17) 

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologicallyinfluenced 

corrosion 

Buried Piping and 

Tanks Surveillance 

or 

Buried Piping and 

Tanks Inspection 

No

Yes 

Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.2.2.2.9. 

Stainless steel piping, piping 

components, and piping 

elements exposed to treated 

water > 60°C (> 140°F) 

(3.2.1-18) 

Cracking due to 

SCC and IGSCC 

BWR SCC and 

Water Chemistry 

No Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.2.2.1.1. 

Steel piping, piping 

components, and piping 

elements exposed to steam 

or treated water 

(3.2.1-19) 

Wall thinning due 

to FAC 

FAC No Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.2.2.1.1. 

CASS piping, piping 

components, and piping 

elements exposed to treated 

water (borated or unborated) 

> 250°C (> 482°F) 

(3.2.1-20) 

Loss of fracture 

toughness due to 

thermal aging 

embrittlement 

Thermal Aging 

Embrittlement of 

CASS 

No Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.2.2.1.1. 

High-strength steel closure 

bolting exposed to air with 

steam or water leakage 

(3.2.1-21) 

Cracking due to 

cyclic loading, 

SCC 

Bolting Integrity No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.2.2.1.1. 
Aging Management Review Results 

 3-185 

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Steel closure bolting exposed 

to air with steam or water 

leakage 

(3.2.1-22) 

Loss of material 

due to general 

corrosion 

Bolting Integrity No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.2.2.1.1. 

Steel bolting and closure 

bolting exposed to air - 

outdoor (external), or air - 

indoor uncontrolled (external) 

(3.2.1-23) 

Loss of material 

due to general, 

pitting, and 

crevice corrosion 

Bolting Integrity No Bolting 

Integrity 

Consistent 

with GALL 

Report. 

Steel closure bolting exposed 

to air - indoor uncontrolled 

(external) 

(3.2.1-24) 

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening 

Bolting Integrity No Bolting 

Integrity 

Consistent 

with GALL 

Report. 

Stainless steel piping, piping 

components, and piping 

elements exposed to closedcycle cooling water > 60°C 

(> 140°F) 

(3.2.1-25) 

Cracking due to 

stress corrosion 

SCC 

Closed-Cycle 

Cooling Water 

System 

No Closed-Cycle 

Cooling Water 

System 

Consistent 

with GALL 

Report. 

Steel piping, piping 

components, and piping 

elements exposed to closedcycle cooling water 

(3.2.1-26) 

Loss of material 

due to general, 

pitting, and 

crevice corrosion 

Closed-Cycle 

Cooling Water 

System 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.2.2.1.1. 

Steel heat exchanger 

components exposed to 

closed-cycle cooling water 

(3.2.1-27) 

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion 

Closed-Cycle 

Cooling Water 

System 

No Closed-Cycle 

Cooling Water 

System 

Consistent 

with GALL 

Report. 

Stainless steel piping, piping 

components, piping elements, 

and heat exchanger 

components exposed to 

closed-cycle cooling water 

(3.2.1-28) 

Loss of material 

due to pitting and 

crevice corrosion 

Closed-Cycle 

Cooling Water 

System 

No Closed-Cycle 

Cooling Water 

System 

Consistent 

with GALL 

Report. 

Copper alloy piping, piping 

components, piping elements, 

and heat exchanger 

components exposed to 

closed-cycle cooling water 

(3.2.1-29) 

Loss of material 

due to pitting, 

crevice, and 

galvanic 

corrosion 

Closed-Cycle 

Cooling Water 

System 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.2.2.1.1. 

Stainless steel and copper 

alloy heat exchanger tubes 

exposed to closed-cycle 

cooling water 

(3.2.1-30) 

Reduction of heat 

transfer due to 

fouling 

Closed-Cycle 

Cooling Water 

System 

No Closed-Cycle 

Cooling Water 

System 

Consistent 

with GALL 

Report. 
Aging Management Review Results 

 3-186 

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

External surfaces of steel 

components including 

ducting, piping, ducting 

closure bolting, and 

containment isolation piping 

external surfaces exposed to 

air-indoor uncontrolled 

(external); condensation 

(external) and air-outdoor 

(external) 

(3.2.1-31) 

Loss of material 

due to general 

corrosion 

External Surfaces 

Monitoring 

No External 

Surfaces 

Monitoring 

Consistent 

with GALL 

Report. 

Steel piping and ducting 

components and internal 

surfaces exposed to air - 

indoor uncontrolled (Internal) 

(3.2.1-32) 

Loss of material 

due to general 

corrosion 

Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components 

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Consistent 

with GALL 

Report. 

Steel encapsulation 

components exposed to airindoor uncontrolled (internal) 

(3.2.1-33) 

Loss of material 

due to general, 

pitting, and 

crevice corrosion 

Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.2.2.1.1. 

Steel piping, piping 

components, and piping 

elements exposed to 

condensation (internal) 

(3.2.1-34) 

Loss of material 

due to general, 

pitting, and 

crevice corrosion 

Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components 

No Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.2.2.1.1. 

Steel containment isolation 

piping and components 

internal surfaces exposed to 

raw water 

(3.2.1-35) 

Loss of material 

due to general, 

pitting, crevice, 

and MIC and 

fouling 

Open-Cycle 

Cooling Water 

System 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.2.2.1.1. 

Steel heat exchanger 

components exposed to raw 

water 

(3.2.1-36) 

Loss of material 

due to general, 

pitting, crevice, 

galvanic, and MIC 

and fouling 

Open-Cycle 

Cooling Water 

System 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.2.2.1.1. 

Stainless steel piping, piping 

components, and piping 

elements exposed to raw 

water 

(3.2.1-37) 

Loss of material 

due to pitting, 

crevice, and MIC 

Open-Cycle 

Cooling Water 

System 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.2.2.1.1. 

Stainless steel containment 

isolation piping and 

components internal surfaces 

exposed to raw water 

(3.2.1-38) 

Loss of material 

due to pitting, 

crevice, and MIC 

and fouling 

Open-Cycle 

Cooling Water 

System 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.2.2.1.1. 
Aging Management Review Results 

 3-187 

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Stainless steel heat 

exchanger components 

exposed to raw water 

(3.2.1-39) 

Loss of material 

due to pitting, 

crevice, and MIC 

and fouling 

Open-Cycle 

Cooling Water 

System 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.2.2.1.1. 

Steel and stainless steel heat 

exchanger tubes (serviced by 

open-cycle cooling water) 

exposed to raw water 

(3.2.1-40) 

Reduction of heat 

transfer due to 

fouling 

Open-Cycle 

Cooling Water 

System 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.2.2.1.1. 

Copper alloy > 15% Zn 

piping, piping components, 

piping elements, and heat 

exchanger components 

exposed to closed-cycle 

cooling water 

(3.2.1-41) 

Loss of material 

due to selective 

leaching 

Selective Leaching 

of Materials 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.2.2.1.1. 

Gray cast iron piping, piping 

components, piping elements 

exposed to closed-cycle 

cooling water 

(3.2.1-42) 

Loss of material 

due to selective 

leaching 

Selective Leaching 

of Materials 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.2.2.1.1. 

Gray cast iron piping, piping 

components, and piping 

elements exposed to soil 

(3.2.1-43) 

Loss of material 

due to selective 

leaching 

Selective Leaching 

of Materials 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.2.2.1.1. 

Gray cast iron motor cooler 

exposed to treated water 

(3.2.1-44) 

Loss of material 

due to selective 

leaching 

Selective Leaching 

of Materials 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.2.2.1.1. 

Aluminum, copper alloy 

> 15% Zn, and steel external 

surfaces, bolting, and piping, 

piping components, and 

piping elements exposed to 

air with borated water leakage 

(3.2.1-45) 

Loss of material 

due to Boric acid 

corrosion 

Boric Acid 

Corrosion 

No Boric Acid 

Corrosion 

Consistent 

with GALL 

Report. 

Steel encapsulation 

components exposed to air 

with borated water leakage 

(internal) 

(3.2.1-46) 

Loss of material 

due to general, 

pitting, crevice 

and boric acid 

corrosion 

Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.2.2.1.1. 

CASS piping, piping 

components, and piping 

elements exposed to treated 

borated water > 250°C 

(> 482°F) 

(3.2.1-47) 

Loss of fracture 

toughness due to 

thermal aging 

embrittlement 

Thermal Aging 

Embrittlement of 

CASS 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.2.2.1.1. 
Aging Management Review Results 

 3-188 

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Stainless steel or stainlesssteel-clad steel piping, piping 

components, piping elements, 

and tanks (including safety 

injection tanks/accumulators) 

exposed to treated borated 

water > 60°C (> 140°F) 

(3.2.1-48) 

Cracking due to 

SCC 

Water Chemistry No Water 

Chemistry 

Consistent 

with GALL 

Report. 

Stainless steel piping, piping 

components, piping elements, 

and tanks exposed to treated 

borated water 

(3.2.1-49) 

Loss of material 

due to pitting and 

crevice corrosion 

Water Chemistry No Water 

Chemistry 

Consistent 

with GALL 

Report. 

Except for 

shutdown 

cooling heat 

exchanger; 

see SER 

Section 

3.2.2.1.2 

Aluminum piping, piping 

components, and piping 

elements exposed to air - 

indoor uncontrolled 

(internal/external) 

(3.2.1-50) 

None None NA None Consistent 

with GALL 

Report. 

Galvanized steel ducting 

exposed to air - indoor 

controlled (external) 

(3.2.1-51) 

None None NA None Consistent 

with GALL 

Report. 

Glass piping elements 

exposed to air - indoor 

uncontrolled (external), 

lubricating oil, raw water, 

treated water, or treated 

borated water 

(3.2.1-52) 

None None NA None Consistent 

with GALL 

Report. 

Stainless steel, copper alloy, 

and nickel-alloy piping, piping 

components, and piping 

elements exposed to air - 

indoor uncontrolled (external) 

(3.2.1-53) 

None None NA None Consistent 

with GALL 

Report. 

Steel piping, piping 

components, and piping 

elements exposed to air - 

indoor controlled (external) 

(3.2.1-54) 

None None NA Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.2.2.1.1. 
Aging Management Review Results 

 3-189 

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Steel and stainless steel 

piping, piping components, 

and piping elements in 

concrete 

(3.2.1-55) 

None None NA None Consistent 

with GALL 

Report. 

Steel, stainless steel, and 

copper alloy piping, piping 

components, and piping 

elements exposed to gas 

(3.2.1-56) 

None None NA None Consistent 

with GALL 

Report. 

Stainless steel and copper 

alloy < 15% Zn piping, piping 

components, and piping 

elements exposed to air with 

borated water leakage 

(3.2.1-57) 

None None NA None Consistent 

with GALL 

Report. 

 

The staff’s review of the ESF systems component groups fell into three categories. One 

category, documented in SER Section 3.2.2.1, reviewed AMR results for components that the 

applicant indicated are consistent with the GALL Report and require no further evaluation. 

Another category, documented in SER Section 3.2.2.2, reviewed AMR results for components 

that the applicant indicated are consistent with the GALL Report and for which further evaluation 

is recommended. A third category, documented in SER Section 3.2.2.3, reviewed AMR results 

for components that the applicant indicated are not consistent with, or not addressed in, the 

GALL Report. SER Section 3.0.3 documents the staff’s review of AMPs credited to manage or 

monitor aging effects of the ESF systems components. 

3.2.2.1 Aging Management Review Results Consistent with the Generic Aging Lessons 

Learned Report 

LRA Section 3.2.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the ESF systems components: 

 ASME Section XI ISI, Subsections IWB, IWC, and IWD 

 Bolting Integrity 

 Boric Acid Corrosion 

 Closed-Cycle Cooling Water System 

 External Surfaces Monitoring 

 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

 Nickel-Alloy Aging Management 

 One-Time Inspection 

 One-Time Inspection of ASME Code Class 1 Small-Bore Piping 

 RCS Supplement 

 Water Chemistry 

LRA Tables 3.2.2-1 through 3.2.2-4 summarize AMRs for the ESF systems components and 

indicate AMRs claimed to be consistent with the GALL Report. 
Aging Management Review Results 

 3-190 

The staff audited and reviewed the information in the LRA. The staff did not repeat its review of 

the matters described in the GALL Report; however, the staff did verify that the material 

presented in the LRA was applicable and that the applicant identified the appropriate GALL 

Report AMRs. The staff’s evaluation follows. 

3.2.2.1.1 Aging Management Review Results Identified as Not Applicable 

LRA Table 3.2.1, items 3.2.1.18 through 3.2.1.20 and 3.2.1.34 discuss the applicant’s 

determination that these items are applicable only to BWRs. The staff verified that these items 

do not apply because the units are a PWR design. Based on this determination, the staff finds 

that the applicant has provided an acceptable basis for concluding AMR items 3.2.1.18 through 

3.2.1.20 and 3.2.1.34 are not applicable. 

LRA Table 3.2.1, item 3.2.1.21 addresses high-strength steel closure bolting, exposed to air 

with steam or water leakage, in the ESF. The GALL Report recommends use of GALL Report 

AMP XI.M18, “Bolting Integrity,” to manage cracking due to cyclic loading or SCC for this 

component group. The applicant stated that this item is not applicable because there is no 

in-scope, high-strength steel closure bolting exposed to air with steam or water leakage in its 

ESF systems. By letter dated February 19, 2010, the staff issued RAI 3.3-1, part (a), asking 

that the applicant clarify if its statement means that it does not use high-strength steel closure 

bolting or that the bolting is used, but not exposed to the stated environment. In its response, 

dated March 24, 2010, the applicant stated that it does not use high-strength (greater than 

150 kilo pounds per square inch) steel closure bolting in the containment leak test, containment 

purge, or containment hydrogen control systems, per plant specification. The applicant also 

stated that its safety injection and shutdown cooling system uses stainless steel bolting that is 

evaluated in a borated water leakage environment. The staff noted that the applicant’s ESF 

systems is comprised of four plant systems: 

(1) the containment leak test system 

(2) the containment purge system 

(3) the containment hydrogen control system 

(4) the safety injection and shutdown cooling system 

The staff also noted that the applicant’s response addresses all four systems, stating that for 

three of the systems, high-strength steel closure bolting is not used and for the fourth system, 

stainless steel, not steel, closure bolting is used. The staff reviewed LRA Sections 2.3.2 and 3.2 

and confirmed that the applicant’s LRA does not have any AMR results that include 

high-strength steel closure bolting exposed to air with steam or water leakage. Because the 

applicant does not use high-strength steel closure bolting in any of the four plant systems 

comprising its ESF systems, the staff finds that the applicant’s response to RAI 3.3-1, part (a) is 

acceptable. The staff’s concern in RAI 3.3-1, part (a) is resolved. Further, the staff accepts the 

applicant’s determination that LRA Table 3.2.1, item 3.2.1.21, is not applicable. 

LRA Table 3.2.1, item 3.2.1.22, addresses steel closure bolting, exposed to air with steam or 

water leakage, in the ESF systems. The GALL Report recommends use of GALL Report 

AMP XI.M18, “Bolting Integrity,” to manage loss of material due to general corrosion for this 

component group. The applicant stated that this item is not applicable because there is no 

closure bolting in its ESF exposed to an environment of “water [sic] with steam or water 

leakage.” By letter dated February 19, 2010, the staff issued RAI 3.3-1, part (b), requesting that 

the applicant correct an apparent wording error where the word “water” was incorrectly used in 

place of the word “air” The staff also asked that the applicant justify its claim that steel closure 

bolting in its ESF is not exposed to an environment of air with steam or water leakage. In its 

response, dated March 24, 2010, the applicant corrected the wording error in the LRA and 

stated that air with water leakage would be an event-driven environment, not considered normal 
Aging Management Review Results 

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for the ESF systems. The applicant also stated that for steel closure bolting, the aging effect 

and mechanism in LRA Table 3.2.1, item 3.2.1.22, is included in the aging effect and 

mechanism for LRA Table 3.2.1, item 3.2.1.23; the Bolting Integrity Program is credited in both 

lines to manage loss of material due to general corrosion for steel closure bolting. The applicant 

further stated that it evaluated all steel closure bolting in its ESF systems as part of LRA 

Table 3.2.1, item 3.2.1.23, rather than in item 3.2.1.22. The staff confirmed that, for steel 

closure bolting, the aging effect stated in LRA Table 3.2.1, item 3.2.1.22, is included in 

item 3.2.1.23, and that the Bolting Integrity Program is credited to manage loss of material for 

both items. The staff finds the applicant’s response to RAI 3.3-1, part (b) acceptable because it 

corrects the error and clarifies that components that could have been evaluated under 

item 3.2.1.22 are included in the evaluations under item 3.2.1.23. The staff’s concern in 

RAI 3.3-1, part (b) is resolved. The staff finds the applicant’s determination that LRA 

Table 3.2.1, item 3.2.1.22 is not applicable, to be acceptable. 

LRA Table 3.2.1, item 3.2.1.26 addresses steel piping, piping components, and piping elements 

exposed to closed-cycle cooling water subject to loss of material due to general, pitting, and 

crevice corrosion. The applicant stated that this item is not applicable because it has no 

in-scope steel piping, piping components, and piping elements exposed to closed-cycle cooling 

water in the ESF systems, so the applicable GALL Report line was not used. The staff reviewed 

LRA Sections 2.3.2 and 3.2 and confirmed that the applicant’s LRA does not have any AMR 

results for the ESF systems that include steel piping, piping components, and piping elements 

exposed to closed-cycle cooling water. The staff reviewed the applicant’s UFSAR and 

confirmed that no in-scope steel piping, piping components, and piping elements exposed to 

closed-cycle cooling water are present in these systems and, therefore, finds the applicant’s 

determination acceptable. 

LRA Table 3.2.1, item 3.2.1.29 addresses copper alloy piping, piping components, piping 

elements, and heat exchanger components exposed to closed-cycle cooling water subject to 

loss of material due to pitting, crevice, and galvanic corrosion for this component group. The 

applicant stated that this item is not applicable because it has no in-scope copper alloy piping, 

piping components, piping elements, and heat exchanger components exposed to closed-cycle 

cooling water in the ESF systems, so the applicable GALL Report lines were not used. The 

staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant’s LRA does not 

have any AMR results for the ESF systems that include copper alloy piping, piping components, 

piping elements, and heat exchanger components exposed to closed-cycle cooling water. The 

staff reviewed the applicant’s UFSAR and confirmed that no in-scope copper alloy piping, piping 

components, piping elements, and heat exchanger components exposed to closed-cycle cooling 

water are present in these systems and, therefore, finds the applicant’s determination 

acceptable. 

LRA Table 3.2.1, item 3.2.1.33 addresses steel encapsulation components exposed to 

air-indoor uncontrolled (internal) subject to loss of material due to general, pitting, and crevice 

corrosion. The applicant stated that this item is not applicable because it has no in-scope steel 

encapsulation components exposed to air-indoor uncontrolled (internal) in the ESF systems, so 

the applicable GALL Report line was not used. The staff reviewed LRA Sections 2.3.2 and 3.2 

and confirmed that the applicant’s LRA does not have any AMR results for the ESF that include 

steel encapsulation components exposed to air-indoor uncontrolled (internal). The staff 

reviewed the applicant’s UFSAR and confirmed that no in-scope steel encapsulation 

components exposed to air-indoor uncontrolled (internal) are present in these systems and, 

therefore, finds the applicant’s determination acceptable. 

LRA Table 3.2.1, item 3.2.1.35 addresses steel containment isolation piping and components 

internal surfaces exposed to raw water that are subject to loss of material due to general, pitting, 

crevice, and microbiologically-influenced corrosion and fouling. The applicant stated that this 
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item is not applicable because the containment isolation components were evaluated in the 

systems in which the components were found to have the function of containment integrity, so 

the applicable GALL Report line was not used. By letter dated January 28, 2010, the staff 

issued RAI 3.2.2-1 requesting the applicant to clarify the statement that the containment 

isolation components were evaluated in the system in which the components were found to 

have the function of containment integrity. In addition, the staff asked that the applicant provide 

additional information on the adequacy of the AMP used to manage steel containment isolation 

piping. 

In its response, dated March 1, 2010, the applicant stated that its plant equipment list does not 

contain a separate system for mechanical containment isolation components. As such, the 

applicant stated that the containment isolation components are evaluated as part of the plant 

system to which they are assigned and are consistent with the expectations in the GALL Report. 

For the ESF systems, the applicant stated that GALL Report, Table 3.2-1, item 3 summarizes 

the mechanical containment isolation components. Gall Report, Table 3.3-1, item 24 for 

auxiliary systems and Table 3.4-1, item 16, for steam and power conversion systems also 

recommend further evaluations for this item. The staff finds the applicant’s response acceptable 

because it clarified where and how it evaluated the associated items in the LRA. The staff’s 

concern described in RAI 3.2.2-1 is resolved. 

The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the LRA does not have any 

AMR results for the ESF systems that include steel containment isolation piping and 

components internal surfaces exposed to raw water. The staff reviewed the applicant’s UFSAR 

and confirmed no in-scope steel containment isolation piping and components internal surfaces 

exposed to raw water are present in these systems and, therefore, finds the applicant’s 

determination acceptable. 

LRA Table 3.2.1, item 3.2.1.36 addresses steel heat exchanger components exposed to raw 

water subject to loss of material due to general, pitting, crevice, galvanic, and 

microbiologically-influenced corrosion and fouling. The applicant stated that this item is not 

applicable because it has no in-scope steel heat exchanger components exposed to raw water 

in the ESF systems, so the applicable GALL Report lines were not used. The staff reviewed 

LRA Sections 2.3.2 and 3.2 and confirmed that the applicant’s LRA does not have any AMR 

results for the ESF systems that include steel heat exchanger components exposed to raw 

water. The staff reviewed the applicant’s UFSAR and confirmed that no in-scope steel heat 

exchanger components exposed to raw water are present in these systems and, therefore, finds 

the applicant’s determination acceptable. 

LRA Table 3.2.1, item 3.2.1.37 addresses stainless steel piping, piping components, and piping 

elements exposed to raw water subject to loss of material due to pitting, crevice, and 

microbiologically-influenced corrosion. The applicant stated that this item is not applicable 

because it has no in-scope stainless steel piping, piping components, and piping elements 

exposed to raw water in the ECCS, so the applicable GALL Report line was not used. The staff 

reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant’s LRA does not have any 

AMR results for the ECCS that include stainless steel piping, piping components, and piping 

elements exposed to raw water. The staff reviewed the applicant’s UFSAR and confirmed that 

no in-scope stainless steel piping, piping components, and piping elements exposed to raw 

water are present in these systems and, therefore, finds the applicant’s determination 

acceptable. 

LRA Table 3.2.1, item 3.2.1.38 addresses stainless steel containment isolation piping and 

component internal surfaces exposed to raw water, which are subject to loss of material due to 

pitting, crevice, and microbiologically-influenced corrosion and fouling. The applicant stated that 

this item is not applicable because it has no in-scope stainless steel components exposed to 

raw water in the ESF systems, so the applicable GALL Report line was not used. The staff 
Aging Management Review Results 

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reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant’s LRA does not have any 

AMR results for the ESF systems that include stainless steel containment isolation piping and 

components internal surfaces exposed to raw water. The staff reviewed the applicant’s UFSAR 

and confirmed that no in-scope stainless steel containment isolation piping and components 

internal surfaces exposed to raw water are present in these systems and, therefore, finds the 

applicant’s determination acceptable. 

LRA Table 3.2.1, item 3.2.1.39 addresses stainless steel heat exchanger components exposed 

to raw water subject to loss of material due to pitting, crevice, and microbiologically-influenced 

corrosion and fouling for this component group. The applicant stated that this item is not 

applicable because it has no in-scope stainless steel heat exchanger components exposed to 

raw water in the ESF systems, so the applicable GALL Report lines were not used. The staff 

reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant’s LRA does not have any 

AMR results for the ESF systems that include stainless steel heat exchanger components 

exposed to raw water. The staff reviewed the applicant’s UFSAR and confirmed that no 

in-scope stainless steel heat exchanger components exposed to raw water are present in these 

systems and, therefore, finds the applicant’s determination acceptable. 

LRA Table 3.2.1, item 3.2.1.40 addresses steel and stainless steel heat exchanger tubes 

(serviced by open-cycle cooling water) exposed to raw water subject to reduction of heat 

transfer due to fouling for this component group. The applicant stated that this item is not 

applicable because it has no in-scope steel and stainless steel heat exchanger tubes (serviced 

by open-cycle cooling water) exposed to raw water in the ESF systems, so the applicable GALL 

Report lines were not used. The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that 

the applicant’s LRA does not have any AMR results for the ESF systems that include steel and 

stainless steel heat exchanger tubes (serviced by open-cycle cooling water) exposed to raw 

water. The staff reviewed the applicant’s UFSAR and confirmed that no in-scope steel and 

stainless steel heat exchanger tubes (serviced by open-cycle cooling water) exposed to raw 

water are present in these systems and, therefore, finds the applicant’s determination 

acceptable. 

LRA Table 3.2.1, item 3.2.1.41 addresses copper alloy with greater than 15-percent zinc piping, 

piping components, piping elements, and heat exchanger components exposed to closed-cycle 

cooling water subject to loss of material due to selective leaching. The applicant stated that this 

item is not applicable because it has no in-scope copper alloy with greater than 15-percent zinc 

piping, piping components, piping elements, and heat exchanger components exposed to 

closed-cycle cooling water in the ESF systems, so the applicable GALL Report lines were not 

used. The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant’s LRA 

does not have any AMR results for the ESF system that include copper alloy with greater than 

15-percent zinc piping, piping components, piping elements, and heat exchanger components 

exposed to closed-cycle cooling water. The staff reviewed the applicant’s UFSAR and 

confirmed that no in-scope copper alloy with greater than 15-percent zinc piping, piping 

components, piping elements, and heat exchanger components exposed to closed-cycle cooling 

water are present in these systems and, therefore, finds the applicant’s determination 

acceptable. 

LRA Table 3.2.1, item 3.2.1.42 addresses gray cast iron piping, piping components, and piping 

elements exposed to closed-cycle cooling water subject to loss of material due to selective 

leaching. The applicant stated that this item is not applicable because it has no in-scope gray 

cast iron piping, piping components, and piping elements exposed to closed-cycle cooling water 

in the ESF systems, so the applicable GALL Report line was not used. The staff reviewed LRA 

Sections 2.3.2 and 3.2 and confirmed that the applicant’s LRA does not have any AMR results 

for the ESF system that include gray cast iron piping, piping components, and piping elements 

exposed to closed-cycle cooling water. The staff reviewed the applicant’s UFSAR and 
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confirmed that no in-scope gray cast iron piping, piping components, and piping elements 

exposed to closed-cycle cooling water are present in these systems and, therefore, finds the 

applicant’s determination acceptable. 

LRA Table 3.2.1, item 3.2.1.43 addresses gray cast iron piping, piping components, and piping 

elements exposed to soil subject to loss of material due to selective leaching. The applicant 

stated that this item is not applicable because it has no in-scope gray cast iron piping, piping 

components, and piping elements exposed to soil in the ESF systems, so it did not use the 

applicable GALL Report line. The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that 

the applicant’s LRA does not have any AMR results for the ESF system that include gray cast 

iron piping, piping components, and piping elements exposed to soil. The staff reviewed the 

applicant’s UFSAR and confirmed that no in-scope gray cast iron piping, piping components, 

and piping elements exposed to soil are present in these systems and, therefore, it finds the 

applicant’s determination acceptable. 

LRA Table 3.2.1, item 3.2.1.44 addresses gray cast iron motor cooler exposed to treated water 

subject to loss of material due to selective leaching. The applicant stated that this item is not 

applicable because it has no in-scope gray cast iron motor cooler exposed to treated water in 

the ESF systems, so the applicable GALL Report lines were not used. The staff reviewed LRA 

Sections 2.3.2 and 3.2 and confirmed that the applicant’s LRA does not have any AMR results 

for the ESF system that include gray cast iron motor cooler exposed to treated water. The staff 

reviewed the applicant’s UFSAR and confirmed that no in-scope gray cast iron motor cooler 

exposed to treated water are present in these systems and, therefore, it finds the applicant’s 

determination acceptable. 

LRA Table 3.2.1, item 3.2.1.46 addresses steel encapsulation components exposed to air with 

borated water leakage (internal) subject to loss of material due to general, pitting, crevice, and 

boric acid corrosion. The applicant stated that this item is not applicable because it has no 

in-scope steel encapsulation components exposed to air with borated water leakage (internal) in 

the ESF systems, so the applicable GALL Report line was not used. The staff reviewed LRA 

Sections 2.3.2 and 3.2 and confirmed that the applicant’s LRA does not have any AMR results 

for the ESF systems that include steel encapsulation components exposed to air with borated 

water leakage (internal). The staff reviewed the applicant’s UFSAR and confirmed that no 

in-scope steel encapsulation components exposed to air with borated water leakage (internal) 

are present in these systems and, therefore, finds the applicant’s determination acceptable. 

LRA Table 3.2.1, item 3.2.1.47 addresses CASS piping, piping components, and piping 

elements exposed to treated borated water greater than 250 degrees C (greater than 

482 degrees F) subject to loss of fracture toughness due to thermal-aging embrittlement. The 

applicant stated that this item is not applicable because it has no in-scope CASS piping, piping 

components, and piping elements exposed to treated borated water greater than 250 degrees C 

in the ECCS, so the applicable GALL Report line was not used. The staff reviewed LRA 

Sections 2.3.2 and 3.2 and confirmed that the applicant’s LRA does not have any AMR results 

for the ESF systems that include CASS piping, piping components, and piping elements 

exposed to treated borated water greater than 250 degrees C (greater than 482 degrees F). 

The staff reviewed the applicant’s UFSAR and confirmed that no in-scope CASS piping, piping 

components, and piping elements exposed to treated borated greater than 250 degrees C 

(greater than 482 degrees F) are present in these systems and, therefore, finds the applicant’s 

determination acceptable. 

LRA Table 3.2.1, item 3.2.1.54 addresses steel piping, piping components, and piping elements 

exposed to air-indoor controlled (external). The GALL Report recommends that there is no 

aging effect requiring management. The applicant stated that this item is not applicable 

because it has no in-scope steel piping, piping components, and piping elements exposed to 

air-indoor controlled (external) in the ESF systems, so the applicable GALL Report line was not 
Aging Management Review Results 

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used. The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant’s LRA 

does not have any AMR results for the ESF systems that include steel piping, piping 

components, and piping elements exposed to air-indoor controlled (external). The staff 

reviewed the applicant’s UFSAR and confirmed that no in-scope steel piping, piping 

components, and piping elements exposed to air-indoor controlled (external) are present in the 

systems and, therefore, finds the applicant’s determination acceptable. 

3.2.2.1.2 Loss of Material Due to Boric Acid Corrosion 

LRA Table 3.2.1, item 3.2.1.49 addresses stainless steel piping, piping components, piping 

elements, and tanks exposed to treated borated water, which are managed for loss of material 

due to pitting and crevice corrosion. The LRA credits the Water Chemistry Program to manage 

this aging effect. The GALL Report recommends AMP XI.M2, “Water Chemistry Program,” to 

ensure that this aging effect is adequately managed. The AMR item cites generic note A, 

indicating that the item is consistent with the GALL Report item for component, material, 

environment, and aging effect, and the LRA AMP is consistent with the GALL Report AMP. 

In its review of components subordinate to item 3.2.1.49, for which the applicant assigned 

generic note A for the heat exchanger (shutdown cooling), the staff noted that the GALL Report, 

under items V.A-27 and V.D1-30, is for stainless steel material. The shutdown cooling heat 

exchanger is a carbon steel heat exchanger clad with stainless steel, which is not the same 

material as indicated in the GALL Report. By letter dated December 29, 2009, the staff issued 

RAI B2.1.4-1 requesting that the applicant justify why the Water Chemistry Program is more 

appropriate than the Boric Acid Corrosion Control Program to manage the clad carbon steel. 

In its response, dated February 19, 2010, the applicant described the environments and 

potential degradation effects for the material types composing the heat exchanger and 

explained the selection of AMPs for each of those material types and environmental 

combinations. The applicant also stated that the exterior carbon steel surfaces of the heat 

exchanger are potentially susceptible to corrosion in the event of boric acid leakage and that the 

Boric Acid Corrosion Program will manage component materials. In addition, the applicant 

provided justification for the use of other AMPs to cover the remaining construction materials of 

the heat exchanger. 

The applicant’s response reported that the LRA was revised in Amendment No. 9 to reflect AMP 

selections for the individual shutdown cooling heat exchanger components, as described above. 

Specifically, LRA Table 3.2.2-4 was revised to add GALL Report, Table 2, item 3.2.1.45 for loss 

of material on the carbon steel exterior surfaces for the shutdown cooling heat exchanger 

exposed to an environment of borated water leakage, managed by the Boric Acid Corrosion 

Program. In addition, LRA Table 3.2.2-4 was revised to change the standard note from “A” to 

“C” for the AMR results associated with loss of material and cracking of the stainless steel 

cladding of the shutdown cooling heat exchanger channel cylinder and tubesheet, exposed to 

treated borated water, managed by the Water Chemistry Program. 

The staff verified that the noted changes to the LRA were provided in Amendment No. 9 of 

Enclosure 2 of its above response. Based on its review, the staff finds the applicant’s response 

to RAI B2.1.4-1 acceptable because the amended LRA added Table 3.2.1, item 3.2.1.45 to 

account for the potential loss of material for the shutdown cooling heat exchanger’s exterior 

carbon steel surfaces due to borated water leakage. The staff’s concern in RAI B2.1.4-1 is 

resolved. 

The staff concludes that the applicant has demonstrated that it will adequately manage the 

effects of aging for the subject components so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3). 
Aging Management Review Results 

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3.2.2.2 Aging Management Review Results Consistent with the Generic Aging Lessons 

Learned Report for Which Further Evaluation Is Recommended 

In LRA Section 3.2.2.2, the applicant further evaluates aging management, as recommended by 

the GALL Report, for the ESF systems components and provides information concerning how it 

will manage the following aging effects: 

 cumulative fatigue damage 

 loss of material due to cladding 

 loss of material due to pitting and crevice corrosion 

 reduction of heat transfer due to fouling 

 hardening and loss of strength due to elastomer degradation 

 loss of material due to erosion 

 loss of material due to general corrosion and fouling 

 loss of material due to general, pitting, and crevice corrosion 

 loss of material due to general, pitting, crevice, and microbiologically-influenced 

corrosion 

 QA for aging management of nonsafety-related components 

For component groups evaluated in the GALL Report, for which the applicant claimed 

consistency with the report and for which the report recommends further evaluation, the staff 

reviewed the applicant’s evaluation to determine if it adequately addressed the issues further 

evaluated. In addition, the staff reviewed the applicant’s further evaluations against the criteria 

contained in SRP-LR Section 3.2.2.2. The staff’s review of the applicant’s further evaluation 

follows. 

3.2.2.2.1 Cumulative Fatigue Damage 

In LRA Section 3.2.2.2.1, the applicant stated that the evaluation of fatigue is a TLAA, as 

defined in 10 CFR 54.3, and TLAAs are evaluated in accordance with 10 CFR 54.21(c)(1). The 

applicant further stated that its piping, designed to ASME III Class 2, Class 3, and ANSI B31.1 

standards, assumes a reduction in the allowable secondary stress range if more than 

7,000 full-range thermal cycles are expected in a design lifetime. LRA Section 4.3.5 describes 

the evaluation of these cyclic-design TLAAs. The applicant further stated that HPSI and low 

pressure safety injection pumps are ASME III Class 2 components, designed with a specified 

number of thermal transient cycles. LRA Section 4.3.2.11 describes the evaluation of these 

cyclic-design TLAAs. 

The staff reviewed LRA Section 3.2.2.2.1 against the criteria in SRP-LR Section 3.2.2.2.1. 

Fatigue is a TLAA, as defined in 10 CFR 54.3. TLAAs are required to be evaluated in 

accordance with 10 CFR 54.21(c)(1). Section 4.3, “Metal Fatigue Analysis,” of the SRP-LR 

addresses this TLAA separately. The staff finds the applicant’s AMR results are consistent with 

the recommendations of the GALL Report and SRP-LR, except for the following identified areas. 

The staff noted that the summary description in LRA Section 4.3.5 states that the implicit fatigue 

analyses, discussed in the section, are applicable to all ASME Code Class 2 and 3 and ANSI 

B31.1 piping, piping components, and piping elements. The staff noted that it is not clear if the 

LRA includes all corresponding AMR items for applicable ASME Code Class 2 and 3 or 

ANSI B31.1 piping, piping components, and piping elements in scope for license renewal. The 

staff also noted that this includes those components in the ESF systems (LRA Section 3.2), 

auxiliary systems (LRA Section 3.3), and steam and power conversion systems (LRA 
Aging Management Review Results 

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Section 3.4). By letter dated July 21, 2010 the staff issued RAI 4.3-13 asked the applicant to 

clarify if the LRA includes all applicable AMR items with an aging effect of cumulative fatigue 

damage for those components in scope for license renewal. If not, the staff asked the applicant 

to explain why the LRA does not include all corresponding AMR items on cumulative fatigue 

damage for applicable ASME Code Class 2 and 3 or ANSI B31.1 piping, piping components, 

and piping elements in scope for license renewal. The staff also asked the applicant to identify 

all component types that are within the scope of the implicit fatigue analyses for ASME Code 

Class 2 and 3 components and B31.1 components in LRA Section 4.3.5. The staff previously 

identified this as Open Item 4.3-1. 

In its response dated August 12, 2010, the applicant stated that, for the ESF systems, no 

additions are required because LRA Table 3.2.2-4 includes AMR items with an aging effect of 

cumulative fatigue damage. The staff reviewed LRA Table 3.2.2-4 and confirmed that it 

contains applicable AMR items associated with the aging effect of cumulative fatigue damage 

for piping and piping components. 

Based on its review, the staff finds the applicant’s response to RAI 4.3-13, part 3, related to LRA 

Section 3.2.2.2.1, acceptable because the applicant confirmed that no additional AMR items 

associated with ASME Code Class 2 and 3 or ANSI B31.1 piping, piping components, and 

piping elements were subject to aging management review in accordance with 10 CFR 

Part 54.21(a)(1). The staff confirmed that the applicant included AMR items associated with 

ASME Code Class 2 and 3 or ANSI B31.1 piping, piping components, and piping elements with 

an aging effect of cumulative fatigue damage in LRA Table 3.2.2-4. The staff’s concern 

described in RAI 4.3-13 is resolved, and this portion of the Open Item is closed. 

Based on its review, the staff concludes that the applicant’s proposal to manage cumulative 

fatigue damage in ASME III Class 2, Class 3, and ANSI B31.1 components meets the SRP-LR 

Section 3.2.2.2.1 criteria. For those line items that apply to LRA Section 3.2.2.2.1, the staff 

determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). SER Section 4.3 documents the staff’s review of the 

applicant’s evaluation of the TLAA for these components. 

3.2.2.2.2 Loss of Material Due to Cladding 

LRA Section 3.2.2.2.2 addresses stainless steel clad pump casings exposed to treated borated 

water in the ECCS. The GALL Report recommends use of a plant-specific AMP to manage the 

loss of material due to cladding breach for this component group. The applicant stated that this 

item is not applicable because it has no in-scope steel pump casings clad with stainless steel 

exposed to treated borated water in the ECCS. The staff reviewed LRA Sections 2.3.2 and 3.2 

and confirmed that the applicant’s LRA does not have any AMR results for the ECCS that 

include steel pump casings with stainless steel cladding exposed to treated borated water. The 

staff reviewed the applicant’s UFSAR and confirmed that there are no in-scope steel pump 

casings with stainless cladding exposed to treated borated water in the ECCS systems and, 

therefore, finds the applicant’s determination acceptable. 

3.2.2.2.3 Loss of Material Due to Pitting and Crevice Corrosion 

The staff reviewed LRA Section 3.2.2.2.3 against the following criteria in the SRP-LR 

Section 3.2.2.2.3: 

 LRA Section 3.2.2.2.3.1 addresses the loss of material due to pitting and crevice 

corrosion of internal surfaces for stainless steel containment isolation components 

exposed to treated water in the ESF systems. The applicant indicated that this item is 
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not applicable because there are no stainless steel components within the scope of 

license renewal exposed to treated water in the ESF systems. 

 The staff reviewed the LRA Table 3.2.2-4 for the safety injection and shutdown cooling 

system and, contrary to the applicant’s statement, noted that the safety injection and 

shutdown cooling system has stainless steel piping in a treated (demineralized) water 

environment. The staff further noted the applicant’s intent to evaluate the related items 

with the Water Chemistry and One-Time Inspection Programs, is appropriate; however, 

the applicant’s statement that this item is “not applicable” appeared incorrect. In order to 

resolve this issue, the staff held a teleconference with the applicant on March 12, 2010, 

wherein the applicant indicated it was revising this section of the LRA. 

 In a letter dated April 1, 2010, the applicant modified LRA Section 3.2.2.2.3.1 by deleting 

the “not applicable” aspect. It added that the Water Chemistry and One-Time Inspection 

Programs will manage the loss of material due to pitting and crevice corrosion for 

stainless steel containment isolation piping and components exposed to treated water, 

including demineralized water. The applicant further stated that the One-Time 

Inspection Program will include selected components at susceptible locations where 

contaminants could accumulate. 

 The staff finds the applicant’s response acceptable because the applicant corrected its 

LRA by recognizing that this item was applicable and by describing how it will manage 

the loss of material due to pitting and crevice corrosion for stainless steel containment 

isolation piping and components exposed to treated water. The staff’s concern 

described in the above discussion is resolved. 

 The staff reviewed LRA Section 3.2.2.2.3.1 against the criteria in SRP-LR 

Section 3.2.2.2.3.1, which states that loss of material due to pitting and crevice corrosion 

could occur on the internal surfaces of stainless steel components for containment 

isolation piping, piping components, and piping elements exposed to treated water. The 

SRP-LR notes that monitoring and control of water chemistry will mitigate degradation; 

however, water chemistry control does not preclude this aging effect in locations with 

stagnant flow conditions. It continues by stating that the applicant should verify the 

effectiveness of the Water Chemistry Control Program and that a one-time inspection at 

susceptible locations is an acceptable method. 

 SER Sections 3.0.3.2.1 and 3.0.3.1.6 document the staff’s evaluation of the applicant’s 

Water Chemistry and One-Time Inspection Programs, respectively. The staff finds the 

applicant’s proposal to manage aging using the Water Chemistry Control Program, 

augmented by the One-Time Inspection Program, acceptable because the applicant’s 

Water Chemistry Program limits the concentrations of chemical species known to cause 

corrosion and adds chemical species known to inhibit degradation. In addition, the staff 

notes that the One-Time Inspection Program verifies the effectiveness of the Water 

Chemistry Program and evaluates aging effects, including loss of material. 

 Based on the programs identified, the staff concludes that the applicant meets SRP-LR 

Section 3.2.2.2.3.1 criteria. For those items that apply to LRA Section 3.2.2.2.3.1, the 

staff determines that the LRA is consistent with the GALL Report. The applicant has 

demonstrated that it will adequately manage the effects of aging so that the intended 

functions will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

 LRA Section 3.2.2.2.3.2 addresses loss of material due to pitting and crevice corrosion 

in stainless steel piping, piping components, and piping elements exposed to soil. The 

applicant stated that this item is not applicable because the ECCS does not contain 

stainless steel piping, piping components, and piping elements in a soil environment. 
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The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant’s LRA 

does not have any AMR results for the ECCS that include stainless steel piping, piping 

components, and piping elements exposed to soil. The staff reviewed the applicant’s 

UFSAR and confirmed that no in-scope stainless steel piping, piping components, and 

piping elements exposed to soil are present in the ECCS and, therefore, finds the 

applicant’s determination acceptable. 

 LRA Section 3.2.2.2.3.3 addresses loss of material due to pitting and crevice corrosion 

in BWR stainless steel and aluminum piping, stating that this aging effect is not 

applicable since it is applicable to BWRs only. SRP-LR Section 3.2.2.2.3 states that loss 

of material due to pitting and crevice corrosion may occur in BWR stainless steel and 

aluminum piping, piping components, and piping elements exposed to treated water. 

The staff finds that SRP-LR Section 3.2.2.2.3, item 3 is not applicable because the 

PVNGS units are PWRs, and the staff guidance in this SRP-LR section is only 

applicable to BWRs. 

 LRA Section 3.2.2.2.3.4 addresses stainless steel and copper alloy piping, piping 

components, and elements exposed to lubricating oil. The GALL Report recommends 

use of GALL AMPs XI.M39, “Lubricating Oil Analysis,” and XI.M32, “One-Time 

Inspection” to manage loss of material due to pitting and crevice corrosion for this 

component group. The applicant stated that this item is not applicable because “PVNGS 

has no in-scope stainless steel and copper alloy piping, piping components, and piping 

elements exposed to lubricating oil.” The staff reviewed LRA Sections 2.3.2 and 3.2 and 

confirmed that the applicant’s LRA does not have any AMR results for the ESF systems 

that include stainless steel and copper alloy components exposed to lube oil in the ESF 

systems. The staff also reviewed the UFSAR to verify the same. Based on its review of 

the LRA and UFSAR, the staff confirmed that the applicant’s plant does not have any 

in-scope stainless steel and copper alloy piping, piping components, and piping 

elements exposed to lubricating oil ESF systems and, therefore, finds the applicant’s 

determination acceptable. 

 LRA Section 3.2.2.2.3.5 addresses loss of material due to pitting and crevice corrosion 

in partially encased stainless steel tanks exposed to raw water. The applicant stated 

that this item is not applicable because the ECCS does not have any in-scope stainless 

steel tanks with a moisture barrier configuration in a raw water environment. The staff 

reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant’s LRA does not 

have any AMR results for the ECCS that include stainless steel tanks exposed to raw 

water. The staff reviewed the applicant’s UFSAR and confirmed that no in-scope 

stainless steel tanks exposed to raw water are present in the ECCS and, therefore, finds 

the applicant’s determination acceptable. 

 LRA Section 3.2.2.2.3.6 addresses the loss of material due to pitting and crevice 

corrosion of the stainless steel piping, components, and tanks exposed to internal 

condensation. The applicant indicated that the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program will manage this aging issue. 

 The staff reviewed LRA Section 3.2.2.2.3.6 against the criteria in SRP-LR 

Section 3.2.2.2.3.6, which states that loss of material due to pitting and crevice corrosion 

could occur for stainless steel piping, piping components, piping elements, and tanks 

exposed to internal condensation. The SRP-LR further indicates that a plant-specific 

program is to manage this aging issue. 

 SER Section 3.0.3.2.15 documents the staff’s review of the applicant’s Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The staff 

noted that the applicant’s program includes stainless steel materials and performs visual 
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inspections to detect loss of material. The staff finds the applicant’s use of the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program acceptable to manage the loss of material due to pitting and corrosion, 

because the program includes the relevant material and performs appropriate 

inspections capable of detecting this aging effect. 

 Based on the program identified, the staff concludes that the applicant’s program meets 

SRP-LR Section 3.2.2.2.3.6 criteria. For those items that apply to LRA 

Section 3.2.2.2.3.6, the staff determines that the LRA is consistent with the GALL 

Report. The applicant has demonstrated that it will adequately manage the effects of 

aging so that the intended functions will be maintained consistent with the CLB during 

the period of extended operation, as required by 10 CFR 54.21(a)(3). 

Based on the programs identified above, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.2.2.2.3 criteria. For those items that apply to LRA Section 3.2.2.2.3, the staff 

determines that the LRA is consistent with the GALL Report. The staff also finds that the 

applicant has demonstrated that it will adequately manage the effects of aging so that the 

intended function(s) will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

3.2.2.2.4 Reduction of Heat Transfer Due to Fouling 

The staff reviewed LRA Section 3.2.2.2.4 against the following criteria in the SRP-LR 

Section 3.2.2.2.4: 

 LRA Section 3.2.2.2.4.1 addresses the reduction of heat transfer due to fouling of steel, 

stainless steel, and copper alloy heat exchanger tubes exposed to lubricating oil for ESF 

systems. The applicant stated that this item is not applicable because PVNGS has no 

in-scope steel, stainless steel, and copper alloy heat exchanger tubes exposed to 

lubricating oil in the ESF systems. The staff reviewed LRA Sections 2.3.2 and 3.2 and 

confirmed that the applicant’s LRA does not have any AMR results for the ESF systems 

that include steel, stainless steel, and copper alloy heat exchanger tubes exposed to 

lubricating oil. The staff reviewed the UFSAR and confirmed that there are no in-scope 

heat exchangers constructed of steel, stainless steel, or copper alloy exposed to 

lubricating oil in the ESF systems and, therefore, finds the applicant’s determination 

acceptable. 

 LRA Section 3.2.2.2.4.2 addresses the reduction of heat transfer due to fouling of 

stainless steel heat exchanger tubes exposed to treated water for ESF systems. The 

applicant stated that this item is not applicable because PVNGS has no in-scope 

stainless steel heat exchanger tubes exposed to treated water with the aging effect of 

reduction of heat transfer in the ESF systems. The staff reviewed LRA Sections 2.3.2 

and 3.2 and confirmed that the applicant’s LRA does not have any AMR results for the 

ESF systems that include stainless steel heat exchanger tubes exposed to treated 

water. The staff reviewed the UFSAR and confirmed that no in-scope heat exchangers 

constructed of stainless steel exposed to treated water are present in the ESF systems, 

therefore, finds the applicant’s determination acceptable. 

Based on the programs identified above, the staff concludes that the applicant meets SRP-LR 

Section 3.2.2.2.4 criteria. For those items that apply to LRA Section 3.2.2.2.4, the staff 

determines that the LRA is consistent with the GALL Report. In addition, the applicant has 

demonstrated that it will adequately manage the effects of aging so that the intended function(s) 

will be maintained consistent with the CLB during the period of extended operation, as required 

by 10 CFR 54.21(a)(3). 
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3.2.2.2.5 Hardening and Loss of Strength Due to Elastomer Degradation 

The staff reviewed LRA Section 3.2.2.2.5 against the criteria in the SRP-LR Section 3.2.2.2.5. 

LRA Section 3.2.2.2.5 addresses hardening and loss of strength due to elastomer degradation, 

stating that this aging effect is not applicable since it is only applicable to BWRs. The SRP-LR 

Section 3.2.2.2.5 states that hardening and loss of strength due to elastomer degradation may 

occur in elastomer seals and components of the BWR standby gas treatment system ductwork 

and filters exposed to air-indoor uncontrolled. The staff finds that SRP-LR Section 3.2.2.2.5 is 

not applicable because the PVNGS units are PWRs, and the staff guidance in this SRP-LR 

section is applicable to components within the standby gas treatment system in BWRs. 

3.2.2.2.6 Loss of Material Due to Erosion 

LRA Section 3.2.2.2.6 addresses the stainless steel minimum flow recirculation line orifice for 

the HPSI pump exposed to treated borated water. The GALL Report recommends a 

plant-specific AMP to evaluate for erosion of the orifice due to extended use of the centrifugal 

HPSI pump for normal charging. The applicant stated that this item is not applicable because 

PVNGS does not use the HPSI pumps for normal charging. The staff reviewed the applicant’s 

UFSAR and confirmed that the HPSI pumps are isolated from the RCS during normal operation. 

Because the applicant does not use HPSI pumps for normal charging, erosion of the HPSI 

minimum flow recirculation line orifice is not likely to occur and, therefore, the applicant’s 

determination is acceptable. 

3.2.2.2.7 Loss of Material Due to General Corrosion and Fouling 

LRA Section 3.2.2.2.7 addresses loss of material due to general corrosion and fouling on steel 

drywell and suppression chamber spray system nozzle and flow orifice internal surfaces 

exposed to air-indoor uncontrolled. This section states that this aging effect is not applicable; it 

is applicable to BWRs only. SRP-LR Section 3.2.2.2.7 states that loss of material due to 

general corrosion and fouling may occur on steel drywell and suppression chamber spray 

system nozzle and flow orifice internal surfaces exposed to air-indoor uncontrolled and may 

cause plugging of the spray nozzles and flow orifices. The staff finds that SRP-LR 

Section 3.2.2.2.7 is not applicable because the PVNGS units are PWRs, and the staff guidance 

in this SRP-LR section is only applicable to drywell and suppression chamber spray systems in 

BWRs. 

3.2.2.2.8 Loss of Material Due to General, Pitting, and Crevice Corrosion 

The staff reviewed LRA Section 3.2.2.2.8 against the following criteria in the SRP-LR 

Section 3.2.2.2.8: 

 LRA Section 3.2.2.2.8.1 addresses loss of material due to general, pitting, and crevice 

corrosion in BWR steel piping, piping components, and piping elements exposed to 

treated water. This section states that this aging effect is not applicable; it is applicable 

to BWRs only. SRP-LR Section 3.2.2.2.8 states that loss of material due to general, 

pitting, and crevice corrosion may occur in BWR steel piping, piping components, and 

piping elements exposed to treated water. The staff finds that SRP-LR Section 3.2.2.2.8 

is not applicable to PVNGS because the PVNGS units are PWRs, and the staff guidance 

in this SRP-LR section is only applicable to steel piping, piping components, and piping 

elements exposed to treated water in BWRs. 

 LRA Section 3.2.2.2.8.2 addresses the loss of material due to general, pitting and 

crevice corrosion from the internal surfaces of steel containment isolation piping and 

components exposed to treated water. The applicant stated that this item is not 

applicable, because it evaluated the containment isolation components in the systems in 

which the components were found to have the function of containment integrity. By 
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letter dated January 28, 2010, the staff issued RAI 3.2.2-1 requesting the applicant to 

clarify what it meant by the statement that it evaluated the containment isolation 

components n the system in which the components were found to have the function of 

containment integrity. In addition, the staff requested that the applicant provide 

additional information on the adequacy of the AMPs used to manage steel containment 

isolation piping. 

 In its response, dated March 1, 2010, the applicant stated that the plant equipment list 

does not contain a separate system for mechanical containment isolation components. 

As such, the applicant indicated that it evaluates the containment isolation components 

as part of the plant equipment list system to which they are assigned and are consistent 

with the expectations in the GALL Report. For the ESF systems, the applicant stated 

that GALL Report Table 3.2-1, item 3 summarizes the mechanical containment isolation 

components and that Table 3.3-1, item 24 for auxiliary systems and Table 3.4-1, item 16 

for steam and power conversion systems recommend further evaluations for this item. 

The staff finds the applicant’s response acceptable because it clarified where and how it 

evaluated the associated items in the LRA. The staff’s concern described in RAI 3.2.2-1 

is resolved. 

 The staff reviewed LRA 2.3.2 and 3.2 and confirmed that the applicant’s LRA does not 

have any AMR results for the ESF systems that include steel containment isolation 

piping, piping components, and piping elements exposed to treated water. The staff 

reviewed the applicant’s UFSAR and confirmed no in-scope steel containment isolation 

piping, piping components, and piping elements exposed to treated water are present in 

the ESF systems and, therefore, the staff finds the applicant’s determination acceptable. 

 LRA Section 3.2.2.2.8.3 addresses carbon steel piping, piping components and 

elements exposed to lubricating oil. The GALL Report recommends use of GALL AMPs 

XI.M39, “Lubricating Oil Analysis,” and XI.M32, “One-Time Inspection” to manage loss of 

material due to general, pitting, and crevice corrosion for this component group. The 

applicant stated that this item is not applicable because “PVNGS has no in-scope carbon 

steel components exposed to lubricating oil in the ESF systems, so the applicable GALL 

Report lines were not used.” The staff reviewed LRA Sections 2.3.2 and 3.2 and 

confirmed that the applicant’s LRA does not have any AMR results for the ESF systems 

that include steel components exposed to lube oil in the ESF systems. The staff also 

reviewed the UFSAR to verify the same. Based on its review of the LRA and UFSAR, 

the staff finds the applicant’s determination acceptable. 

Based on the programs identified above, the staff concludes that the applicant meets SRP-LR 

Section 3.2.2.2.8 criteria. For those items that apply to LRA Section 3.2.2.2.8, the staff 

determines that the LRA is consistent with the GALL Report. Further, the applicant has 

demonstrated that it will adequately manage the effects of aging so that the intended function(s) 

will be maintained consistent with the CLB during the period of extended operation, as required 

by 10 CFR 54.21(a)(3). 

3.2.2.2.9 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion 

LRA Section 3.2.2.2.9 addresses loss of material due to general, pitting, crevice, and 

microbiologically-influenced corrosion in steel piping, piping components, and piping elements, 

with or without coating or wrapping, buried in soil. The applicant stated that this item is only 

applicable to BWRs. The staff reviewed SRP-LR Section 3.2.2.2.9 and Table 3.2-1, which 

refers to the GALL Report item E-42. The staff reviewed the GALL Report Table V.B. and 

confirmed that it is only applicable to the standby gas treatment system for BWR plants. The 

staff finds the applicant’s determination acceptable. 
Aging Management Review Results 

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3.2.2.2.10 Quality Assurance for Aging Management of Nonsafety-Related Components 

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA program. 

3.2.2.3 Aging Management Review Results Not Consistent with or Not Addressed in 

the Generic Aging Lessons Learned Report 

In LRA Tables 3.2.2-1 through 3.2.2-4, the staff reviewed additional details of the AMR results 

for material, environment, AERM, and AMP combinations not consistent with, or not addressed 

in, the GALL Report. 

In LRA Tables 3.2.2-1 through 3.2.2-4, the applicant indicated, using Notes F–J, which 

combinations of component type, material, environment, and AERM do not correspond to an 

item in the GALL Report. The applicant provided information about how it will manage the aging 

effects. Specifically, Note F indicates that the material for the AMR item component is not 

evaluated in the GALL Report. Note G indicates that the environment for the AMR item 

component and material is not evaluated in the GALL Report. Note H indicates that the aging 

effect for the AMR item component, material, and environment combination is not evaluated in 

the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the 

item component, material, and environment combination is not applicable. Note J indicates that 

neither the component nor the material and environment combination for the item is evaluated in 

the GALL Report. 

For component type, material, and environment combinations not evaluated in the GALL 

Report, the staff reviewed the applicant’s evaluation to determine if the applicant has 

demonstrated that it will adequately manage the effects of aging so that the intended function(s) 

will be maintained consistent with the CLB for the period of extended operation. The staff’s 

evaluation is documented in the following sections. 

3.2.2.3.1 Containment Leak Test System—Summary of Aging Management Review—License 

Renewal Application Table 3.2.2-1 

The staff reviewed LRA Table 3.2.2-1, which summarize the results of AMR evaluations for the 

containment leak test system component groups. The staff’s review did not identify any items 

with notes F–J, indicating that the combinations of component type, material, environment, and 

AERM for this system are consistent with the GALL Report. 

SER Section 3.0.2.2 documents the staff’s evaluation of the items with Notes A–E. 

3.2.2.3.2 Containment Purge System—Summary of Aging Management Review—License 

Renewal Application Table 3.2.2-2 

The staff reviewed LRA Table 3.2.2-2, which summarizes the results of AMR evaluations for the 

containment purge system component groups. 

In LRA Table 3.2.2-2, the applicant stated that the Bolting Integrity Program manages carbon 

steel closure bolting exposed to atmosphere or weather, for loss of preload. In LRA 

Table 3.2.2-3, the applicant also stated that the Bolting Integrity Program manages stainless 

steel closure bolting, exposed to plant indoor air, for loss of preload. The AMR items cite 

generic note G, indicating that the environment is not in the GALL Report for this component 

and material combination. The applicant also cited plant-specific note 1, stating that loss of 

preload is considered applicable for all closure bolting. The staff reviewed all AMR result lines 

in the GALL Report where the aging effect is loss of preload and confirmed there are no AMR 

results for carbon steel bolting in an environment of atmosphere or weather or for stainless steel 

bolting in an environment of plant indoor air. 

SER Section 3.0.3.2.3 documents the staff’s evaluation of the applicant’s Bolting Integrity 

Program. The staff noted that the mechanisms listed in the GALL Report that cause loss of 
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preload are thermal effects, gasket creep, and self-loosening, and that these aging effects are 

not dependent on the specific bolting material or environment. The staff also noted that 

activities in the Bolting Integrity Program that manage loss of preload are equally effective for 

carbon steel and stainless steel bolts. The staff further noted that the GALL Report 

recommends using the Bolting Integrity Program to manage loss of preload in carbon steel bolts 

exposed to air-indoor uncontrolled. The staff finds the applicant’s use of the Bolting Integrity 

Program to manage loss of preload in carbon steel and stainless steel closure bolting 

acceptable because it is consistent with the GALL Report recommendations for managing loss 

of preload in carbon steel closure bolting exposed to air. In addition, the Bolting Integrity 

Program’s activities for managing loss of preload are applicable for both carbon steel and 

stainless steel bolts. 

Based on its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that it will adequately manage the 

effects of aging so that the intended function(s) will be maintained consistent with the CLB for 

the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.2.2.3.3 Containment Hydrogen Control System–Summary of Aging Management Review–

License Renewal Application Table 3.2.2-3 

The staff reviewed LRA Table 3.2.2-3, which summarizes the results of AMR evaluations for the 

containment hydrogen control system component groups. 

SER Section 3.2.2.3.2 documents the staff’s evaluation for stainless steel closure bolting 

exposed to plant indoor air being managed for loss of preload by the Bolting Integrity Program, 

citing generic note G. 

In LRA Table 3.2.2-3, the applicant stated that for nickel-alloy flexible hoses exposed internally 

to dry gas, there is no aging effect and no AMP is proposed. The AMR item cites generic 

Note G, indicating that for the item, the environment is not in the GALL Report for this 

component and material. 

The staff reviewed the associated items in the LRA and confirmed that no aging effect is 

applicable for this component, material, and environment because austenitic materials such as 

nickel alloys are not subject to loss of material or cracking when exposed to this environment, 

and these materials are used as corrosion-resistant replacement materials where other 

materials have degraded. The staff noted that corrosion-resistant materials, such as austenitic 

and martensitic stainless steels and high strength nickel base alloys, offer good protection 

against loss of material. The staff also noted that the conditions required for cracking, due to a 

variety of mechanisms (SCC, PWSCC, IASCC and IGSCC) to occur, such as being exposed to 

an aqueous solution (reactor coolant or other corrosive solutions) and high temperatures, do not 

exist on the surfaces of these components when exposed to dry gas. The staff noted that GALL 

Report AMR item IV.E-1 states that nickel alloy exposed to air-indoor uncontrolled is not subject 

to an AERM. The staff noted that an air-indoor uncontrolled environment is more aggressive 

than a dry gas environment because it is possible for condensation to occur in an air-indoor 

uncontrolled environment. The staff finds the applicant’s determination acceptable because 

nickel alloy is a highly corrosion resistant material and is not subject to conditions where 

cracking is possible. In addition, this component is exposed to a less aggressive environment 

when compared to GALL, AMR item IV.E-1, for which there is no AERM. 

Based on its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that it will adequately manage the 

effects of aging so that the intended function(s) will be maintained consistent with the CLB for 

the period of extended operation, as required by 10 CFR 54.21(a)(3). 
Aging Management Review Results 

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3.2.2.3.4 Safety Injection and Shutdown Cooling System—Summary of Aging Management 

Review—License Renewal Application Table 3.2.2-4 

The staff reviewed LRA Table 3.2.2-4, which summarizes the results of AMR evaluations for the 

safety injection and shutdown cooling system component groups. 

In LRA Table 3.2.2-4, the applicant stated that for flow indicators made of glass exposed to 

borated water leakage (external) there is no aging effect and no AMP is proposed. The AMR 

item cites generic Note G, indicating that for the item, the environment is not in the GALL Report 

for this component and material. 

The staff reviewed all AMR items in the GALL Report where the material is glass, and confirmed 

that, for this environment, there are no entries in the GALL Report for this component and 

material. The staff notes that for glass components, the GALL Report does list a treated water 

environment in contrast to borated water leakage, but this is not significant to the evaluation 

because the GALL Report AMR items state that there is no aging effect and no recommended 

AMP. The staff finds the applicant’s proposal acceptable because glass in an environment of 

borated water leakage is expected to have the same aging effects as glass in an environment of 

treated borated water, and the GALL Report states that there are no AERMs for glass piping 

components in a treated borated water environment. 

In LRA Table 3.2.2-4, the applicant stated that for nickel-alloy piping exposed to borated water 

leakage there is no aging effect and no AMP is proposed. The AMR item cites generic Note G, 

indicating that for the item, the environment is not in the GALL Report for this component and 

material. 

The staff reviewed the associated items in the LRA and confirmed that no aging effect is 

applicable for this component, material, and environment because austenitic materials such as 

nickel alloys are not subject to loss of material or cracking when exposed to this environment, 

and these materials are used as corrosion-resistant replacement materials where other 

materials have degraded. The staff noted that according to EPRI NP-5769, “Degradation and 

Failure of Bolting in Nuclear Power Plants,” Volumes 1 and 2, April 1988, corrosion-resistant 

materials, such as austenitic and martensitic stainless steels and high-strength, nickel-base 

alloys, offer good protection against loss of material due to boric acid corrosion. The staff also 

noted that the conditions required for cracking to occur (e.g., SCC, PWSCC, IASCC and 

IGSCC), such as being exposed to high temperatures and reactor coolant or other corrosive 

solutions, do not exist on the surfaces of these components when exposed to borated water 

leakage. Therefore, the staff finds no AMP is necessary for nickel alloys in a borated water 

leakage environment. 

In LRA Table 3.2.2-4, the applicant stated that the Water Chemistry and One-Time Inspection 

Programs manage the stainless steel shutdown cooling heat exchangers exposed to treated 

borated water, for reduction of heat transfer. The AMR item cites generic Note H, indicating that 

the aging effect is not in the GALL Report for this component, material, and environment 

combination. The item associated with the stainless steel shutdown cooling heat exchangers 

exposed to treated borated water cites plant-specific Note 1, which states that reduction in heat 

transfer due to fouling is a potential aging effect for stainless steel heat exchanger components 

in treated borated water. This statement is based upon the component, material, aging effects, 

and AMP combination of GALL Report, AMR item VII.E1-4. 

The staff reviewed all AMR result items in the GALL Report where the component and material 

is stainless steel heat exchangers exposed to treated borated water and noted that the 

applicant’s plant-specific Note 1 reference does not directly relate to the aging effect, whereas 

GALL Report items EP-34, AP-62, and SP-40 do address heat transfer fouling. The staff also 

noted that the GALL Report recommends that the aging be managed by the Water Chemistry 
Aging Management Review Results 

 3-206 

Program and verified by the One Time Inspection Program, the same programs that the 

applicant has selected to manage aging. 

SER Sections 3.0.3.2.1 and 3.0.3.1.6 document the staff’s evaluations of the applicant’s Water 

Chemistry and One-Time Inspection Programs, respectively. The staff finds the applicant’s 

proposal to manage aging using the Water Chemistry and One-Time Inspection Programs 

acceptable because the Water Chemistry Program minimizes the potential development and 

progress of heat exchanger fouling, and the One-Time Inspection Program verifies the 

effectiveness of the Water Chemistry Program using inspections with specific attributes related 

to reduction of heat transfer. 

Based on its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, and AMP combinations not addressed in the GALL Report. 

The staff finds that the applicant has demonstrated that it will adequately manage the effects of 

aging so that the intended function(s) will be maintained consistent with the CLB for the period 

of extended operation, as required by 10 CFR.21(a)(3). 

In LRA Tables 3.3.2-4 and 3.3.2-10, the applicant stated that calcium silicate and mineral wool 

insulation exposed to borated water leakage have no AERM, and no AMP is proposed. The 

AMR items cite generic Note J. 

The staff reviewed the associated items in the LRA and noted that the applicant only included 

piping insulation in-scope for license renewal for those systems where the insulation has an 

intended function. The staff also noted that both calcium silicate and mineral wool insulation 

materials can experience loss of insulating properties when exposed to moisture, due to effects 

such as compression of the material or change in material properties, but that proper jacketing 

of the insulation can be effective at preventing moisture intrusion. The staff further noted that 

both materials can retain moisture well after exposure, prolonging the contact time of the 

moisture with the piping being insulated. By letter dated July 30, 2010, the applicant submitted 

confirmatory information that the affected piping is jacketed with overlapping seams such that 

moisture intrusion is not a concern. The staff finds the applicant’s determination, that calcium 

silicate and mineral wool insulation in this environment have no AERM, acceptable because 

these materials perform well when exposed to air and are properly jacketed to prevent moisture 

intrusion. 

Based on its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combination not addressed in the GALL 

Report. The staff finds that the applicant demonstrated that it will adequately manage the 

effects of aging for these components so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.2.3 Conclusion 

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the ESF systems components, 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). 

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 of: 

 fuel handling and storage system 
Aging Management Review Results 

 3-207 

 spent fuel pool and cleanup system 

 essential cooling water system 

 essential chilled water system 

 normal chilled water system 

 nuclear cooling water system 

 essential spray pond system 

 nuclear sampling system 

 compressed air system 

 chemical volume and control system (CVCS) 

 control building HVAC system 

 auxiliary building HVAC system 

 fuel building HVAC system 

 containment building HVAC system 

 diesel generator building HVAC system 

 radwaste building HVAC system 

 turbine building HVAC system 

 miscellaneous site structures/spray pond pump house HVAC system 

 fire protection system 

 diesel generator fuel oil storage and transfer system 

 diesel generator 

 domestic water system 

 demineralized water system 

 water reclamation facility (WRF) fuel system 

 service gases (N2

 and H2) system 

 gaseous radwaste system 

 radioactive waste drains system 

 station blackout generator 

 cranes, hoists, and elevators 

 miscellaneous auxiliary systems in-scope only for criterion 10 CFR 54.4(a)(2) 

3.3.1 Summary of Technical Information in the Application 

LRA Section 3.3 provides AMR results for the auxiliary systems components and component 

groups. LRA Table 3.3.1, “Summary of Aging Management Evaluations in Chapter VII of 

NUREG-1801 [the GALL Report] for Auxiliary Systems,” is a summary comparison of the 

applicant’s AMRs with those evaluated in the GALL Report for the auxiliary systems 

components and component groups. 

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry 

operating experience in the determination of AERMs. The plant-specific evaluation included 

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 provided sufficient information 

to demonstrate that it will adequately manage the effects of aging for the auxiliary systems 

components, within the scope of license renewal and subject to an AMR, 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). 
Aging Management Review Results 

 3-208 

The staff reviewed AMRs to ensure the applicant’s claim that certain 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 identified the appropriate GALL Report AMRs. SER Section 3.0.3 documents 

the staff’s evaluations of the AMPs, and SER Section 3.3.2.1 documents details of the staff’s 

evaluation. 

The staff also reviewed AMRs 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 SRP-LR Section 3.3.2.2 acceptance criteria. SER Section 3.3.2.2 documents the 

staff’s evaluations. 

The staff also conducted a technical review of the remaining AMRs not consistent with, or not 

addressed in, the GALL Report. The technical review evaluated if the applicant identified all 

plausible aging effects and if the aging effects listed were appropriate for the 

material-environment combinations specified. SER Section 3.3.2.3 documents the staff’s 

evaluations. 

For SSCs that the applicant claimed were not applicable or required no aging management, the 

staff reviewed the AMR items and the plant’s operating experience to verify the applicant’s 

claims. 

Table 3.3-1 summarizes the staff’s evaluation of components, aging effects or mechanisms, and 

AMPs listed in LRA Section 3.3 and addressed in the GALL Report. 

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

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Steel cranes-structural girders 

exposed to air-indoor 

uncontrolled (external) 

(3.3.1-1) 

Cumulative 

fatigue damage

TLAA to be 

evaluated for 

structural girders of 

cranes. See the 

SRP-LR, 

Section 4.7 for 

generic guidance for 

meeting the 

requirements of 

10 CFR 54.21(c)(1).

Yes TLAA Consistent 

with GALL 

Report. See 

SER Section 

3.3.2.2.1. 

Steel and stainless steel piping, 

piping components, piping 

elements, and heat exchanger 

components exposed to air - 

indoor uncontrolled, treated 

borated water or treated water 

(3.3.1-2) 

Cumulative 

fatigue damage

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c) 

Yes TLAA Consistent 

with GALL 

Report. See 

SER Section 

3.3.2.2.1. 
Aging Management Review Results 

 3-209 

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Stainless steel heat exchanger 

tubes exposed to treated water 

(3.3.1-3) 

Reduction of 

heat transfer 

due to fouling 

Water Chemistry 

and One-Time 

Inspection 

Yes Not applicable The staff did 

not agree with 

the 

applicant’s 

determination 

of ‘not 

applicable.’ 

See SER 

Sections 

3.3.2.2.2 and 

3.3.2.3.2. 

Stainless steel piping, piping 

components, and piping 

elements exposed to sodium 

pentaborate solution > 60°C 

(> 140°F) 

(3.3.1-4) 

Cracking due 

to SCC 

Water Chemistry 

and One-Time 

Inspection 

Yes Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.3.2.2.3(1). 

Stainless steel and stainless 

clad steel heat exchanger 

components exposed to treated 

water > 60°C (> 140°F) 

(3.3.1-5) 

Cracking due 

to SCC 

A plant specific 

AMP is to be 

evaluated. 

Yes Not applicable Not 

applicable. 

See SER 

Section 

3.3.2.2.3(2). 

Stainless steel diesel engine 

exhaust piping, piping 

components, and piping 

elements exposed to diesel 

exhaust 

(3.3.1-6) 

Cracking due 

to SCC 

A plant specific 

AMP is to be 

evaluated. 

Yes Inspection Of 

Internal 

Surfaces In 

Miscellaneous 

Piping And 

Ducting 

Components 

Consistent 

with GALL 

Report. See 

SER Section 

3.3.2.2.3(3). 

Stainless steel nonregenerative heat exchanger 

components exposed to treated 

borated water > 60°C (> 140°F) 

(3.3.1-7) 

Cracking due 

to SCC and 

cyclic loading 

Water Chemistry 

and a plant-specific 

verification program. 

An acceptable 

verification program 

is to include 

temperature and 

radioactivity 

monitoring of the 

shell side water, 

and eddy current 

testing of tubes. 

Yes Water 

Chemistry and 

One- Time 

Inspection 

Consistent 

with GALL 

Report. See 

SER Section 

3.3.2.2.4(1). 

Stainless steel regenerative 

heat exchanger components 

exposed to treated borated 

water > 60°C (> 140°F) 

(3.3.1-8) 

Cracking due 

to SCC and 

cyclic loading 

Water Chemistry 

and a plant-specific 

verification program. 

The AMP is to be 

augmented by 

verifying the 

absence of cracking 

due to SCC and 

cyclic loading. A 

plant specific AMP 

is to be evaluated. 

Yes Water 

Chemistry and 

One-Time 

Inspection 

Consistent 

with GALL 

Report. See 

SER Section 

3.3.2.2.4(2). 
Aging Management Review Results 

 3-210 

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Stainless steel high-pressure 

pump casing in PWR CVCS 

(3.3.1-9) 

Cracking due 

to SCC and 

cyclic loading 

Water Chemistry 

and a plant-specific 

verification program. 

The AMP is to be 

augmented by 

verifying the 

absence of cracking 

due to SCC and 

cyclic loading. A 

plant specific AMP 

is to be evaluated. 

Yes Water 

Chemistry and 

One-Time 

Inspection 

Consistent 

with GALL 

Report. See 

SER Section 

3.3.2.2.4(3). 

High-strength steel closure 

bolting exposed to air with 

steam or water leakage. 

(3.3.1-10) 

Cracking due 

to SCC, cyclic 

loading 

Bolting Integrity. 

The AMP is to be 

augmented by 

appropriate 

inspection to detect 

cracking if the bolts 

are not otherwise 

replaced during 

maintenance. 

Yes Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.3.2.2.4(4). 

Elastomer seals and 

components exposed to air - 

indoor uncontrolled 

(internal/external) 

(3.3.1-11) 

Hardening and 

loss of strength 

due to 

elastomer 

degradation 

A plant specific 

AMP is to be 

evaluated. 

Yes Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

and External 

Surfaces 

Monitoring 

Consistent 

with GALL 

Report. See 

SER Section 

3.3.2.2.5(1). 

Elastomer lining exposed to 

treated water or treated 

borated water 

(3.3.1-12) 

Hardening and 

loss of strength 

due to 

elastomer 

degradation 

A plant-specific 

AMP is to be 

evaluated. 

Yes Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Consistent 

with GALL 

Report. See 

SER Section 

3.3.2.2.5(2). 

Boral, boron steel spent fuel 

storage racks neutronabsorbing sheets exposed to 

treated water or treated 

borated water 

(3.3.1-13) 

Reduction of 

neutronabsorbing 

capacity and 

loss of material 

due to general 

corrosion 

A plant specific 

AMP is to be 

evaluated. 

Yes Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.3.2.2.6. 

Steel piping, piping component, 

and piping elements exposed 

to lubricating oil 

(3.3.1-14) 

Loss of 

material due to 

general, pitting, 

and crevice 

corrosion 

Lubricating Oil 

Analysis and 

One-Time 

Inspection 

Yes Lubricating Oil 

Analysis and 

One-Time 

Inspection 

Consistent 

with GALL 

Report. See 

SER Section 

3.3.2.2.7(1). 

Steel RCP oil collection system 

piping, tubing, and valve bodies 

exposed to lubricating oil 

(3.3.1-15) 

Loss of 

material due to 

general, pitting, 

and crevice 

corrosion 

Lubricating Oil 

Analysis and 

One-Time 

Inspection 

Yes Lubricating Oil 

Analysis and 

One-Time 

Inspection 

Consistent 

with GALL 

Report. See 

SER Section 

3.3.2.2.7(1). 
Aging Management Review Results 

 3-211 

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Steel RCP oil collection system 

tank exposed to lubricating oil 

(3.3.1-16) 

Loss of 

material due to 

general, pitting, 

and crevice 

corrosion 

Lubricating Oil 

Analysis and 

One-Time 

Inspection to 

evaluate the 

thickness of the 

lower portion of the 

tank 

Yes Lubricating Oil 

Analysis and 

One-Time 

Inspection 

Consistent 

with GALL 

Report. See 

SER Section 

3.3.2.2.7(1). 

Steel piping, piping 

components, and piping 

elements exposed to treated 

water 

(3.3.1-17) 

Loss of 

material due to 

general, pitting, 

and crevice 

corrosion 

Water Chemistry 

and One-Time 

Inspection 

Yes Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.3.2.2.7(2). 

Stainless steel and steel diesel 

engine exhaust piping, piping 

components, and piping 

elements exposed to diesel 

exhaust 

(3.3.1-18) 

Loss of 

material/gener

al (steel only), 

pitting and 

crevice 

corrosion 

A plant specific 

AMP is to be 

evaluated. 

Yes Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Consistent 

with GALL 

Report. See 

SER Section 

3.3.2.2.7(3). 

Steel (with or without coating or 

wrapping) piping, piping 

components, and piping 

elements exposed to soil 

(3.3.1-19) 

Loss of 

material due to 

general, pitting, 

crevice, and 

MIC 

Buried Piping and 

Tanks Surveillance 

or 

Buried Piping and 

Tanks Inspection 

No

Yes 

Buried Piping 

and Tanks 

Inspection 

Consistent 

with GALL 

Report. See 

SER Section 

3.3.2.2.8. 

Steel piping, piping 

components, piping elements, 

and tanks exposed to fuel oil 

(3.3.1-20) 

Loss of 

material due to 

general, pitting, 

crevice, and 

MIC and 

fouling 

Fuel Oil Chemistry 

and One-Time 

Inspection 

Yes Fuel Oil 

Chemistry and 

One-Time 

Inspection 

Consistent 

with GALL 

Report. See 

SER Section 

3.3.2.2.9(1). 

Steel heat exchanger 

components exposed to 

lubricating oil 

(3.3.1-21) 

Loss of 

material due to 

general, pitting, 

crevice, and 

MIC and 

fouling 

Lubricating Oil 

Analysis and 

One-Time 

Inspection 

Yes Lubricating Oil 

Analysis and 

One-Time 

Inspection 

Consistent 

with GALL 

Report. See 

SER Section 

3.3.2.2.9(2).

Steel with elastomer lining or 

stainless steel cladding piping, 

piping components, and piping 

elements exposed to treated 

water and treated borated 

water 

(3.3.1-22) 

Loss of 

material due to 

pitting and 

crevice 

corrosion (only 

for steel after 

lining/cladding 

degradation) 

Water Chemistry 

and One-Time 

Inspection 

Yes Water 

Chemistry and 

One-Time 

Inspection 

Not applicable 

to PVNGS. 

See SER 

Section 

3.3.2.2.10(1). 

Stainless steel and steel with 

stainless steel cladding heat 

exchanger components 

exposed to treated water 

(3.3.1-23) 

Loss of 

material due to 

pitting and 

crevice 

corrosion 

Water Chemistry 

and One-Time 

Inspection 

Yes Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.3.2.2.10(2). 
Aging Management Review Results 

 3-212 

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Stainless steel and aluminum 

piping, piping components, and 

piping elements exposed to 

treated water 

(3.3.1-24) 

Loss of 

material due to 

pitting and 

crevice 

corrosion 

Water Chemistry 

and One-Time 

Inspection 

Yes Not applicable See SER 

Section 

3.3.2.2.10(2). 

Copper alloy HVAC piping, 

piping components, piping 

elements exposed to 

condensation (external) 

(3.3.1-25) 

Loss of 

material due to 

pitting and 

crevice 

corrosion 

A plant-specific 

AMP is to be 

evaluated. 

Yes Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

and External 

Surfaces 

Monitoring 

Consistent 

with GALL 

Report. See 

SER Section 

3.3.2.2.10(3). 

Copper alloy piping, piping 

components, and piping 

elements exposed to 

lubricating oil 

(3.3.1-26) 

Loss of 

material due to 

pitting and 

crevice 

corrosion 

Lubricating Oil 

Analysis and 

One-Time 

Inspection 

Yes Lubricating Oil 

Analysis and 

One-Time 

Inspection 

Consistent 

with GALL 

Report. See 

SER Section 

3.3.2.2.10(4). 

Stainless steel HVAC ducting 

and aluminum HVAC piping, 

piping components and piping 

elements exposed to 

condensation 

(3.3.1-27) 

Loss of 

material due to 

pitting and 

crevice 

corrosion 

A plant-specific 

AMP is to be 

evaluated. 

Yes Inspection Of 

Internal 

Surfaces In 

Miscellaneous 

Piping And 

Ducting 

Components 

Consistent 

with GALL 

Report. See 

SER Section 

3.3.2.2.10(5). 

Copper alloy fire protection 

piping, piping components, and 

piping elements exposed to 

condensation (internal) 

(3.3.1-28) 

Loss of 

material due to 

pitting and 

crevice 

corrosion 

A plant-specific 

AMP is to be 

evaluated. 

Yes Inspection Of 

Internal 

Surfaces In 

Miscellaneous 

Piping And 

Ducting 

Components 

Consistent 

with GALL 

Report. See 

SER Section 

3.3.2.2.10(6). 

Stainless steel piping, piping 

components, and piping 

elements exposed to soil 

(3.3.1-29) 

Loss of 

material due to 

pitting and 

crevice 

corrosion 

A plant-specific

AMP is to be 

evaluated. 

Yes Buried Piping 

and Tanks 

Inspection 

Consistent 

with GALL 

Report. See 

SER Section 

3.3.2.2.10(7). 

Stainless steel piping, piping 

components, and piping 

elements exposed to sodium 

pentaborate solution 

(3.3.1-30) 

Loss of 

material due to 

pitting and 

crevice 

corrosion 

Water Chemistry 

and One-Time 

Inspection 

Yes Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.3.2.2.10(8). 

Copper alloy piping, piping 

components, and piping 

elements exposed to treated 

water 

(3.3.1-31) 

Loss of 

material due to 

pitting, crevice, 

and galvanic 

corrosion 

Water Chemistry 

and One-Time 

Inspection 

Yes Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.3.2.2.11. 
Aging Management Review Results 

 3-213 

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Stainless steel, aluminum and 

copper alloy piping, piping 

components, and piping 

elements exposed to fuel oil 

(3.3.1-32) 

Loss of 

material due to 

pitting, crevice, 

and MIC 

Fuel Oil Chemistry 

and One-Time 

Inspection 

Yes Fuel Oil 

Chemistry and 

One-Time 

Inspection 

Consistent 

with GALL 

Report. See 

SER Section 

3.3.2.2.12(1). 

Stainless steel piping, piping 

components, and piping 

elements exposed to 

lubricating oil 

(3.3.1-33) 

Loss of 

material due to 

pitting, crevice, 

and MIC 

Lubricating Oil 

Analysis and 

One-Time 

Inspection 

Yes Lubricating Oil 

Analysis and 

One-Time 

Inspection 

Consistent 

with GALL 

Report. See 

SER Section 

3.3.2.2.12(2). 

Elastomer seals and 

components exposed to airindoor uncontrolled (internal or 

external) 

(3.3.1-34) 

Loss of 

material due to 

wear 

A plant specific 

AMP is to be 

evaluated. 

Yes Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.3.2.2.13. 

Steel with stainless steel 

cladding pump casing exposed 

to treated borated water 

(3.3.1-35) 

Loss of 

material due to 

cladding 

breach 

A plant-specific 

AMP is to be 

evaluated. 

Reference NRC 

IN 94-63, “Boric 

Acid Corrosion of 

Charging Pump 

Casings Caused by 

Cladding Cracks.” 

Yes Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.3.2.2.14. 

Boraflex spent fuel storage 

racks neutron-absorbing sheets 

exposed to treated water 

(3.3.1-36) 

Reduction of 

neutronabsorbing 

capacity due to 

boraflex 

degradation 

Boraflex Monitoring No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.3.2.1.1. 

Stainless steel piping, piping 

components, and piping 

elements exposed to treated 

water > 60°C (> 140°F) 

(3.3.1-37) 

Cracking due 

to SCC, 

IGSCC 

BWR Reactor Water 

Cleanup System 

No Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.3.2.1.1. 

Stainless steel piping, piping 

components, and piping 

elements exposed to treated 

water > 60°C (> 140°F) 

(3.3.1-38) 

Cracking due 

to SCC 

BWR SCC and 

Water Chemistry 

No Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.3.2.1.1. 

Stainless steel BWR spent fuel 

storage racks exposed to 

treated water > 60°C (> 140°F) 

(3.3.1-39) 

Cracking due 

to SCC 

Water Chemistry No Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.3.2.1.1. 

Steel tanks in diesel fuel oil 

system exposed to air - outdoor 

(external) 

(3.3.1-40) 

Loss of 

material due to 

general, pitting, 

and crevice 

corrosion 

Aboveground Steel 

Tanks 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.3.2.1.1. 
Aging Management Review Results 

 3-214 

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

High-strength steel closure 

bolting exposed to air with 

steam or water leakage 

(3.3.1-41) 

Cracking due 

to cyclic 

loading, SCC 

Bolting Integrity No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.3.2.1.1. 

Steel closure bolting exposed 

to air with steam or water 

leakage 

(3.3.1-42) 

Loss of 

material due to 

general 

corrosion 

Bolting Integrity No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.3.2.1.1. 

Steel bolting and closure 

bolting exposed to air-indoor 

uncontrolled (external) or airoutdoor (external) 

(3.3.1-43) 

Loss of 

material due to 

general, pitting, 

and crevice 

corrosion 

Bolting Integrity No Bolting 

Integrity 

Consistent 

with GALL 

Report. 

Steel compressed air system 

closure bolting exposed to 

condensation 

(3.3.1-44) 

Loss of 

material due to 

general, pitting, 

and crevice 

corrosion 

Bolting Integrity No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.3.2.1.1. 

Steel closure bolting exposed 

to air-indoor uncontrolled 

(external) 

(3.3.1-45) 

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening 

Bolting Integrity No Bolting 

Integrity 

Consistent 

with GALL 

Report. 

Stainless steel and stainless 

clad steel piping, piping 

components, piping elements, 

and heat exchanger 

components exposed to closed 

cycle cooling water > 60°C 

(> 140°F) 

(3.3.1-46) 

Cracking due 

to SCC 

Closed-Cycle 

Cooling Water 

System 

No Closed-Cycle 

Cooling Water 

System 

Consistent 

with GALL 

Report. 

Steel piping, piping 

components, piping elements, 

tanks, and heat exchanger 

components exposed to closed 

cycle cooling water 

(3.3.1-47) 

Loss of 

material due to 

general, pitting, 

and crevice 

corrosion 

Closed-Cycle 

Cooling Water 

System 

No Closed-Cycle 

Cooling Water 

System 

Consistent 

with GALL 

Report. 

Steel piping, piping 

components, piping elements, 

tanks, and heat exchanger 

components exposed to closed 

cycle cooling water 

(3.3.1-48) 

Loss of 

material due to 

general, pitting, 

crevice, and 

galvanic 

corrosion 

Closed-Cycle 

Cooling Water 

System 

No Closed-Cycle 

Cooling Water 

System 

Consistent 

with GALL 

Report. 

Stainless steel; steel with 

stainless steel cladding heat 

exchanger components 

exposed to closed cycle 

cooling water 

(3.3.1-49) 

Loss of 

material due to 

MIC 

Closed-Cycle 

Cooling Water 

System 

No Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.3.2.1.1. 
Aging Management Review Results 

 3-215 

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Stainless steel piping, piping 

components, and piping 

elements exposed to closed 

cycle cooling water 

(3.3.1-50) 

Loss of 

material due to 

pitting and 

crevice 

corrosion 

Closed-Cycle 

Cooling Water 

System 

No Closed-Cycle 

Cooling Water 

System 

Consistent 

with GALL 

Report. 

Copper alloy piping, piping 

components, piping elements, 

and heat exchanger 

components exposed to closed 

cycle cooling water 

(3.3.1-51) 

Loss of 

material due to 

pitting, crevice, 

and galvanic 

corrosion 

Closed-Cycle 

Cooling Water 

System 

No Closed-Cycle 

Cooling Water 

System 

Consistent 

with GALL 

Report. 

Steel, stainless steel, and 

copper alloy heat exchanger 

tubes exposed to closed cycle 

cooling water 

(3.3.1-52) 

Reduction of 

heat transfer 

due to fouling 

Closed-Cycle 

Cooling Water 

System 

No Closed-Cycle 

Cooling Water 

System 

Consistent 

with GALL 

Report. 

Steel compressed air system 

piping, piping components, and 

piping elements exposed to 

condensation (internal) 

(3.3.1-53) 

Loss of 

material due to 

general and 

pitting 

corrosion 

Compressed Air 

Monitoring 

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Alternative 

program 

used. See 

SER Section 

3.3.2.1.2 

Stainless steel compressed air 

system piping, piping 

components, and piping 

elements exposed to internal 

condensation 

(3.3.1-54) 

Loss of 

material due to 

pitting and 

crevice 

corrosion 

Compressed Air 

Monitoring 

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Alternative 

program 

used. See 

SER Section 

3.3.2.1.2. 

Steel ducting closure bolting 

exposed to air - indoor 

uncontrolled (external) 

(3.3.1-55) 

Loss of 

material due to 

general 

corrosion 

External Surfaces 

Monitoring 

No External 

Surfaces 

Monitoring 

Consistent 

with GALL 

Report. 

Steel HVAC ducting and 

components external surfaces 

exposed to air-indoor 

uncontrolled (external) 

(3.3.1-56) 

Loss of 

material due to 

general 

corrosion 

External Surfaces 

Monitoring 

No External 

Surfaces 

Monitoring 

Consistent 

with GALL 

Report. 

Steel piping and components 

external surfaces exposed to 

air-indoor uncontrolled 

(External) 

(3.3.1-57) 

Loss of 

material due to 

general 

corrosion 

External Surfaces 

Monitoring 

No External 

Surfaces 

Monitoring 

Consistent 

with GALL 

Report. 
Aging Management Review Results 

 3-216 

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Steel external surfaces 

exposed to air-indoor 

uncontrolled (external), airoutdoor (external), and 

condensation (external) 

(3.3.1-58) 

Loss of 

material due to 

general 

corrosion 

External Surfaces 

Monitoring 

No External 

Surfaces 

Monitoring 

and Inspection 

of Internal 

Surfaces in 

Miscellaneous 

Piping And 

Ducting 

Components 

Consistent 

with GALL 

Report or 

alternative 

program 

used. See 

SER Section 

3.3.2.1.3. 

Steel heat exchanger 

components exposed to airindoor uncontrolled (external) 

or air-outdoor (external) 

(3.3.1-59) 

Loss of 

material due to 

general, pitting, 

and crevice 

corrosion 

External Surfaces 

Monitoring 

No External 

Surfaces 

Monitoring 

Consistent 

with GALL 

Report. 

Steel piping, piping 

components, and piping 

elements exposed to airoutdoor (external) 

(3.3.1-60) 

Loss of 

material due to 

general, pitting, 

and crevice 

corrosion 

External Surfaces 

Monitoring 

No External 

Surfaces 

Monitoring 

Consistent 

with GALL 

Report. 

Elastomer fire barrier 

penetration seals exposed to 

air-outdoor or air-indoor 

uncontrolled 

(3.3.1-61) 

Increased 

hardness, 

shrinkage and 

loss of strength 

due to 

weathering 

Fire Protection No Fire Protection Consistent 

with GALL 

Report. 

Aluminum piping, piping 

components, and piping 

elements exposed to raw water 

(3.3.1-62) 

Loss of 

material due to 

pitting and 

crevice 

corrosion 

Fire Protection No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.3.2.1.1. 

Steel fire rated doors exposed 

to air-outdoor or air-indoor 

uncontrolled 

(3.3.1-63) 

Loss of 

material due to 

wear 

Fire Protection No Fire Protection Consistent 

with GALL 

Report. 

Steel piping, piping 

components, and piping 

elements exposed to fuel oil 

(3.3.1-64) 

Loss of 

material due to 

general, pitting, 

and crevice 

corrosion 

Fire Protection and 

Fuel Oil Chemistry 

No Not applicable Not 

applicable. 

See SER 

Section 

3.3.2.1.1. 

Reinforced concrete structural 

fire barriers-walls, ceilings and 

floors exposed to air-indoor 

uncontrolled 

(3.3.1-65) 

Concrete 

cracking and 

spalling due to 

aggressive 

chemical 

attack, and 

reaction with 

aggregates 

Fire Protection and 

Structures 

Monitoring Program 

No Fire Protection 

and Structures 

Monitoring 

Program 

Consistent 

with GALL 

Report. 
Aging Management Review Results 

 3-217 

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Reinforced concrete structural 

fire barriers-walls, ceilings and 

floors exposed to air-outdoor 

(3.3.1-66) 

Concrete 

cracking and 

spalling due to 

freeze thaw, 

aggressive 

chemical 

attack, and 

reaction with 

aggregates 

Fire Protection and 

Structures 

Monitoring Program 

No Fire Protection 

and Structures 

Monitoring 

Program 

Consistent 

with GALL 

Report. 

Reinforced concrete structural 

fire barriers-walls, ceilings and 

floors exposed to air-outdoor or 

air-indoor uncontrolled 

(3.3.1-67) 

Loss of 

material due to 

corrosion of 

embedded 

steel 

Fire Protection and 

Structures 

Monitoring Program 

No Fire Protection 

and Structures 

Monitoring 

Program 

Consistent 

with GALL 

Report. 

Steel piping, piping 

components, and piping 

elements exposed to raw water 

(3.3.1-68) 

Loss of 

material due to 

general, pitting, 

crevice, and 

MIC and 

fouling 

Fire Water System No Fire Water 

System 

Consistent 

with GALL 

Report. 

Stainless steel piping, piping 

components, and piping 

elements exposed to raw water 

(3.3.1-69) 

Loss of 

material due to 

pitting and 

crevice 

corrosion, and 

fouling 

Fire Water System No Fire Water 

System 

Consistent 

with GALL 

Report. 

Copper alloy piping, piping 

components, and piping 

elements exposed to raw water 

(3.3.1-70) 

Loss of 

material due to 

pitting, crevice, 

and MIC and 

fouling 

Fire Water System No Fire Water 

System 

Consistent 

with GALL 

Report. 

Steel piping, piping 

components, and piping 

elements exposed to moist air 

or condensation (internal) 

(3.3.1-71) 

Loss of 

material due to 

general, pitting, 

and crevice 

corrosion 

Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components 

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Consistent 

with GALL 

Report. 

Steel HVAC ducting and 

components internal surfaces 

exposed to condensation 

(internal) 

(3.3.1-72) 

Loss of 

material due to 

general, pitting, 

crevice, and 

(for drip pans 

and drain lines) 

MIC 

Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components 

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Consistent 

with GALL 

Report. 

Steel crane structural girders in 

load handling system exposed 

to air-indoor uncontrolled 

(external) 

(3.3.1-73) 

Loss of 

material due to 

general 

corrosion 

Inspection of 

Overhead Heavy 

Load and Light 

Load (Related to 

Refueling) Handling 

Systems 

No Inspection of 

Overhead 

Heavy Load 

and Light 

Load (Related 

to Refueling) 

Handling 

Systems 

Consistent 

with GALL 

Report. 
Aging Management Review Results 

 3-218 

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Steel cranes-rails exposed to 

air-indoor uncontrolled 

(external) 

(3.3.1-74) 

Loss of 

material due to 

Wear 

Inspection of 

Overhead Heavy 

Load and Light 

Load (Related to 

Refueling) Handling 

Systems 

No Inspection of 

Overhead 

Heavy Load 

and Light 

Load (Related 

to Refueling) 

Handling 

Systems 

Consistent 

with GALL 

Report. 

Elastomer seals and 

components exposed to raw 

water 

(3.3.1-75) 

Hardening and 

loss of strength 

due to 

elastomer 

degradation; 

loss of material 

due to erosion 

Open-Cycle Cooling 

Water System 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.3.2.1.1. 

Steel piping, piping 

components, and piping 

elements (without lining/ 

coating or with degraded 

lining/coating) exposed to raw 

water 

(3.3.1-76) 

Loss of 

material due to 

general, pitting, 

crevice, and 

MIC, fouling, 

and 

lining/coating 

degradation 

Open-Cycle Cooling 

Water System 

No Open-Cycle 

Cooling Water 

System and 

Inspection Of 

Internal 

Surfaces in 

Miscellaneous 

Piping And 

Ducting 

Components 

Consistent 

with GALL 

Report or 

alternative 

program 

used. See 

SER Section 

3.3.2.1.4. 

Steel heat exchanger 

components exposed to raw 

water 

(3.3.1-77) 

Loss of 

material due to 

general, pitting, 

crevice, 

galvanic, and 

MIC and 

fouling 

Open-Cycle Cooling 

Water System 

No Open-Cycle 

Cooling Water 

System 

Consistent 

with GALL 

Report. 

Stainless steel, nickel alloy, 

and copper alloy piping, piping 

components, and piping 

elements exposed to raw water 

(3.3.1-78) 

Loss of 

material due to 

pitting and 

crevice 

corrosion 

Open-Cycle Cooling 

Water System 

No Open-Cycle 

Cooling Water 

System 

Consistent 

with GALL 

Report. 

Stainless steel piping, piping 

components, and piping 

elements exposed to raw water 

(3.3.1-79) 

Loss of 

material due to 

pitting and 

crevice 

corrosion, and 

fouling 

Open-Cycle Cooling 

Water System 

No Inspection Of 

Internal 

Surfaces In 

Miscellaneous 

Piping And 

Ducting 

Components 

Alternative 

program 

used. See 

SER Section 

3.3.2.1.5. 

Stainless steel and copper 

alloy piping, piping 

components, and piping 

elements exposed to raw water 

(3.3.1-80) 

Loss of 

material due to 

pitting, crevice, 

and 

microbiologicall

y influenced 

corrosion 

Open-Cycle Cooling 

Water System 

No Open-Cycle 

Cooling Water 

System 

Consistent 

with GALL 

Report. 
Aging Management Review Results 

 3-219 

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Copper alloy piping, piping 

components, and piping 

elements, exposed to raw 

water 

(3.3.1-81) 

Loss of 

material due to 

pitting, crevice, 

and MIC and 

fouling 

Open-Cycle Cooling 

Water System 

No Inspection Of 

Internal 

Surfaces In 

Miscellaneous 

Piping And 

Ducting 

Components 

Alternative 

program 

used. See 

SER Section 

3.3.2.1.6. 

Copper alloy heat exchanger 

components exposed to raw 

water 

(3.3.1-82) 

Loss of 

material due to 

pitting, crevice, 

galvanic, and 

MIC and 

fouling 

Open-Cycle Cooling 

Water System 

No Open-Cycle 

Cooling Water 

System 

Consistent 

with GALL 

Report. 

Stainless steel and copper 

alloy heat exchanger tubes 

exposed to raw water 

(3.3.1-83) 

Reduction of 

heat transfer 

due to fouling 

Open-Cycle Cooling 

Water System 

No Open-Cycle 

Cooling Water 

System 

Consistent 

with GALL 

Report. 

Copper alloy > 15% Zn piping, 

piping components, piping 

elements, and heat exchanger 

components exposed to raw 

water, treated water, or closed 

cycle cooling water 

(3.3.1-84) 

Loss of 

material due to 

selective 

leaching 

Selective Leaching 

of Materials 

No Selective 

Leaching of 

Materials 

Consistent 

with GALL 

Report. 

Gray cast iron piping, piping 

components, and piping 

elements exposed to soil, raw 

water, treated water, or closedcycle cooling water 

(3.3.1-85) 

Loss of 

material due to 

selective 

leaching 

Selective Leaching 

of Materials 

No Selective 

Leaching of 

Materials 

Consistent 

with GALL 

Report. 

Structural steel (new fuel 

storage rack assembly) 

exposed to air - indoor 

uncontrolled (external) 

(3.3.1-86) 

Loss of 

material due to 

general, pitting, 

and crevice 

corrosion 

Structures 

Monitoring Program 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.3.2.1.1. 

Boraflex spent fuel storage 

racks neutron-absorbing sheets 

exposed to treated borated 

water 

(3.3.1-87) 

Reduction of 

neutronabsorbing 

capacity due to 

boraflex 

degradation 

Boraflex Monitoring No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.3.2.1.1. 

Aluminum and copper alloy 

> 15% Zn piping, piping 

components, and piping 

elements exposed to air with 

borated water leakage 

(3.3.1-88) 

Loss of 

material due to 

boric acid 

corrosion 

Boric Acid 

Corrosion 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.3.2.1.1. 
Aging Management Review Results 

 3-220 

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Steel bolting and external 

surfaces exposed to air with 

borated water leakage 

(3.3.1-89) 

Loss of 

material due to 

boric acid 

corrosion 

Boric Acid 

Corrosion 

No Boric Acid 

Corrosion 

Consistent 

with GALL 

Report. 

Stainless steel and steel with 

stainless steel cladding piping, 

piping components, piping 

elements, tanks, and fuel 

storage racks exposed to 

treated borated water > 60°C 

(> 140°F) 

(3.3.1-90) 

Cracking due 

to SCC 

Water Chemistry No Water 

Chemistry 

Consistent 

with GALL 

Report. 

Stainless steel and steel with 

stainless steel cladding piping, 

piping components, and piping 

elements exposed to treated 

borated water 

(3.3.1-91) 

Loss of 

material due to 

pitting and 

crevice 

corrosion 

Water Chemistry No Water 

Chemistry 

Consistent 

with GALL 

Report. 

Galvanized steel piping, piping 

components, and piping 

elements exposed to air-indoor 

uncontrolled 

(3.3.1-92) 

None None NA None Consistent 

with GALL 

Report. 

Glass piping elements exposed 

to air, air-indoor uncontrolled 

(external), fuel oil, lubricating 

oil, raw water, treated water, 

and treated borated water 

(3.3.1-93) 

None None NA None Consistent 

with GALL 

Report. 

Stainless steel and nickel-alloy 

piping, piping components, and 

piping elements exposed to airindoor uncontrolled (external) 

(3.3.1-94) 

None None NA None Consistent 

with GALL 

Report. 

Steel and aluminum piping, 

piping components, and piping 

elements exposed to air-indoor 

controlled (external) 

(3.3.1-95) 

None None NA None Consistent 

with GALL 

Report. 

Steel and stainless steel piping, 

piping components, and piping 

elements in concrete 

(3.3.1-96) 

None None NA None Consistent 

with GALL 

Report. 
Aging Management Review Results 

 3-221 

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Steel, stainless steel, 

aluminum, and copper alloy 

piping, piping components, and 

piping elements exposed to 

gas 

(3.3.1-97) 

None None NA None Consistent 

with GALL 

Report. 

Steel, stainless steel, and 

copper alloy piping, piping 

components, and piping 

elements exposed to dried air 

(3.3.1-98) 

None None NA None Consistent 

with GALL 

Report. 

Stainless steel and copper 

alloy < 15% Zn piping, piping 

components, and piping 

elements exposed to air with 

borated water leakage 

(3.3.1-99) 

None None NA None Consistent 

with GALL 

Report. 

 

The staff’s review of the auxiliary systems component groups followed one of three categories. 

One category, documented in SER Section 3.3.2.1, reviewed AMR results for components that 

the applicant indicated are consistent with the GALL Report and require no further evaluation. 

Another category, documented in SER Section 3.3.2.2, reviewed AMR results for components 

that the applicant indicated are consistent with the GALL Report and for which further evaluation 

is recommended. A third category, documented in SER Section 3.3.2.3, reviewed AMR results 

for components that the applicant indicated are not consistent with, or not addressed in, the 

GALL Report. SER Section 3.0.3 documents the staff’s review of AMPs credited to manage or 

monitor aging effects of the auxiliary systems components. 

3.3.2.1 Aging Management Review Results Consistent with the Generic Aging Lessons 

Learned Report 

LRA Section 3.3.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the auxiliary systems components: 

 ASME Section XI ISI, Subsections IWB, IWC, and IWD 

 Bolting Integrity 

 Boric Acid Corrosion 

 Buried Piping and Tanks Inspection 

 Closed-Cycle Cooling Water System 

 External Surfaces Monitoring 

 Fire Water System 

 FAC 

 Fuel Oil Chemistry 

 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 
Aging Management Review Results 

 3-222 

 Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

System 

 Lubricating Oil Analysis 

 Nickel-Alloy Aging Management 

 One-Time Inspection 

 One-Time Inspection of ASME Code Class I Small-Bore Piping 

 Open-Cycle Cooling Water System 

 RCS Supplement 

 Selective Leaching Of Materials 

 Water Chemistry 

LRA Tables 3.3.2-1 through 3.3.2-30 summarize the AMRs for the auxiliary system components 

and indicate AMRs claimed to be consistent with the GALL Report. 

The staff audited and reviewed the information in the LRA. The staff did not repeat its review of 

the matters described in the GALL Report; however, the staff did verify that the material 

presented in the LRA was applicable and that the applicant identified the appropriate GALL 

Report AMRs. The staff’s evaluation follows. 

3.3.2.1.1 Aging Management Review Results Identified as Not Applicable 

LRA Table 3.3.1, items 3.3.1.36 through 3.3.1.39 and 3.3.1.49 discuss the applicant’s 

determination that these items are applicable only to BWRs. The staff verified that these items 

do not apply because the units are a PWR design. Based on this determination, the staff finds 

that the applicant has provided an acceptable basis for concluding the AMR items 3.3.1.36 

through 3.3.1.39 and 3.3.1.49 are not applicable. 

LRA Table 3.3.1, item 3.3.1.40, addresses steel tanks in the diesel fuel oil system exposed to 

outdoor air (external). The applicant stated that this item is not applicable because there are no 

steel tanks in the EDG fuel oil storage and transfer system that are exposed to the outdoor air 

(external) environment. The staff reviewed LRA Sections 2.3.3 and 3.3 and confirmed that the 

applicant’s LRA does not have any AMR results for the diesel generator fuel oil storage and 

transfer system that includes steel tanks exposed to outdoor air (external). The staff also 

reviewed the applicant’s information in the UFSAR and confirmed that no in-scope steel tanks 

exposed to outdoor air (external) are present in the diesel generator fuel oil storage and transfer 

system and, therefore, finds the applicant’s determination acceptable. 

LRA Table 3.3.1, item 3.3.1.41, addresses high-strength steel closure bolting exposed to air 

with steam or water leakage in the auxiliary systems. The GALL Report recommends use of 

AMP XI.M18, “Bolting Integrity,” to manage cracking due to cyclic loading or SCC for this 

component group. The applicant stated that this item is not applicable because high strength 

steel closure bolting is not used in the auxiliary systems. The staff reviewed LRA Sections 2.3.3 

and 3.3 and confirmed that the applicant’s LRA does not have any AMR results for the auxiliary 

systems that include high strength steel closure bolting exposed to air with steam or water 

leakage. During its review of the UFSAR, operating experience, and applicant interviews 

associated with the Bolting Integrity Program, the staff did not identify the use of high strength 

steel closure bolting in the auxiliary systems within the scope of license renewal. Based on its 

review of the LRA and the applicant’s Bolting Integrity Program, the staff confirmed that there is 

no high-strength steel closure bolting exposed to air with steam or water leakage in the auxiliary 

systems and, therefore, finds the applicant’s determination applicable. 
Aging Management Review Results 

 3-223 

LRA Table 3.3.1, items 3.3.1.42 and 3.3.1.44, address steel closure bolting exposed to air with 

steam or water leakage (item 42) or condensation (item 44) in the auxiliary systems. The GALL 

Report recommends use of AMP XI.M18, “Bolting Integrity,” to manage loss of material due to 

general corrosion for this component group. The applicant stated that the items are not 

applicable because it has no in-scope steel closure bolting exposed to air with steam or water 

leakage or condensation in the auxiliary systems. By letter dated February 19, 2010, the staff 

issued RAI 3.3-1, part (b), requesting that the applicant justify its claim that steel closure bolting 

in its auxiliary systems are not exposed to an environment of air with steam or water leakage or 

condensation. In its response, dated March 24, 2010, the applicant stated that air with water 

leakage would be an event-driven environment, not considered normal for the auxiliary systems. 

The applicant also stated that for steel closure bolting, the aging effect and mechanism in LRA 

Table 3.3.1, items 3.3.1.42 and 3.3.1.44 are both included in the aging effect and mechanisms 

for LRA Table 3.3.1, item 3.3.1.43. The Bolting Integrity Program is credited in all three lines to 

manage the aging effect of loss of material due to general corrosion. The applicant further 

stated that it evaluated steel closure bolting in its auxiliary systems as part of LRA Table 3.3.1, 

item 3.3.1.43, rather than in item 3.3.1.42. The staff confirmed that for steel closure bolting the 

aging effect stated in LRA Table 3.3.1, item 3.3.1.42, is included in item 3.3.1.43 and that the 

Bolting Integrity Program is credited to manage the aging effect. 

The staff finds the applicant’s response to RAI 3.3.1, part (b) acceptable because it clarifies that 

components that could have been evaluated under items 3.3.1.42 and 3.3.1.44 are 

appropriately included in the evaluations under item 3.3.1.43. The staff also finds it acceptable 

for the applicant to evaluate steel closure bolting subject to general corrosion under 

item 3.3.1.43 because the aging effect and mechanism identified in items 3.3.1.42 and 3.3.1.44 

are included in the aging effect and mechanisms identified in item 3.3.1.43. Further, the AMP 

recommended by both items is the same; therefore, the staff further finds the applicant’s 

determination, that items 3.3.1.42 and 3.3.1.44 are not applicable, to be acceptable. 

LRA Table 3.3.1, item 3.3.1.62 addresses aluminum piping, piping components, and piping 

elements exposed to raw water. The GALL Report recommends the use of AMP XI.M27, “Fire 

Protection Program,” to manage loss of material due to pitting and crevice corrosion for this 

component group. The applicant stated that this item is not applicable because it has no inscope aluminum components exposed to raw water in the fire protection system. The staff 

reviewed LRA Sections 2.3.3 and 3.3 and confirmed that the applicant’s LRA does not have any 

AMR results for the fire protection system that include aluminum piping, piping components, and 

piping elements exposed to raw water. The staff also reviewed the applicant’s UFSAR and 

confirmed that there are no in-scope aluminum piping, piping components, and piping elements 

exposed to raw water in the fire protection system, and therefore, finds the applicant’s 

determination acceptable. 

LRA Table 3.3.1, item 3.3.1.64 addresses steel piping, piping components, and piping elements 

exposed to fuel oil. The GALL Report recommends use of AMPs XI.M27, “Fire Protection 

Program,” and AMP XI.M30, “Fuel Oil Chemistry Program,” to manage loss of material due to 

general, pitting, and crevice corrosion for this component group. The applicant stated that this 

item is not applicable because it used other available applicable GALL Report items. The staff 

reviewed LRA Table 3.3.2-19, “Fire Protection System,” and confirmed that the applicant 

addressed steel piping, piping components, and piping elements exposed to fuel oil and 

credited the Fuel Oil Chemistry and One-Time Inspection Programs to manage loss of material 

due to general, pitting, and crevice corrosion. This is consistent with GALL Report 

item VII.H2-24 and is addressed by LRA Table 3.3.1, item 3.3.1.20 and LRA 

Subsection 3.3.2.2.9.1. Based on its review of the LRA, the staff concludes that the applicant 

has properly addressed steel piping, piping components, and piping elements exposed to fuel 

oil using other available GALL Report items, and therefore, finds the applicant’s determination 

acceptable. 
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LRA Table 3.3.1, item 3.3.1.75 addresses elastomer seals and components exposed to raw 

water. The GALL Report recommends use of AMP XI.M20, “Open-Cycle Cooling Water 

System,” to manage hardening and loss of strength due to elastomer degradation and loss of 

material due to erosion for this component group. The applicant stated that this item is not 

applicable because it has no in-scope elastomer components exposed to raw water in the 

open-cycle cooling water systems. The staff reviewed LRA Sections 2.3.3 and 3.3 and 

identified several items that could be classified as elastomer seals and components exposed to 

raw water: in Table 3.3.2-7, it identified polyvinyl chloride (PVC) components; in Table 3.3.2-22, 

it identified polyethylene items; and in Tables 3.3.2–3.3.22 and 3.3.2-30, it identified carbon 

steel with elastomer linings. 

The staff held a teleconference call with the applicant on July 8, 2010, to discuss its concerns 

regarding how the components discussed above, or any other elastomer components exposed 

to raw water in auxiliary systems, are managed for aging during the period of extended 

operation. The applicant indicated it would provide information demonstrating that the PVC and 

polyethylene components are not susceptible to loss of material due to erosion, and that the 

AMPs proposed to manage aging of the elastomer lined carbon steel piping are appropriate. 

The applicant stated it would submit a formal response to RAI 3.3.1-1. This was previously 

identified as Confirmatory Item 3.3.2.1.1-1. 

In its response dated July 30, 2010, the applicant stated that PVC and polyethylene are 

thermoplastics that are rigid and have good resistance to abrasion and erosion, and loss of 

material due to erosion only occurs if the fluid contains particulates and fluid velocities are high. 

The applicant also stated that the PVC components are in the essential spray pond and are not 

subject to high fluid velocities. Further, the applicant stated that the polyethylene components 

are in the well water portion of the domestic water system, that this system contains minimal 

particulates, and the components are not subject to high flow velocities. The staff finds this 

acceptable because the applicant provided sufficient information to show that the subject 

components will not have a loss of material due to erosion requiring management during the 

period of extended operation. 

For the carbon steel pipe with elastomer linings exposed to raw water, the applicant stated that 

loss of material and potential consequences are managed by the Fire Water System Program, 

which uses internal visual inspections performed in accordance with the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program. The applicant further 

stated that the potential consequences are also addressed by the Fire Water System Program 

through periodic flow testing of the fire water loops and the fire suppression water system. The 

staff finds the applicant’s response acceptable because the inspections and flow tests are 

capable of identifying the loss of material. 

For the carbon steel pipe with elastomer linings exposed to oily and non-radioactive waste, the 

applicant stated that the loss of material is managed by internal visual inspections in 

accordance with the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program. The staff finds the applicant’s proposal to manage aging using the cited 

AMP acceptable because the surveillance techniques can identify and adequately manage this 

aging effect. Based on the above information, the concern described in RAI 3.3.1-1 is resolved, 

and Confirmatory Item 3.3.2.1.1-1 is closed. 

LRA Table 3.3.1, item 3.3.1.86 addresses structural steel new fuel storage rack assemblies 

exposed to indoor uncontrolled air. The applicant stated that this item is not applicable because 

its new fuel storage assemblies are made of stainless steel. The staff reviewed LRA 

Sections 2.3.3 and 3.3 and confirmed that the applicant’s LRA does not have any AMR results 

for the auxiliary systems that include steel fuel storage racks exposed to indoor uncontrolled air. 

The staff also reviewed the applicant’s UFSAR and confirmed that no in-scope steel fuel storage 
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assemblies are present in the auxiliary systems and therefore, finds the applicant’s 

determination acceptable. 

LRA Table 3.3.1, item 3.3.1.87 addresses boraflex spent fuel storage racks neutron absorbing 

sheets exposed to treated borated water. The applicant stated that this item is not applicable 

because it does not have any boraflex spent fuel storage racks exposed to treated borated 

water. The staff reviewed LRA Sections 2.3.3 and 3.3 and confirmed that the applicant’s LRA 

does not have any AMR results for the auxiliary systems that include boraflex spent fuel storage 

racks neutron absorbing sheets exposed to treated borated water. The staff also reviewed the 

applicant’s UFSAR and confirmed that no boraflex spent fuel storage racks neutron absorbing 

sheets are present in the auxiliary systems and therefore, finds the applicant’s determination 

acceptable. 

LRA Table 3.3.1, item 3.3.1.88 addresses aluminum and copper alloy with greater than 

15-percent zinc piping, piping components, and piping elements exposed to air with borated 

water leakage. The GALL Report, items VII.A3-4, VII.E1-10, VII.I-12, and VIII.E-39, recommend 

use of AMP XI.M10, “Boric Acid Corrosion,” to manage loss of material due to boric acid 

corrosion for this component group. The applicant stated that this item is not applicable 

because there are no in-scope aluminum and copper alloy greater than 15-percent zinc piping, 

piping components, and piping elements in the auxiliary systems exposed to air with borated 

water leakage. The staff reviewed LRA Sections 2.3.3 and 3.3 and confirmed that the 

applicant’s LRA does not have any AMR results in-scope aluminum and copper alloy greater 

than 15-percent zinc piping, piping components, and piping elements in the auxiliary systems 

exposed to air with borated water leakage. The staff also reviewed the applicant’s information 

in the UFSAR associated with Table 3.3.1, item 3.3.1.88 and confirmed that no in-scope 

aluminum and copper alloy greater than 15-percent zinc piping, piping components, and piping 

elements are present in the auxiliary systems. Therefore, the staff finds the applicant’s 

determination acceptable. 

3.3.2.1.2 Loss of Material Due to General and Pitting Corrosion of Steel and Stainless Steel 

Internal Surfaces Exposed to Condensation 

LRA Table 3.3.1, items 3.3.1.53 and 3.3.1.54, address stainless steel and steel piping, piping 

components, and piping elements exposed to internal condensation. The GALL Report 

recommends use of AMP XI.M24, “Compressed Air Monitoring,” to manage loss of material for 

this component group. The applicant stated that these items are not applicable because no 

applicable components were in the scope of license renewal. The staff conducted audit 

interviews and observed the plant compressed air system as part of a walkdown of plant 

environments and materials during the AMP audit. Based on this information, the staff 

determined that there were stainless steel and steel piping components exposed to internal 

condensation. 

By letter dated December 29, 2009, the NRC issued RAI B2.1.20-3 asking that the applicant 

clarify how it will manage the aging effects on piping and valves within the compressed air 

system that are exposed to condensation for loss of material and other potential aging effects. 

In its response, dated February 19, 2010, the applicant stated that several components within 

the compressed air system were incorrectly identified as having an environment of dry gas, 

further noting that the components that supply nitrogen to the spent fuel pool gate seals were 

correctly identified as having a dry gas environment. The applicant also stated that it revised 

LRA Tables 3.3.1 and 3.3.2-9 to reflect the addition of wetted air to the environments to which 

carbon steel and stainless steel piping and components in the compressed air system are 

exposed. The applicant also added plant specific footnote 1, as follows: 

AMP XI.M24, “Compressed Air Monitoring” applies to monitoring the piping and 

components associated with the air compressors and dryers. The air 
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compressor, dryer piping, and components are not in-scope for Palo Verde. 

In-scope piping and components for Palo Verde are associated with containment 

penetrations and nitrogen gas piping/components for backup to the spent fuel 

pool gate seals. Therefore, XI.M24 is not considered appropriate to Palo Verde 

and alternate AMPs are specified for the in-scope piping and components. 

The applicant further stated that it credits the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program for managing loss of material aging effects. 

Based on its review, the staff finds the applicant’s response acceptable for the following 

reasons: 

 GALL Report AMP XI.M24, “Compressed Air Monitoring,” is based on the applicant’s 

response to NRC GL 88-14. Based on a review of the applicant’s response to this GL 

and LRA Section 2.3.3.9, there are no in scope stainless steel and steel piping, piping 

components, and piping elements exposed to internal condensation that are subject to 

the requirements of the GL and this AMR item. 

 The staff notes that only the portions of the compressed air system which provide 

containment isolation for the instrument air, service, and breathing air containment 

penetration piping are in the scope of license renewal based on the criteria of 

10 CFR 54.4(a)(1). The staff also notes that only the nonsafety-related portions of the 

instrument air subsystem in the auxiliary and containment buildings that attach to 

safety-related containment building penetration piping, and the safety-related backup 

nitrogen supply tubing to the spent fuel pool gate seals are within the scope of license 

renewal as nonsafety-related components affecting safety-related components, based 

on the criterion of 10 CFR 54.4(a)(2). With the exception of the atmospheric dump 

valves, all of the air-operated valves that support fire protection, EQ, and SBO 

requirements (10 CFR 54.4(a)(3) criterion) fail to a safe position upon loss of instrument 

air. The motive force supply for the atmospheric dump valves is dry nitrogen gas; thus, 

these valves are not in the scope of this AMR item. 

 In a conference call between the staff and the applicant on June 9, 2010, the applicant 

stated that the solenoid valves that vent air from all of the air-operated valves that must 

fail to the safe position are full port valves. Therefore, the staff does not have a concern 

related to potential blockage if corrosion products should travel through the system to 

the solenoid valves. 

 Given the safety function of the in-scope components (i.e., pressure retaining boundary), 

the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program is adequate to manage loss of material due to general and pitting corrosion. 

This program will perform visual inspections to detect aging effects that could result in a 

loss of component intended function during periodic maintenance. 

The staff’s concern described in RAI B2.1.20-3 is resolved. 

3.3.2.1.3 Loss of Material Due to General Corrosion of Steel External Surfaces Exposed to 

Air 

LRA Table 3.3.1, item 3.3.1.58 addresses carbon steel and gray cast iron valves and piping 

exposed to weather and plant indoor air which are being managed for loss of material. The LRA 

credits the Internal Surfaces in Miscellaneous Piping and Ducting Components Program to 

manage the loss of material aging effect. The GALL Report recommends AMP XI.M36, 

“External Surfaces Monitoring Program,” to ensure that the applicant adequately manages these 

aging effects. The associated AMR item cites generic Note E, indicating that the LRA AMR is 
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consistent with the GALL Report item for material, environment and aging effect, but a different 

AMP is credited. 

For those items associated with generic Note E, the GALL Report recommends the External 

Surfaces Monitoring Program, which recommends using visual inspections to assess the 

condition of SSCs for loss of material when managing the aging effects of these items. In its 

review of components associated with item 3.3.1.58, for which the applicant cited generic Note 

E, the staff noted that the Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program proposes to manage the aging of piping and valves made of carbon steel and gray 

cast iron through the use of visual inspection techniques. The staff also noted, under 

item 3.3.1.58, that the applicant specifically plans to use the Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program to manage the aging effects of the internal surfaces 

of the fire protection components that are normally vented to the air. The applicant further 

stated that there is no difference between the environmental conditions to which the surfaces for 

these components are exposed, thus eliminating the distinction between internal and external 

environments. 

SER Section 3.0.3.2.15 documents the staff’s evaluation of the applicant’s Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program. The staff evaluated this program to 

determine if it is adequate to inspect the internal surfaces of piping, piping components, and 

elements (including the internal surfaces of fire protection components) for loss of material. The 

staff also reviewed the recommendations set in the program elements of both GALL Report 

programs, External Surfaces Monitoring and Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components. The staff noted that, while both programs focus on visual 

inspection of SSC for loss of material, in the “detection of aging effects” program element, the 

GALL Report External Surfaces Monitoring AMP is time-dependant with inspections performed 

at least once per refueling cycle. GALL Report Internal Surfaces in Miscellaneous Piping and 

Ducting Components AMP, on the other hand, is an opportunistic AMP where inspections are 

performed when systems and components are available for inspection. 

The staff noted that the applicant stated that within 10 years of entering the period of extended 

operation, it will review all systems within the scope of the Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program to determine the number of inspection opportunities 

afforded for systems or components within the scope of the program. When necessary, it will 

follow with additional inspections to provide reasonable assurance that the intended functions 

are maintained. For the fire protection system piping, the applicant stated that it will augment 

the visual inspection, when necessary, with volumetric inspections to monitor loss of material 

and pipe thinning. The staff also noted that in NUREG-1833, “Technical Bases for Revision to 

the License Renewal Guidance Documents,” external surfaces of steel components exposed to 

air, moisture, and humidity are vulnerable to general corrosion, and the selected AMP is the 

External Surfaces Monitoring Program. NUREG-1833 also notes that for steel piping, 

components and elements exposed to outdoor air, the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components AMP provides an acceptable means to manage 

aging for these components. In its review of components associated with item 3.3.1.58, the 

staff finds the applicant’s proposal to manage aging using the Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program acceptable because: (1) it will use 

similar visual inspections as those recommended by the External Surfaces Monitoring AMP and 

where necessary will augment these with volumetric inspections; (2) the environment applicable 

to the two programs are similar per the GALL Report; and (3) periodic monitoring of SSCs will 

be performed to assure that their intended functions are maintained. 

The staff concludes that the applicant has demonstrated that it will adequately manage the 

effects of aging for this component type, in the specified environment, so that its intended 
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function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

3.3.2.1.4 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion, Fouling, and Lining and Coating Degradation 

LRA Table 3.3.1, item 76 addresses steel piping, piping components, and piping elements 

(without lining or coating or with degraded lining or coating) exposed to raw water, which are 

managed for loss of material due to general, pitting, crevice, and microbiologically-influenced 

corrosion, fouling, and lining or coating degradation. The LRA credits the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program to manage the aging effect 

for a subsection of these components. The GALL Report recommends AMP XI.M20, 

“Open-Cycle Cooling Water System,” to ensure that these aging effects are adequately 

managed. The associated AMR item cites generic Note E, indicating that the LRA AMR is 

consistent with GALL Report item for material, environment, and aging effect, but it credits a 

different AMP. 

For those items associated with generic Note E, the GALL Report recommends the Open-Cycle 

Cooling Water System AMP, which recommends using surveillance and control techniques to 

manage aging of these items. In its review of components associated with item 76, for which 

the applicant cited generic Note E, the staff noted that the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program proposes to manage the aging of steel 

piping, piping components, and piping elements (without lining or coating or with degraded lining 

or coating) through the use of visual inspections of plant components for evidence of 

degradation (see staff evaluation of this AMP in SER Section 3.0.3.2.15). The staff also noted 

that the applicant identified components such as floor drains and building sumps that may be 

exposed to a variety of types of treated and untreated water as well as to raw water for the 

determination of aging effects. The staff finally noted that this water is not monitored by a 

chemistry program and, therefore, the Open-Cycle Cooling Water Program could not be used to 

properly manage the aging effect in this environment. The staff finds the applicant’s use of the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is 

acceptable because its surveillance techniques can identify and adequately manage this aging 

effect. 

The staff concludes that the applicant has demonstrated that it will adequately manage the 

effects of aging of these components so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3). 

3.3.2.1.5 Loss of Material Due to Pitting and Crevice Corrosion and Fouling 

LRA Table 3.3.1, item 3.3.1.79 addresses stainless steel piping, piping components, and piping 

elements exposed to raw water which are managed for loss of material due to pitting and 

crevice corrosion and fouling. The LRA credits the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program to manage the aging effect. The 

GALL Report recommends AMP XI.M20, “Open-Cycle Cooling Water System,” to ensure that 

the applicant adequately manages these aging effects. The associated AMR items cite generic 

Note E, indicating that the LRA AMR is consistent with the GALL Report item for material, 

environment, and aging effect, but a different AMP is credited. 

For those items associated with generic Note E, the GALL Report recommends the Open-Cycle 

Cooling Water System AMP, which recommends using surveillance and control techniques to 

manage the aging of these components. In its review of components associated with item 79, 

for which the applicant cited generic Note E, the staff noted that the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program proposes to manage the 

aging of stainless steel piping, piping components, and piping elements through the use of 
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visual inspections of plant components for evidence of degradation (see staff evaluation of this 

program in SER Section 3.0.3.2.15). The staff also noted that the applicant identified 

components such as floor drains and building sumps that may be exposed to a variety of types 

of treated and untreated water as well as to raw water for the determination of aging effects. 

The applicant stated that these environments may contain contaminants, including oil and boric 

acid, as well as originally treated water that is not monitored by a chemistry program. The staff 

further noted there are no water chemistry controls in these environments (i.e., drains and 

sumps) and, therefore, the Open-Cycle Cooling Water System Program could not properly 

manage this system. The staff finds that the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components AMP is appropriate because its surveillance techniques can 

identify and will adequately manage this aging effect. 

The staff concludes that the applicant has demonstrated that it will adequately manage the 

effects of aging of these components so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.3.2.1.6 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion 

and Fouling 

LRA Table 3.3.1, item 81 addresses copper alloy piping, piping components, and piping 

elements exposed to raw water, which are managed for loss of material due to pitting, crevice, 

and microbiologically-influenced corrosion and fouling. The LRA credits the Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program to manage the 

aging effect. The GALL Report recommends AMP XI.M20, “Open-Cycle Cooling Water 

System,” to ensure that the applicant adequately manages these aging effects. The associated 

AMR item cites generic Note E, indicating that the LRA AMR is consistent with the GALL Report 

item for material, environment, and aging effect, but a different AMP is credited. 

For those items associated with generic Note E, the GALL Report recommends the Open-Cycle 

Cooling Water System AMP, which recommends using surveillance and control techniques to 

manage the aging of these items. In its review of components associated with item 3.3.1.81, for 

which the applicant cited generic Note E, the staff noted that the Inspection of Internal Surfaces 

in Miscellaneous Piping and Ducting Components Program proposes to manage the aging of 

copper alloy piping, piping components, and piping elements through the use of visual 

inspections of plant components for evidence of degradation (see staff evaluation of this 

program in SER Section 3.0.3.2.15). The staff also noted that the applicant identified 

components such as floor drains and building sumps that may be exposed to a variety of types 

of treated and untreated water as well as to raw water for the determination of aging effects. 

The staff further noted that there are no water chemistry controls in these environments (i.e., 

drains and sumps) and therefore, the Open-Cycle Cooling Water System Program could not 

properly manage this aging effect. The staff finds the applicant’s use of the Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program acceptable 

because its surveillance techniques can identify and adequately manage the effects of aging. 

The staff concludes that the applicant has demonstrated that it will adequately manage the 

effects of aging of these components so that their 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 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 aging effects. On the basis of its review, the staff concludes that 

the AMR results, which the applicant claimed to be consistent with the GALL Report, are 

consistent. Therefore, the staff concludes that the applicant has demonstrated that the effects 
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of aging for these components will be adequately managed so that their intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.3.2.2 Aging Management Review Results Consistent with the Generic Aging Lessons 

Learned Report for Which Further Evaluation Is Recommended 

In LRA Section 3.3.2.2, the applicant further evaluates aging management, as recommended by 

the GALL Report, for the auxiliary system components and provides information concerning how 

it will manage the following aging effects: 

 cumulative fatigue damage 

 reduction of heat transfer due to fouling 

 cracking due to SCC 

 cracking due to SCC and cyclic loading 

 hardening and loss of strength due to elastomer degradation 

 reduction of neutron-absorbing capacity and loss of material due to general corrosion 

 loss of material due to general, pitting, and crevice corrosion 

 loss of material due to general, pitting, crevice, and microbiologically-influenced 

corrosion 

 loss of material due to general, pitting, crevice, microbiologically-influenced corrosion 

and fouling 

 loss of material due to pitting and crevice corrosion 

 loss of material due to pitting, crevice, and galvanic corrosion 

 loss of material due to pitting, crevice, and microbiologically-influenced corrosion 

 loss of material due to wear 

 loss of material due to cladding breach 

 QA for aging management of nonsafety-related components 

For component groups evaluated in the GALL Report, for which the applicant claimed 

consistency with the report and for which the report recommends further evaluation, the staff 

reviewed the applicant’s evaluation to determine if it adequately addressed the issues further 

evaluated. In addition, the staff reviewed the applicant’s further evaluations against the criteria 

contained in SRP-LR Section 3.3.2.2. The staff’s review of the applicant’s further evaluation 

follows. 

3.3.2.2.1 Cumulative Fatigue Damage 

In LRA Section 3.3.2.2.1, the applicant stated that evaluation of cumulative fatigue damage of 

auxiliary system piping and heat exchangers, and the number of significant lifts assumed for 

design of fuel handling equipment is a TLAA, as defined in 10 CFR 54.3. TLAAs are evaluated 

in accordance with 10 CFR 54.21(c)(1). The applicant further stated that LRA Section 4.7.1 

describes the evaluation of fuel-handling equipment TLAAs. The applicant stated that its piping 

outside the RCPB is designed to ASME III Class 2, Class 3, and ANSI B31.1, all of which 

require a reduction in the allowable secondary stress range if more than 7,000 full-range 

thermal cycles are expected in a design lifetime. LRA Section 4.3.5 describes the evaluation of 

these cyclic piping design TLAAs. The applicant further stated that a survey of other than 
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ASME III Class 1 pressure-retaining components (vessels, heat exchangers, pumps, and 

valves) discovered two Class 2 heat exchangers in each unit, the CVCS letdown and 

regenerative heat exchangers. LRA Section 4.3.2.9 describes the evaluation of this TLAA. 

The staff reviewed LRA Section 3.3.2.2.1 against the criteria in SRP-LR Section 3.3.2.2.1, which 

states that fatigue is TLAA, as defined in 10 CFR 54.3. TLAAs are required to be evaluated in 

accordance with 10 CFR 54.21(c)(1). Section 4.3, “Metal Fatigue Analysis,” of the SRP-LR 

addresses this TLAA separately. The staff finds the applicant’s AMR results are consistent with 

the recommendations of the GALL Report and SRP-LR, except for the following noted areas. 

The staff noted that the Summary Description in LRA Section 4.3.5 states that the implicit 

fatigue analyses discussed in the section are applicable to all ASME Code Class 2 and 3 and 

ANSI B31.1 piping, piping components, and piping elements. The staff noted that it is not clear 

if the LRA includes all corresponding AMR items for applicable ASME Code Class 2 and 3 or 

ANSI B31.1 piping, piping components, and piping elements within the scope of license 

renewal. The staff also noted that this includes those components in the ESF Systems (LRA 

Section 3.2), Auxiliary Systems (LRA Section 3.3), and Steam and Power Conversion Systems 

(LRA Section 3.4). By letter dated July 21, 2010, the staff issued RAI 4.3-13 requesting the 

applicant to clarify if the LRA includes all applicable AMR items with an aging effect of 

cumulative fatigue damage for those components within the scope of license renewal. If not, 

the staff asked the applicant to justify why the LRA does not include all corresponding AMR 

items on cumulative fatigue damage for applicable ASME Code Class 2 and 3 or ANSI B31.1 

piping, piping components, and piping elements within the scope of license renewal. Further, 

the staff asked the applicant to identify all component types that are within the scope of the 

implicit fatigue analyses for ASME Code Class 2 and 3 components and B31.1 components in 

LRA Section 4.3.5 and, therefore, should be within the scope of applicable component-specific 

AMR items on cumulative fatigue damage. The staff previously identified this as Open 

Item 4.3-1. 

In its response dated August 12, 2010, the applicant stated that, for auxiliary systems, additional 

AMR line items were added to the LRA. The applicant further stated that LRA Tables 3.3.2-8, 

3.3.2-21, and 3.3.2-30 required the addition of AMR line items. The staff also noted that the 

applicant amended LRA Table 3.3.2-8 to include the associated AMR item consistent with the 

GALL Report AMR item VII.E-16, LRA Table 3.3.2-21 to include the associated AMR item 

consistent with the GALL Report AMR item VII.E1-8, and LRA Table 3.3.2-30 to include the 

associated AMR item consistent with the GALL Report AMR item VIII B1-10. The staff 

confirmed that these additional AMR items are consistent with the associated GALL Report 

AMR items. The staff’s evaluation for ANSI B31.1 and ASME III Class 2 and 3 piping is 

documented in SER Section 4.3.5.2. 

Based on its review of the amended LRA Tables 3.3.2-8, 3.3.2-21 and 3.3.2-30, the staff finds 

the applicant’s response to RAI 4.3-13, part 3, and the additions of these AMR items acceptable 

because they are consistent with the GALL Report AMR items VII.E-16, VII.E1-8 and VIII B1-10. 

The staff’s concern described in RAI 4.3-13 is resolved, and this portion of Open Item 4.3-1 is 

closed. 

Based on its review, the staff concludes that the applicant’s proposal to manage cumulative 

fatigue damage in auxiliary system piping and heat exchangers, and the number of significant 

lifts assumed for design of fuel handling equipment meets the SRP-LR Section 3.3.2.2.1 criteria. 

For those items that apply to LRA Section 3.3.2.2.1, the staff determines that the LRA is 

consistent with the GALL Report. The applicant has demonstrated that it will adequately 

manage the effects of aging so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). SER 

Section 4.3 documents the staff’s review of the applicant’s evaluation of the TLAA for these 

components. 
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3.3.2.2.2 Reduction of Heat Transfer Due to Fouling 

LRA Section 3.3.2.2.2 refers to LRA Table 3.3.1, item 3.3.1.3, and addresses reduction of heat 

transfer due to fouling of stainless steel heat exchanger tubes exposed to treated water for 

auxiliary systems. The applicant stated that this item is not applicable because it only applies to 

BWRs. 

The staff reviewed SRP-LR Table 3.3-1, item 3, and noted that, contrary to the applicant’s 

statement, this item applies to both BWRs and PWRs. Additionally, although not listed in the 

GALL Report Table VII.A3, associated with the PWR spent fuel pool cooling system, the staff 

noted that the documented basis from NUREG-1833 for adding the related item, AP-62, was a 

precedent established in the R.E. Ginna SER, NUREG-1786. The environment specifically 

noted in that SER was “treated water-borated.” As such, the omission from the GALL Report 

Table VII.A3 appears to have been inadvertent and is being addressed in the update to the 

GALL Report currently in progress. 

The staff reviewed LRA Sections 2.3.3 and Section 3.3 and identified two items with a reduction 

of heat transfer due to fouling for stainless steel heat exchanger tubes exposed to treated 

borated water in Table 3.3.2-2, “Spent Fuel Pool Cooling and Cleanup System,” and 

Table 3.3.2-8, “Nuclear Sampling System.” In both instances, the applicant cited generic 

Note H, indicating that for the items, the aging effect is not in the GALL Report for this 

component, material, and environment combination. The LRA states that the Water Chemistry 

and One-Time Inspection Programs would manage the reduction of heat transfer for these 

components. SER Section 3.3.2.3.2 discusses the staff’s review for these items. 

3.3.2.2.3 Cracking Due to Stress Corrosion Cracking 

The staff reviewed LRA Section 3.3.2.2.3 against the following criteria in SRP-LR 

Section 3.3.2.2.3: 

 LRA Section 3.3.2.2.3.1 addresses cracking due to SCC in the stainless steel 

components of a BWR standby liquid control system, stating that this aging effect is not 

applicable to PVNGS; it is applicable to BWRs only. SRP-LR Section 3.3.2.2.3.1 states 

that cracking due to SCC could occur in the stainless steel piping, piping components, 

and piping elements of the BWR standby liquid control system that are exposed to 

sodium pentaborate solution greater than 60 degrees C (140 degrees F). The staff finds 

that SRP-LR Section 3.3.2.2.3, item 1 is not applicable because the PVNGS units are 

PWRs, and the staff guidance in this SRP-LR section is only applicable to BWRs. 

 LRA Section 3.3.2.2.3.2 refers to LRA Table 3.3.1, item 3.3.1.5, and addresses cracking 

due to SCC in stainless steel and stainless steel clad steel heat exchangers exposed to 

treated water greater than 60 degrees C (140 degrees F). The applicant stated that this 

item is not applicable to PVNGS, because it only applies to BWRs. 

 The staff reviewed LRA Section 3.3.2.2.3.2 against the criteria in SRP-LR 

Section 3.3.2.2.3, item 2, which states that cracking due to SCC could occur in stainless 

steel and stainless clad steel heat exchanger components exposed to treated water 

greater than 60 degrees C (140 degrees F). It continued by recommending further 

evaluation of a plant-specific AMP to ensure this aging effect was adequately managed 

and noted that acceptance criteria are described in Appendix A.1 of the SRP-LR. In 

addition, the staff noted that, contrary to the applicant’s statement, the related item 

applies to both BWRs and PWRs. 

 Furthermore, in reviewing LRA Table 3.3.2-30, the staff noted that the applicant listed 

the sample cooler heat exchanger with an aging mechanism of cracking for stainless 

steel exposed to secondary water. As such, the basis for the applicant’s determination, 

that this item was not applicable to PVNGS, was not clear to the staff. By letter dated 
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April 28, 2010, the staff issued RAI 3.3.2.2.3-1 requesting the applicant to provide its 

basis for why SRP-LR Section 3.3.2.2.3.2 was not applicable or, if it was applicable, to 

explain how aging will be managed. 

 In its response, dated May 21, 2010, the applicant stated that SRP-LR Table 3.3.1, 

item 5 referenced SRP-LR Section 3.3.2.2.3.2, which is related to the GALL Report, 

items VII.E3-3 and VIIE3-19. These related items only appear in the GALL Report 

tables associated with BWR reactor water cleanup systems; however, the applicant also 

noted that the stainless steel sample cooler exposed to secondary water will experience 

cracking, which is managed by the Water Chemistry and One-Time Inspections 

Programs, consistent with the GALL Report, item VIII.F-3. The staff noted that this item 

is related to SRP-LR further evaluation Section 3.4.2.2.6. 

 The staff reviewed the applicant’s response to RAI 3.3.2.2.3-1 and finds the response 

acceptable because the applicant addressed the in-scope heat exchangers components 

constructed of stainless steel and stainless clad steel exposed to treated water greater 

than 60 degrees C (140 degrees F) using item VIII.F-3, and it will manage these 

components as indicated in SRP-LR Section 3.4.2.2.6. The staff finds the applicant’s 

evaluation of SRP-LR Section 3.3.2.2.3, item 2 through SRP-LR further evaluation in 

Section 3.4.2.2.6 an acceptable approach. 

 LRA Section 3.3.2.2.3 refers to LRA Table 3.3.1, item 3.3.1.6, and addresses stainless 

steel diesel engine exhaust piping, piping components, and piping elements exposed to 

diesel exhaust, which the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program manages cracking due to SCC. The applicant addressed 

the further evaluation criteria of the SRP-LR by stating in the AMP that this program will 

perform visual inspections to detect aging effects that could result in loss of component 

intended function. 

 The staff reviewed LRA Section 3.3.2.2.3.3 against the criteria in SRP-LR 

Section 3.3.2.2.3, item 3, which states that cracking due to SCC could occur in stainless 

steel diesel engine exhaust piping, piping components, and piping elements exposed to 

diesel exhaust. The SRP-LR also states that the GALL Report recommends further 

evaluation of a plant-specific AMP to ensure that the applicant adequately manages 

these aging effects. SER Section 3.0.3.2.15 documents the staff’s evaluation of the 

applicant’s Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program. In its review of components associated with item 3.3.1.6, the 

staff finds the applicant’s proposal to manage aging using the Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program acceptable. This program will 

include volumetric evaluations of the internal surfaces of stainless steel components 

exposed to diesel exhaust and will perform visual inspections during periodic 

maintenance, predictive maintenance, surveillance testing, and corrective maintenance. 

Both volumetric evaluations and visual inspections are capable of detecting cracking due 

to SCC that could result in a loss of component intended function. 

 Based on the program identified, the staff concludes that the applicant’s programs meet 

the SRP-LR Section 3.3.2.2.3, item 3, criteria. For those items that apply to LRA 

Section 3.3.2.2.3, item 3, the staff determines that the LRA is consistent with the GALL 

Report. The staff also finds that the applicant has demonstrated that the effects of aging 

will be adequately managed so that the intended functions will be maintained consistent 

with the CLB during the period of extended operation, as required by 10 CFR 

54.21(a)(3). 

The staff determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 
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function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

3.3.2.2.4 Cracking Due to Stress Corrosion Cracking and Cyclic Loading 

The staff reviewed LRA Section 3.3.2.2.4 against the following criteria in SRP-LR 

Section 3.3.2.2.4: 

 LRA Section 3.3.2.2.4.1 refers to Table 3.3.1, item 7, and addresses cracking due to 

SCC and cyclic loading in stainless steel non-regenerative heat exchanger components 

exposed to borated water greater than 60 degrees C (140 degrees F). The LRA states 

that the Water Chemistry and One-Time Inspection Programs will manage cracking due 

to SCC and cyclic loading for the stainless steel CVCS letdown (non-regenerative) heat 

exchanger components exposed to treated borated water, where temperature and 

radioactivity of the shell-side water are monitored by installed instrumentation, and the 

One-Time Inspection Program is selected in lieu of eddy current testing of tubes. The 

applicant also noted that the staff accepted this position in NUREG-1785, “Safety 

Evaluation Report Related to the License Renewal of H.B. Robinson Steam Electric 

Plant, Unit 2.” 

 The staff reviewed LRA Section 3.3.2.2.4, item 1, against the criteria in SRP-LR 

Section 3.3.2.2.4, item 1, which states that the existing program relies on monitoring and 

control of primary water chemistry in PWRs to manage cracking due to SCC, and that 

the effectiveness of the Water Chemistry Control Program should be verified to ensure 

that cracking does not occur. SRP-LR Section 3.3.2.2.4.1 further states that the GALL 

Report recommends a plant-specific AMP to verify the absence of cracking due to SCC 

and cyclic loading and that an acceptable verification program includes temperature and 

radioactivity monitoring of the shell side water and eddy current testing of tubes. 

 The staff reviewed the applicant’s Water Chemistry and One-Time Inspection Programs 

in SER Sections 3.0.3.2.1 and 3.0.3.1.6, respectively. The staff noted that the various 

non-regenerative heat exchanger components can be subjected to enhanced visual 

inspection or volumetric inspection to detect cracking. The applicant’s One-time 

Inspection Program uses representative sampling to detect aging of components with 

similar environments since all these components are subjected to a treated borated 

water environment. If the applicant discovers any cracking during execution of its 

One-Time Inspection Program, it will evaluate the cracking through its Corrective Action 

Program where the need for expanded inspection sites, periodic inspections, and data 

trending. However, the applicant did not specify the NDE methodology that would be 

used as an alternative to eddy current testing of the heat exchanger tubes. 

 On July 8, 2010, the staff held a teleconference call with the applicant to discuss its 

concerns associated with the NDE method that will be used during the one-time 

inspection and the justification of the proposed methodology based on plant-specific and 

industry operating experience. In LRA Amendment 20, dated July 21, 2010, the 

applicant clarified its use of the One-Time Inspection Program by stating that it will select 

heat exchanger tubes in a similar environment and made of similar material to the 

non-regenerative heat exchanger tubes. The applicant also stated that this program will 

conduct eddy current testing of the stainless steel heat exchanger tubes in a borated 

water environment that is above the threshold temperature for cracking in stainless steel. 

The staff finds this clarification acceptable because eddy current testing, the NDE 

method specified by the applicant, is capable of identifying cracking in stainless steel 

heat exchanger tubes and, therefore, is able to verify the absence of cracking due to 

SCC and cyclic loading. 
Aging Management Review Results 

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 The staff concludes that the applicant’s programs meet SRP-LR Section 3.3.2.2.4, 

item 1 criteria. For those line items that apply to LRA Section 3.3.2.2.4, item 1, the staff 

determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

functions will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

 LRA Section 3.3.2.2.4.2 refers to Table 3.3.1, item 8, and addresses cracking due to 

SCC and cyclic loading in stainless steel PWR regenerative heat exchanger components 

exposed to borated water greater than 60 degrees C (140 degrees F). The LRA states 

that the Water Chemistry and the One-Time Inspection Programs will manage this aging 

effect for the stainless steel CVCS and nuclear sampling systems heat exchanger 

components exposed to treated borated water. The LRA also noted that the one-time 

inspection will include selected components at susceptible locations. 

 The staff reviewed LRA Section 3.3.2.2.4, item 2 against the criteria in SRP-LR 

Section 3.3.2.2.4, item 2, which states that management of this aging effect relies on 

monitoring and control of primary water chemistry in PWRs, but control of water 

chemistry does not preclude cracking due to SCC and cyclic loading. The SRP-LR 

further states that the effectiveness of the Water Chemistry Control Program should be 

verified and recommends that the applicant evaluate a plant-specific AMP to ensure that 

it adequately manages these aging effects. Appendix A.1 of the SRP-LR describes the 

acceptance criteria. 

 The staff reviewed the applicant’s Water Chemistry and One-Time Inspection Programs 

in SER Sections 3.0.3.2.1 and 3.0.3 1.6, respectively. The staff also noted that the 

various regenerative heat exchanger components can be subjected to enhanced visual 

inspection or volumetric inspection to detect cracking. The applicant’s One-time 

Inspection Program uses representative sampling to detect aging of components with 

similar environments since all these components are subjected to a treated borated 

water environment. If the applicant discovers any cracking during execution of its 

One-Time Inspection Program, it will evaluate the cracking through its Corrective Action 

Program, which includes the need for expanded inspection sites, periodic inspections, 

and data trending. The staff concludes that cracking in stainless steel PWR 

regenerative heat exchanger components exposed to borated water, will be adequately 

managed by the applicant’s One-time Inspection Program in lieu of a plant-specific 

program, through the period of extended operation because detection methods will 

detect cracking and corrective action will consider expansion of the number of inspection 

sites, periodic inspection, and trending of data. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.4.2 criteria. For those items that apply to LRA 

Section 3.4.2.2.4.2, the staff determines that the LRA is consistent with the GALL 

Report. The applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 LRA Section 3.3.2.2.4.3 refers to LRA Table 3.3.1, item 3.3.1.9, and addresses stainless 

steel high-pressure pump casing in PWR CVCS exposed to treated borated water 

(internal), which are being managed for cracking due to SCC and cyclic loading by the 

Water Chemistry Program and One-Time Inspection Program. The applicant addressed 

the further evaluation criteria of the SRP-LR by stating that the Water Chemistry 

Program and the One-Time Inspection Program will manage cracking due to SSC and 

cyclic loading for stainless steel pump casings exposed to treated borated water. The 
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applicant stated the one-time inspection will include selected components at susceptible 

locations. 

 The staff reviewed LRA Section 3.3.2.2.4.3 against the criteria in SRP-LR 

Section 3.3.2.2.4, item 3, which states that the existing AMP relies on monitoring and 

control of primary water chemistry in PWRs to manage the aging effects of cracking due 

to SCC. The SRP-LR further states that that control of water chemistry does not 

preclude cracking due to SCC and cyclic loading, and the effectiveness of the Water 

Chemistry Control Program should be verified to ensure that cracking does not occur. 

The SRP-LR also states that the GALL Report recommends that the applicant evaluate 

a plant-specific AMP to verify the absence of cracking due to SCC and cyclic loading to 

ensure that it adequately manages these aging effects. 

 SER Sections 3.0.3.2.1 and 3.0.3.1.6 document the staff’s evaluation of the applicant’s 

Water Chemistry Program and One-Time Inspection Program, respectively. The staff 

noted that the Water Chemistry Program controls the chemical environment to ensure 

that the aging effects due to contaminants are limited by managing the primary and 

secondary water. The staff noted that this is accomplished by limiting the concentration 

of chemical species known to cause corrosion and adding chemical species known to 

inhibit degradation by their influence on pH and dissolved oxygen levels. The staff also 

noted that this program is effective in creating an environment that is not conducive for 

cracking to occur in areas of intermediate and high flow, where thorough mixing takes 

place and the monitoring samples are representative of actual conditions. The staff 

noted that the applicant’s One-Time Inspection Program will conduct NDE inspections of 

a representative group of components in order to verify the effectiveness of the Water 

Chemistry Program in low flow and stagnant areas. The applicant’s proposal to manage 

the SCC and cyclic loading of stainless steel high-pressure pump casing is consistent 

with GALL Report item VII.E1-7. In its review of components associated with item 9, the 

staff finds the applicant’s proposal to manage aging using the Water Chemistry Program 

and One-Time Inspection Program acceptable. because the Water Chemistry Program 

will create an environment that is not conducive for cracking to occur, the One-Time 

Inspection Program will verify the effectiveness of the water chemistry, and the 

applicant’s use of these programs is consistent with the GALL Report. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.4, item 3 criteria. For those items that apply to LRA 

Section 3.3.2.2.4.3, the staff determines that the LRA is consistent with the GALL 

Report. The applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation as required by 10 CFR 54.21(a)(3). 

 LRA section 3.3.2.2.4 refers to Table 3.3.1, item 3.3.1.10, and addresses high-strength 

steel closure bolting exposed to air with steam or water leakage in the auxiliary systems. 

The GALL Report recommends use of AMP XI.M18, “Bolting Integrity,” to manage 

cracking due to SCC and cyclic loading for this component group. The applicant stated 

that this item is not applicable because it has no in-scope, high-strength steel closure 

bolting exposed to air with steam or water leakage in the auxiliary systems. The staff 

reviewed LRA Sections 2.3.3 and 3.3 and confirmed that the applicant’s LRA does not 

have any AMR results for the auxiliary systems that include high-strength steel closure 

bolting in the auxiliary systems exposed to air with steam or water leakage. During its 

on-site audit of the applicant’s Bolting Integrity Program, the staff also confirmed that the 

applicant does not have any in-scope, high-strength closure bolting in its auxiliary 

systems during audit interviews. Based on its review of the LRA and applicant audit 

interviews, the staff confirmed that there is no in-scope steel closure bolting exposed to 
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air with steam or water leakage in the auxiliary systems, and, therefore, finds the 

applicant’s determination acceptable. 

Based on the programs identified above, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.4 criteria. For those items that apply to LRA Section 3.3.2.2.4, the staff 

determines that the LRA is consistent with the GALL Report. The applicant has demonstrated 

that the effects of aging will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.3.2.2.5 Hardening and Loss of Strength Due to Elastomer Degradation 

The staff reviewed LRA Section 3.3.2.2.5 against the following criteria in SRP-LR 

Section 3.3.2.2.5: 

 LRA Section 3.3.2.2.5.1 refers to LRA Table 3.3.1, item 3.3.1.11, and addresses 

elastomeric seals of heating and ventilation systems exposed to air indoor uncontrolled, 

which are managed for hardening and loss of strength due to degradation by the 

External Surfaces Monitoring and Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components Programs. The applicant addressed the further 

evaluation acceptance criteria of the SRP-LR by stating that the programs will manage 

hardening and loss of strength from degradation for elastomeric internal and external 

surfaces exposed to ventilation atmosphere in locations where the ambient temperature 

cannot be shown to be less than 95 degrees F. 

 The staff reviewed LRA Section 3.3.2.2.5.1 against the criteria in SRP-LR 

Section 3.3.2.2.5, item1, which states that hardening and loss of strength due to 

elastomer degradation could occur in elastomeric seals and components of heating and 

ventilation systems exposed to air-indoor uncontrolled (internal or external). The 

SRP-LR recommends further evaluation of a plant-specific AMP to ensure that the aging 

effect is adequately managed. Acceptance criteria are described in Branch Technical 

Position RLSB-1 (Appendix A.1 of the SRP-LR). 

 In its review of components associated with LRA Table 3.3.1, item 11, the staff noted 

that the GALL Report, in Table XI.D, “Environments,” provides a basis for the applicant 

to use 95 degrees F as a threshold temperature, below which thermal aging of organic 

elastomers can be considered insignificant during the period of extended operation. 

However, the GALL Report does not provide a basis for using this temperature to 

preclude other potential elastomeric degradation due to exposure to ozone, oxidation, or 

radiation. By letter dated February 19, 2010, the staff issued RAI 3.3.2.2.5.1-1, asking 

the applicant to identify the systems containing in-scope elastomeric components that 

will be inspected and to determine if use of the 95 degree F criterion results in excluding 

any in-scope elastomeric components from aging management. 

 In its response, dated March 24, 2010, the applicant identified seven mechanical 

systems included in LRA Section 3.3.2.2.5.1: 

(1) the containment purge system 

(2) the fuel building HVAC system 

(3) the auxiliary building HVAC system 

(4) the containment HVAC system 

(5) the diesel building HVAC system 

(6) the control building HVAC system 
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(7) the miscellaneous buildings HVAC system. 

 The applicant stated that none of the elastomeric flexible connectors in these systems 

are excluded from aging management based on the 95 degree F criterion. The staff 

noted that the applicant’s list of HVAC systems, where aging management of 

elastomeric components is not excluded, is similar to the list of systems for which the 

GALL Report recommends aging management of elastomeric components. The staff 

finds the applicant’s response acceptable because the systems listed by the applicant 

are similar to the systems recommended in the GALL Report, and the use of the 

95 degree F criterion does not result in unacceptable exclusion of components from 

aging management. The staff’s concern described in RAI 3.3.2.2.5.1-1 is resolved. 

 SER Sections 3.0.3.2.14 and 3.0.3.2.15 document the staff’s evaluation of the 

applicant’s External Surfaces Monitoring Program and Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program, respectively. The staff noted 

that both GALL Report AMPs manage loss of material for steel components; however, 

for each of these programs, the applicant has taken exceptions to the GALL Report 

AMPs. These exceptions increase the scope of the materials managed to include 

elastomers and augment the visual inspections specified in the GALL Report with 

physical manipulations to verify absence of hardening or loss of strength for elastomers. 

The staff finds the applicant’s proposal to manage aging using the External Surfaces 

Monitoring Program and Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program acceptable because the applicant will perform, 1) visual 

inspections of external surfaces during engineering walkdowns; 2) visual inspections of 

internal surfaces during periodic maintenance, predictive maintenance, surveillance 

testing, and corrective maintenance; and 3) physical manipulation may be used during 

the visual inspections to verify absence of hardening or loss of strength for elastomers. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.5, item 1 criteria. For those items that apply to LRA Section 

3.3.2.2.5.1, the staff determines that the LRA is consistent with the GALL Report and 

that the applicant has demonstrated that the effects of aging will be adequately managed 

so that the intended function(s) will be maintained consistent with the CLB during the 

period of extended operation, as required by 10 CFR 54.21(a)(3). 

 LRA Section 3.3.2.2.5.2 refers to Table 3.3-1, item 12, and addresses the elastomeric 

boot seal for the safety injection pump suction strainer in the refueling water tank 

exposed to treated borated water, which is being managed for hardening and loss of 

strength due to degradation by the Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program. The applicant addressed the further evaluation criteria 

by stating that the program will manage hardening and loss of strength from degradation 

for the boot seal. 

 The staff reviewed LRA Section 3.3.2.2.5.2 against the criteria in SRP-LR 

Section 3.3.2.2.5, item 2. This states that hardening and loss of strength due to 

elastomeric degradation could occur in elastomeric linings of filters, valves, and ion 

exchangers in spent fuel pool cooling and cleanup systems exposed to treated water or 

to treated borated water. It also recommends further evaluation of a plant-specific AMP 

to ensure that the aging effect is adequately managed. BTP RLSB-1 describes 

acceptance (Appendix A.1 of the SRP-LR). 

 LRA Section 3.3.2.2.5.2 states that the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components AMP will manage hardening and loss of strength for the 

elastomer boot seal for the safety injection pump suction strainer in the refueling water 

tank that is exposed to treated borated water. The staff notes that the applicant did not 
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address elastomeric linings of filters, valves, and ion exchangers in spent fuel pool 

cooling and cleanup systems. The staff also notes that a search of the applicant’s 

UFSAR confirmed that no in-scope elastomeric linings of filters, valves, and ion 

exchangers exposed to treated water or to treated borated water are present in the 

spent fuel pool cooling and cleanup systems except for the boot seal. 

 SER Section 3.0.3.2.15 documents the staff’s evaluation of the applicant’s Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program. The staff noted 

that the GALL Report Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components AMP manages loss of material for steel components. However, 

the applicant has taken exceptions to the GALL Report AMP that increase the scope of 

the materials managed to include elastomers and augment the visual inspections 

specified in the GALL Report with physical manipulations to verify absence of hardening 

or loss of strength for elastomers. In its review of components associated with item 12, 

the staff finds the applicant’s proposal to manage aging using the Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program acceptable because the 

applicant will perform visual inspections during periodic maintenance, predictive 

maintenance, surveillance testing, and corrective maintenance, and the visual 

inspections will be augmented by physical manipulation to verify absence of hardening 

or loss of strength for elastomers. 

 Based on the programs identified, the staff concludes that the applicant’s program meets 

SRP-LR Section 3.3.2.2.5, item 2 criteria. For those items that apply to LRA 

Section 3.3.2.2.5.2, the staff determines that the LRA is consistent with the GALL 

Report. The applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended functions will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

Based on the programs identified above, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.5 criteria. For those items that apply to LRA Section 3.3.2.2.5, the staff 

determines that the LRA is consistent with the GALL Report. The staff finds that the applicant 

has demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

3.3.2.2.6 Reduction of Neutron-Absorbing Capacity and Loss of Material Due to General 

Corrosion 

LRA Section 3.3.2.2.6 refers to Table 3.3.1, item 3.3.1.13, which addresses boral, boron steel 

spent fuel storage racks, and neutron-absorbing sheets exposed to treated water or treated 

borated water, which are being managed for a reduction of neutron-absorbing capacity and loss 

of material due to general corrosion. The GALL Report recommends use of a plant-specific 

AMP to manage aging. The applicant stated that this item is not applicable because it does not 

use boral or boron steel in its spent fuel storage racks to maintain subcriticality. The staff 

reviewed LRA Sections 2.3.3 and 3.3 and confirmed that the applicant’s LRA does not have any 

AMR results for the auxiliary systems that include boral or boron steel or other 

neutron-absorbing sheets in the auxiliary systems exposed to treated water or treated borated 

water. The staff also reviewed the spent fuel pool criticality analysis in the UFSAR and 

confirmed that the analysis does not rely on boral or boron steel neutron-absorbing materials. 

Based on its review of the LRA and UFSAR, the staff confirmed that there is no boral, boron 

steel spent fuel storage racks, neutron-absorbing sheets exposed to treated water or treated 

borated water in the auxiliary systems, and, therefore, finds the applicant’s determination 

acceptable. 
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3.3.2.2.7 Loss of Material Due to General, Pitting, and Crevice Corrosion 

The staff reviewed LRA Section 3.3.2.2.7 against the following criteria in SRP-LR 

Section 3.3.2.2.7: 

 LRA Section 3.3.2.2.7 refers to LRA Table 3.3.1, items 3.3.1.14, 3.3.1.15, and 3.3.1.16, 

and addresses cast iron and carbon steel piping and their components and elements 

including tubing, valves, and tanks in the RCP oil collection system, exposed to 

lubricating oil. The Lubricating Oil Analysis and One-Time Inspection Programs manage 

these components for loss of material due to general, pitting, and crevice corrosion and 

SCC. The applicant addressed the further evaluation criteria of the SRP-LR by stating 

that it will include a one-time inspection of selected components at susceptible locations 

where contaminants such as water could accumulate. The applicant further stated that 

the one-time inspection will assess the thickness of the lower portion of a representative 

sample of RCP lubricating oil collection tanks. 

 The staff reviewed LRA Section 3.3.2.2.7.1 against the criteria in SRP-LR 

Section 3.3.2.2.7, item 1, which states that loss of material due to general, pitting, and 

crevice corrosion could occur in steel piping, their components, and elements, including 

the tubing, valves, and tanks in the RCP oil collection system, exposed to lubricating oil 

(as part of the fire protection system). It also states that the existing AMP relies on the 

periodic sampling and analysis of lubricating oil to maintain contaminants within 

acceptable limits, thereby preserving an environment that is not conducive to corrosion. 

It further states that control of lube oil contaminants may not always have been adequate 

to preclude corrosion, and corrosion may occur at locations in the RCP oil collection tank 

where water from wash downs may accumulate. The effectiveness of the program, 

therefore, should be verified with a one-time inspection to ensure that corrosion is not 

occurring. 

 SER Sections 3.0.3.2.16 and 3.0.3.1.6 document the staff's review of the LRA 

Lubricating Oil Analysis Program and One-Time Inspection Program, respectively. In its 

review of the cast iron and carbon steel components associated with the LRA items 

listed above, the staff finds the applicant’s proposal to manage aging using the 

Lubricating Oil Analysis and One-Time Inspection Programs acceptable because the 

Lubricating Oil Analysis Program provides for periodic sampling of lubricating oil to 

maintain contaminants at acceptable limits to preclude loss of material due to general, 

pitting, and crevice corrosion. In addition, the applicant will perform one-time inspections 

of select steel piping, piping components, and piping elements, including the tubing, 

valves, and tanks in the RCP oil collection system, exposed to lubricating oil, for loss of 

material due to general, pitting, and crevice corrosion. This one-time inspection will 

verify the effectiveness of the Lubricating Oil Analysis Program in applicable auxiliary 

systems, following the GALL Report recommendation that the “One Time Inspection” is 

an acceptable AMP to verify the effectiveness of the applicant’s Lubricating Oil Analysis 

Program. 

 Based on the programs identified, the staff finds that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.7, item 1 criteria. For those items that apply to LRA 

Section 3.3.2.2.7.1, the staff determines that the LRA is consistent with the GALL Report 

and that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 LRA Section 3.3.2.2.7 addresses loss of material due to general, pitting, and crevice 

corrosion in steel components in the BWR reactor water cleanup and shutdown cooling 

systems exposed to treated water, stating that this aging effect is not applicable; it is 
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applicable to BWRs only. The staff finds that SRP-LR Section 3.3.2.2.7 is not applicable 

because the PVNGS units are PWRs, and the staff guidance in this SRP-LR section is 

only applicable to BWRs. 

 LRA Section 3.3.2.2.7 refers to LRA Table 3.3.1, item 18, and addresses stainless steel 

and steel diesel engine exhaust piping, piping components, and piping elements 

exposed to diesel exhaust, which the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program manages for loss of material due to general 

(steel only), pitting, and crevice corrosion. The applicant addressed the further 

evaluation criteria of the SRP-LR in the AMP by stating that this program will perform 

visual inspections to detect aging effects that could result in loss of component intended 

function. 

 The staff reviewed LRA Section 3.3.2.2.7.3 against the criteria in SRP-LR 

Section 3.3.2.2.7, item 3, which states that loss of material due to general (steel only), 

pitting, and crevice corrosion could occur for steel and stainless steel diesel engine 

exhaust piping, piping components, and piping elements exposed to diesel exhaust. 

The SRP-LR also states that the GALL Report recommends further evaluation of a 

plant-specific AMP to ensure that the applicant adequately manages these aging effects. 

 SER Section 3.0.3.1.15 documents the staff’s evaluation of the applicant’s Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program. In its 

review of components associated with item 3.3.1-18, the staff finds the applicant’s 

proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program acceptable because the program will perform 

visual inspections during periodic maintenance, predictive maintenance, surveillance 

testing, and corrective maintenance. These inspections are capable of detecting pitting 

and crevice corrosion that could result in a loss of component intended function. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

the SRP-LR Section 3.3.2.2.7, item 3 criteria. For those items that apply to LRA 

Section 3.3.2.2.7.3, the staff determines that the LRA is consistent with the GALL 

Report. The applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended functions will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

Based on the programs identified above, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.7 criteria. For those items that apply to LRA Section 3.3.2.2.7, the staff 

determines that the LRA is consistent with the GALL Report. The staff finds that the applicant 

has demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

3.3.2.2.8 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion 

LRA Section 3.3.2.2.8 refers to Table 3.3.1, item 3.3.1.19, and addresses steel piping, piping 

components, and piping elements buried in soil which are being managed for loss of material 

due to general, pitting, crevice, and microbiologically-influenced corrosion by the Buried Piping 

and Tanks Inspection Program. The applicant addressed the further evaluation criteria of the 

SRP-LR by stating that the Buried Piping and Tanks Inspection Program will manage the loss of 

material due to general, pitting, crevice, and microbiologically-influenced corrosion for carbon 

steel external surfaces of buried components. 

The staff reviewed LRA Section 3.3.2.2.8 against the criteria in SRP-LR Section 3.3.2.2.8, which 

states that loss of material due to general, pitting, crevice, and MIC could occur for steel piping, 
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piping components, and piping elements, with or without coating or wrapping, in a soil 

environment. The SRP-LR also states that 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 and the 

effectiveness of the Buried Piping and Tanks Inspection Program should be verified to evaluate 

the inspection frequency and operating experience with buried components, ensuring that loss 

of material is not occurring. 

SER Section 3.0.3.2.12 documents the staff’s evaluation of the applicant’s Buried Piping and 

Tanks Inspection Program. The staff finds the applicant’s proposal to manage aging using the 

Buried Piping and Tanks Inspection Program acceptable because the program requires periodic 

visual inspections of the external surface of buried steel piping, prior to and within the period of 

extended operation, to ensure that the applicant will adequately manage corrosion of external 

surfaces. 

Based on the program identified, the staff concludes that the applicant’s program meets 

SRP-LR Section 3.3.2.2.8 criteria. For those items that apply to LRA Section 3.3.2.2.8, the staff 

determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that their intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

3.3.2.2.9 Loss of Material Due to General, Pitting, Crevice, Microbiologically-Influenced 

Corrosion and Fouling 

The staff reviewed LRA Section 3.3.2.2.9 against the following criteria in SRP-LR 

Section 3.3.2.2.9. 

 LRA Section 3.3.2.2.9.1 refers to Table 3.3.1, item 20, and addresses the loss of 

material due to general, pitting, and crevice corrosion; MIC; and fouling for carbon steel 

components in the fuel oil system. The applicant stated that the Fuel Oil Chemistry 

Program (reviewed in SER Section 3.0.3.2.9) and the One-Time Inspection Program 

(reviewed in SER Section 3.0.3.1.6) manage this aging effect. The applicant also stated 

that the one-time inspection will include selected components at susceptible locations 

where contaminants could accumulate (e.g. stagnant flow locations and tank bottoms). 

 The staff reviewed LRA Section 3.3.2.2.9.1 against the criteria in SRP-LR 

Section 3.3.2.2.9, item 1, which states that loss of material due to general, pitting, and 

crevice corrosion, MIC, and fouling could occur for steel piping, piping components, 

piping elements, and tanks exposed to fuel oil. The GALL Report recommends that 

these aging effects be managed through the use of the Fuel Oil Chemistry Program and 

that the effectiveness of this program be verified through the use of the One-Time 

Inspection Program. The GALL Report also recommends further evaluation because 

corrosion or fouling may occur at locations where contaminants accumulate. 

 The staff noted that LRA Section 3.3.2.2.9.1 identifies appropriate AMPs and lists the 

critical conditions requiring further review (i.e., the potential for fuel oil chemistry control 

to be ineffective in locations where contaminants accumulate). The staff finds that LRA 

Section 3.3.2.2.9.1 is consistent with SRP-LR Section 3.3.2.2.9, item 1. 

 In its review of LRA Section 3.3.2.2.9.1, the staff also reviewed AMR items, which refer 

to LRA Table 3.3.1, item 3.3.1.20 and are associated with LRA Section 3.3.2.2.9.1. In 

this review, the staff noted that the applicant proposes that the AMR items associated 

with item 3.3.1.20 are consistent with the GALL Report in all respects, except the 

applicant has taken some exceptions to the GALL Report AMP (generic Note B) or are 
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consistent with the GALL Report, except that the component is different and that the 

applicant has taken some exceptions to the GALL Report AMP (generic Note D). 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.9.1 criteria. For those items that apply to LRA 

Section 3.3.2.2.9.1, the staff determines that the LRA is consistent with the GALL Report 

and that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 LRA Section 3.3.2.2.9.2 refers to LRA Table 3.3.1, item 21, and addresses steel heat 

exchanger components exposed to lubricating oil, which the Lubricating Oil Analysis 

Program and the One-Time Inspection Program manage for loss of material due to 

general, pitting, or crevice corrosion, MIC, and fouling. The applicant addressed the 

further evaluation criteria of the SRP-LR by stating that it will include a one-time 

inspection of selected components at susceptible locations where contaminants such as 

water could accumulate. 

 The staff reviewed LRA Section 3.3.2.2.9.2 against the criteria in SRP-LR 

Section 3.3.2.2.9, item 2, which states that loss of material due to general, pitting, or 

crevice corrosion, MIC, and fouling could occur for steel heat exchanger components 

exposed to lubricating oil. SRP-LR Section 3.3.2.2.9 item 2 further states that: (1) the 

existing AMP relies on the periodic sampling and analysis of lubricating oil to maintain 

contaminants within acceptable limits, thereby preserving an environment that is not 

conducive to corrosion; (2) the effectiveness of lubricating oil control should be verified 

to ensure that corrosion is not occurring; and (3) the GALL Report recommends further 

evaluation of programs to manage corrosion by verifying their effectiveness with a 

one-time inspection of selected components at susceptible locations. 

 SER Sections 3.0.3.2.16 and 3.0.3.1.6 document the staff's review of the applicant's 

Lubricating Oil Analysis Program and One-Time Inspection Program, respectively. In its 

review of the steel components associated with the LRA item listed above, the staff finds 

the applicant’s proposal to manage aging effects using the Lubricating Oil Analysis and 

One-Time Inspection Programs acceptable because: (1) the Lubricating Oil Analysis 

Program provides for periodic sampling of lubricating oil to maintain contaminants at 

acceptable limits to preclude loss of material due to general, pitting, or crevice corrosion, 

MIC, and fouling; and (2) the applicant will perform one-time inspections of steel heat 

exchanger components exposed to lubricating oil for loss of material due to general, 

pitting, crevice, MIC, and fouling to verify the effectiveness of the Lubricating Oil Analysis 

Program. This follows the GALL Report recommendation that the “One Time Inspection” 

is an acceptable AMP to verify the effectiveness of the applicant’s Lubricating Oil 

Analysis Program. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.9.2 criteria. For those items that apply to LRA 

Section 3.3.2.2.9, item 2, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

Based on the programs identified above, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.9 criteria. For those items that apply to LRA Section 3.3.2.2.9, the staff 

determines that the LRA is consistent with the GALL Report. The staff also finds that the 

applicant has demonstrated that the effects of aging will be adequately managed so that the 
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intended function(s) will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.2.10 Loss of Material Due to Pitting and Crevice Corrosion 

The staff reviewed LRA Section 3.3.2.2.10 against the following criteria in SRP-LR 

Section 3.3.2.2.10: 

 LRA Section 3.3.2.2.10.1 refers to Table 3.3.1, item 3.3.1.22 and addresses steel piping 

with either elastomeric liners or stainless steel cladding exposed to treated water and 

treated borated water if the cladding or lining is degraded and affected by loss of 

material due to pitting and crevice corrosion. The applicant stated that this item is not 

applicable because it has no in-scope components constructed of steel with elastomeric 

lining or steel with stainless steel cladding exposed to treated or treated borated water in 

the spent fuel pool cooling system. The staff reviewed LRA Sections 2.3.3 and 3.3 and 

confirmed that the applicant’s LRA does not have any AMR results for the spent fuel 

pool cooling system that include steel piping with either elastomeric liners or stainless 

steel cladding exposed to treated water and treated borated water if the cladding or 

lining is degraded. The staff reviewed the applicant’s UFSAR, and confirmed that no 

in-scope steel piping with either elastomeric liners or stainless steel cladding exposed to 

treated water and treated borated water are present in the spent fuel pool cooling 

system and, therefore, it finds the applicant’s determination acceptable. 

 LRA Section 3.3.2.2.10.2 refers to Table 3.3.1, items 3.3.1.23 and 3.3.1.24 and 

addresses the loss of material of the stainless steel, aluminum, and stainless steel clad 

heat exchanger components exposed to treated water in the auxiliary systems. The 

applicant indicated that this item is only applicable to boiling water reactors and noted 

this in LRA Table 3.3.1, for items 3.3.1.23 and 3.3.1.24. 

 For item 3.3.1.23, the staff verified that this item does not apply because the units are a 

PWR design. Based on this determination, the staff finds that the applicant has provided 

an acceptable basis for concluding the AMR, item 3.3.1.23 is not applicable. 

 The staff reviewed LRA Section 3.3.2.2.10.2 against the criteria in SRP-LR 

Section 3.3.2.2.10.2, which states that loss of material due to pitting and crevice 

corrosion could occur for stainless steel and aluminum piping, piping components, and 

piping elements exposed to treated water. In addition, the SRP-LR states that 

monitoring and controlling water chemistry manages this aging effect, but high 

concentrations of impurities at crevices and stagnant flow locations could cause pitting 

or crevice corrosion. The SRP-LR states that the effectiveness of the chemistry control 

program should be verified and notes that the GALL Report recommends a one-time 

inspection of select components as susceptible locations to ensure that corrosion is not 

occurring. The staff also noted that, contrary to the applicant’s statement, SRP-LR 

Table 3.3-1, item 24, applies to both PWRs and BWRs. 

 The staff reviewed the tables in LRA Section 3.3 for the auxiliary systems and found 

multiple stainless steel components in this commodity group for multiple systems that 

were exposed to treated (demineralized) water with an aging effect given as loss of 

material. In every case, the applicant cited Table 3.4.1, item 16, which is the subject of a 

further evaluation in SRP-LR Section 3.4.2.2.7, item 1. Also in every case, the applicant 

indicated that the Water Chemistry Program, augmented by the One-Time Inspection 

Program, was managing this aging effect. SER Sections 3.0.3.2.1 and 3.0.3.1.6 

document the staff’s evaluation of the applicant’s Water Chemistry and One-Time 

Inspection Programs, respectively. In its review of components associated with 

item 3.3.1.24, which the applicant evaluated using Table 3.4.1, item 3.4.1.16, the staff 

finds the applicant’s proposal to manage aging using the Water Chemistry Program 
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augmented by the One-Time Inspection Program acceptable because the applicant’s 

Water Chemistry Program limits the concentrations of chemical species known to cause 

corrosion and adds chemical species known to inhibit degradation. In addition, the staff 

notes that the One-Time Inspection Program verifies the effectiveness of the Water 

Chemistry Program and evaluates aging effects, including loss of material. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.10, item 2 criteria. For those items that apply to LRA 

Section 3.3.2.2.10.2, the staff determines that the LRA is consistent with the GALL 

Report. The applicant has demonstrated that it will adequately manage the effects of 

aging so that the intended function(s) will be maintained consistent with the CLB during 

the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 LRA Section 3.3.2.2.10.3 refers to LRA Table 3.3.1, item 25 and addresses copper alloy 

HVAC piping, piping components, and piping elements exposed to condensation, which 

are being managed for loss of material due to pitting and crevice corrosion by the 

External Surfaces Monitoring and Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components Programs. The applicant addressed the further 

evaluation criteria of the SRP-LR by stating that it will use the External Surfaces 

Monitoring Program to perform inspections on the external surfaces of the components 

exposed to plant indoor air, and it will use the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program to perform inspections on the 

internal surfaces of the components exposed to the ventilation atmosphere. 

 The staff reviewed LRA Section 3.3.2.2.10.3 against the criteria in SRP-LR 

Section 3.3.2.2.10, item 3, which states that loss of material due to pitting and crevice 

corrosion could occur for copper alloy HVAC piping, piping components, and piping 

elements exposed to condensation. The SRP-LR also states that the GALL Report 

recommends further evaluation of a plant-specific AMP. 

 SER Sections 3.0.3.2.14 and 3.3.3.2.15 document the staff’s evaluation of the 

applicant’s External Surfaces Monitoring and Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Programs, respectively. The staff finds 

the applicant’s use of the External Surfaces Monitoring and Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Programs acceptable 

because both these programs perform visual inspections that are capable of detecting 

loss of material for the components being managed. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.10, item 3 criteria. For those items that apply to LRA 

Section 3.3.2.2.10.3, the staff determines that the LRA is consistent with the GALL 

Report. The applicant has demonstrated that it will adequately manage the effects of 

aging so that the intended function(s) will be maintained consistent with the CLB during 

the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 LRA Section 3.3.2.2.10.4 refers to LRA Table 3.3.1, item 26 and addresses copper alloy 

piping and components and elements exposed to lubricating oil, which the Lubricating 

Oil Analysis Program and the One-Time Inspection Program are managing for loss of 

material due to pitting and crevice corrosion. The applicant addressed the further 

evaluation criteria of the SRP-LR by stating that it will include a one-time inspection of 

selected components at susceptible locations where contaminants, such as water, could 

accumulate. 

 The staff reviewed LRA Section 3.3.2.2.10.4 against the criteria in SRP-LR 

Section 3.3.2.2.10, item 4, which states that loss of material due to pitting and crevice 

corrosion could occur for copper alloy piping, piping components, and piping elements 
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exposed to lubricating oil. The SRP-LR Section 3.3.2.2.10 item 4, further states that: 

1) the existing AMP relies on the periodic sampling and analysis of lubricating oil to 

maintain contaminants within acceptable limits, thereby preserving an environment that 

is not conducive to corrosion; (2) a one-time inspection of selected components at 

susceptible locations is an acceptable method to ensure that corrosion is not occurring; 

and (3) the GALL Report recommends further evaluation of programs to manage 

corrosion by verifying their effectiveness with a one-time inspection of selected 

components at susceptible locations. 

 SER Sections 3.0.3.2.16 and 3.0.3.1.6 document the staff's review of the applicant’s 

Lubricating Oil Analysis and One-Time Inspection Programs, respectively. In its review 

of the components associated with the LRA item listed above, the staff finds the 

applicant’s proposal to manage aging effects using the Lubricating Oil Analysis and 

One-Time Inspection Programs acceptable because: (1) the Lubricating Oil Analysis 

Program provides for periodic sampling of lubricating oil to maintain contaminants at 

acceptable limits to preclude loss of material; (2) the applicant will perform one-time 

inspections of select copper alloy piping, piping components, and piping elements 

exposed to lubricating oil for loss of material due to pitting and crevice corrosion to verify 

the effectiveness of the Lubricating Oil Analysis Program following The GALL Report 

recommendation that the “One Time Inspection” is an acceptable AMP to verify the 

effectiveness of the applicant’s Lubricating Oil Analysis Program. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.10, item 4 criteria. For those items that apply to LRA 

Section 3.3.2.2.10.4, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 LRA Section 3.3.2.2.10.5 refers to LRA Table 3.3.1, item 27 and addresses loss of 

material due to pitting and crevice corrosion in HVAC stainless steel ducting and 

components and aluminum piping and components exposed to condensation. The 

applicant stated that the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program will manage the loss of material due to pitting and crevice 

corrosion for stainless steel and aluminum internal surfaces exposed to ventilation 

atmosphere and wetted gas. 

 The staff reviewed LRA Section 3.3.2.2.10.5 against the criteria in SRP-LR 

Section 3.3.2.2.10, item 5, which states that loss of material due to pitting and crevice 

corrosion could occur in HVAC aluminum piping, piping components, and piping 

elements and stainless steel ducting and components exposed to condensation. It also 

recommends further evaluation of a plant-specific AMP to ensure this aging effect is 

adequately managed. 

 The applicant stated that the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program will conduct visual inspections during periodic 

maintenance, predictive maintenance, surveillance testing, and corrective maintenance 

to detect aging effects that could result in a loss of component intended function. The 

staff noted that the GALL Report AMP manages aging effect of loss of material for steel 

components. However, the applicant has taken an exception to increase the scope of 

the materials to include aluminum and stainless steel alloy. The staff reviewed the 

exception as part of its review of the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program, and its evaluation is documented in SER 

Section 3.0.3.2.15. 
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 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.10 item 5 criteria. For those items that apply to LRA 

Section 3.3.2.2.10.5, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended functions will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 LRA Section 3.3.2.2.10.6 refers to LRA Table 3.3.1, item 28 and addresses copper alloy 

fire protection system piping, piping components, and piping elements exposed to 

condensation, which are being managed for loss of material due to pitting and crevice 

corrosion by the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program. The applicant addressed the further evaluation criteria 

of the SRP-LR by stating that it will use the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program to perform inspections on the 

internal surfaces of the components exposed to wetted gas. 

 The staff reviewed LRA Section 3.3.2.2.10.6 against the criteria in SRP-LR 

Section 3.3.2.2.10, item 6, which states that loss of material, due to pitting and crevice 

corrosion, could occur for copper alloy fire protection system piping, piping components, 

and piping elements exposed to internal condensation. The SRP-LR also states that the 

GALL Report recommends further evaluation of a plant specific AMP to ensure that the 

aging effects are adequately managed. 

 SER Section 3.0.3.2.15 documents the staff’s evaluation of the applicant’s Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The staff 

finds the applicant’s use of the Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program acceptable because it performs visual inspections 

that can detect loss of material for copper alloy components. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.10, item 6 criteria. For those items that apply to LRA 

Section 3.3.2.2.10.6, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation as required by 10 CFR 54.21(a)(3). 

 LRA Section 3.3.2.2.10.7 refers to Table 3.3.1, item 29 and addresses stainless steel 

piping, piping components, and piping elements exposed to soil which are being 

managed for loss of material due to pitting and crevice corrosion by the Buried Piping 

and Tanks Inspection Program. The applicant addressed the further evaluation criteria 

of the SRP-LR by stating that the Buried Piping and Tanks Inspection Program will 

manage the loss of material due to pitting and crevice corrosion in external surfaces of 

stainless steel piping, piping components, and piping elements in a soil environment. 

 The staff reviewed LRA Section 3.3.2.2.10.7 against the criteria described in SRP-LR 

Section 3.3.2.2.10, item 7, which states that loss of material due to pitting and crevice 

corrosion could occur for stainless steel piping, piping components, and piping elements 

exposed to soil. The SRP-LR also recommends further evaluation of a plant-specific 

AMP to ensure that these aging effects are adequately managed. BTP RLSB-1 

describes acceptance criteria are (Appendix A.1 of the SRP-LR). 

 SER Section 3.0.3.2.12 documents the staff’s evaluation of the applicant’s Buried Piping 

and Tanks Inspection Program. The staff finds the applicant’s proposal to manage aging 

using the Buried Piping and Tanks Inspection Program acceptable because it requires 

periodic visual inspections of the external surface of buried steel piping prior to and 

within the period of extended operation. 
Aging Management Review Results 

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 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.10, item 7 criteria. For those items that apply to LRA 

Section 3.3.2.2.10.7, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation as required by 10 CFR 54.21(a)(3). 

 LRA Section 3.3.2.2.10.8 references Table 3.3.1, item 30 and addresses loss of material 

due to pitting and crevice corrosion in stainless steel piping, piping components, and 

piping elements of the BWR Standby Liquid Control System that are exposed to sodium 

pentaborate solution, stating that this aging effect is not applicable; it is applicable to 

BWRs only. The staff finds that SRP-LR Section 3.3.2.2.10 item 8 is not applicable 

because the PVNGS units are PWRs, and the staff guidance in this SRP-LR section is 

only applicable to BWRs. 

Based on the programs identified above, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.10 criteria. For those items that apply to LRA Section 3.3.2.2.10, the 

staff determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

3.3.2.2.11 Loss of Material Due to Pitting, Crevice, and Galvanic Corrosion 

LRA Section 3.3.2.2.11 refers to Table 3.3.1, item 3.3.1.31 and addresses the loss of material 

due to pitting, crevice, and galvanic corrosion. The applicant indicated that this is only 

applicable to BWRs. The staff reviewed LRA Section 3.3.2.2.11 against the criteria in SRP-LR 

Section 3.3.2.2.11 and agrees that this item is not applicable to a PWR unit, and therefore, 

finds the applicant’s determination acceptable. 

3.3.2.2.12 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion 

The staff reviewed LRA Section 3.3.2.2.12 against the following criteria in SRP-LR 

Section 3.3.2.2.12: 

 LRA Section 3.3.2.2.12.1 refers to Table 3.3.1, item 3.3.1.32 and addresses the loss of 

material due to pitting and crevice corrosion and MIC for stainless steel, aluminum, and 

copper components exposed to fuel oil. The applicant stated that the Fuel Oil Chemistry 

Program (LRA B2.1.14), reviewed in SER Section 3.0.3.2.9, and the One-Time 

Inspection Program (LRA B2.1.16), reviewed in SER Section 3.0.3.1.6, manage this 

aging effect. The applicant also stated that the one-time inspection will include selected 

components at susceptible locations where contaminants could accumulate (e.g. 

stagnant flow locations and tank bottoms). 

 The staff reviewed LRA Section 3.3.2.2.12.1 against the criteria in SRP-LR 

Section 3.3.2.2.12.1, which states that loss of material due to pitting and crevice 

corrosion and MIC could occur in stainless steel, aluminum, and copper alloy piping, 

piping components, and piping elements exposed to fuel oil. The GALL Report 

recommends that these aging effects be managed by the Fuel Oil Chemistry Program 

(GALL Report AMP XI.M30) and that the effectiveness of this program be verified 

through the use of the One-Time Inspection Program (GALL Report AMP XI.M32). The 

GALL Report also recommends further evaluation because corrosion may occur at 

locations were contaminants accumulate. 

 The staff notes that in LRA Section 3.3.2.2.12.1, the applicant has identified appropriate 

AMPs and has identified the critical conditions requiring further review, i.e., the potential 

for fuel oil chemistry control to be ineffective in locations where contaminants 
Aging Management Review Results 

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accumulate. The staff finds that LRA Section 3.3.2.2.12.1 is consistent with SRP-LR 

Section 3.3.2.2.12, item 1. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.12.1 criteria. For those items that apply to LRA 

Section 3.3.2.2.12.1, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3) 

 LRA Section 3.3.2.2.12 refers to LRA Table 3.3.1, item 3.3.1.33 and addresses stainless 

steel piping, piping components, and elements exposed to lubricating oil, which are 

being managed for loss of material due to pitting and crevice corrosion and MIC by the 

Lubricating Oil Analysis Program and the One-Time Inspection Program. The applicant 

addressed the further evaluation criteria of the SRP-LR by stating that it will include a 

one-time inspection of selected components at susceptible locations where 

contaminants such as water could accumulate. 

 The staff reviewed LRA Section 3.3.2.2.12 item 2 against the criteria in SRP-LR 

Section 3.3.2.2.12, item 2, which states that loss of material due to pitting, crevice, and 

MIC could occur in stainless steel piping, piping components, and piping elements 

exposed to lubricating oil. SRP-LR Section 3.3.2.2.12.2 further states that: (1) the 

existing program relies on the periodic sampling and analysis of lubricating oil to 

maintain contaminants within acceptable limits, thereby preserving an environment that 

is not conducive to corrosion; (2) the effectiveness of the lubricating oil program is 

verified through one-time inspection of selected components at susceptible locations to 

ensure that corrosion is not occurring and that the component’s intended function will be 

maintained during the period of extended operation; and (3) the GALL Report 

recommends further evaluation of programs to manage corrosion by verifying their 

effectiveness with a one-time inspection of selected components at susceptible 

locations. 

 The staff reviewed the applicant’s Lubricating Oil Analysis Program and One-Time 

Inspection Program in SER Sections 3.0.3.2.16 and 3.0.3.1.6, respectively. In its review 

of the components associated with the LRA items listed above, the staff finds the 

applicant’s proposal to manage aging using the Lubricating Oil Analysis and One-Time 

Inspection Programs acceptable because: (1) the Lubricating Oil Analysis Program 

provides for periodic sampling of lubricating oil to maintain contaminants at acceptable 

limits to preclude loss of material; (2) the applicant will perform one-time inspections of 

select stainless steel piping, piping components, and piping elements exposed to 

lubricating oil for loss of material due to pitting and crevice corrosion and MIC. This 

one-time inspection verifies the effectiveness of the Lubricating Oil Analysis Program in 

applicable auxiliary systems, following The GALL Report recommendation that the “One 

Time Inspection” is an acceptable AMP to verify the effectiveness of the applicant’s 

Lubricating Oil Analysis Program. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.12.2 criteria. For those items that apply to LRA 

Section 3.3.2.2.12.2, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

Based on the programs identified above, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.12 criteria. For those items that apply to LRA Section 3.3.2.2.12, the 
Aging Management Review Results 

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staff determines that the LRA is consistent with the GALL Report. The staff also finds that the 

applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.2.13 Loss of Material Due to Wear 

LRA Section 3.3.2.2.13 refers to Table 3.3.1, item 34 and addresses elastomeric components 

exposed to air-indoor uncontrolled (internal or external) affected by loss of material due to wear. 

The applicant stated that this item is not applicable because it has no in scope elastomeric 

components exposed to relative motion with other components to produce an aging effect of 

loss of material due to wear. The staff reviewed LRA Sections 2.3.3 and 3.3 and confirmed that 

the applicant’s LRA does not have any AMR results for the auxiliary systems that include 

elastomeric components exposed to air-indoor uncontrolled (internal or external) that are 

subject to relative motion. The staff notes that the SRP-LR references GALL Report tables that 

limit the scope of this item to HVAC systems. The staff reviewed the applicant’s UFSAR and 

confirmed that no in-scope elastomeric components exposed to air-indoor uncontrolled (internal 

or external) are present in the auxiliary systems that are exposed to relative motion and, 

therefore, it finds the applicant’s determination acceptable. 

3.3.2.2.14 Loss of Material Due to Cladding Breach 

LRA Section 3.3.2.2.14 refers to Table 3.3.1, item 3.3.1.35 and addresses the loss of material 

due to cladding breach for steel pumps with stainless steel cladding exposed to treated borated 

water in the auxiliary systems. The applicant stated that PVNGS has no in-scope stainless steel 

clad pump casings exposed to treated borated water in the CVCS. The staff reviewed LRA 

Sections 2.3.3 and 3.3 and confirmed that the applicant’s LRA does not have any AMR results 

for the auxiliary systems that include steel pumps with stainless steel cladding exposed to 

treated borated water. The staff reviewed the applicant’s UFSAR to verify the design of the 

CVCS pumps. The staff confirmed, using the UFSAR, that these charging pump casings were 

fabricated from solid pieces of stainless steel; therefore, the staff finds the applicant’s 

determination acceptable. 

3.3.2.2.15 Quality Assurance for Aging Management of Nonsafety-Related Components 

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA program. 

3.3.2.3 Aging Management Review Results Not Consistent with or Not Addressed in 

the Generic Aging Lessons Learned Report 

In LRA Tables 3.3.2-1 through 3.3.2-30, the staff reviewed additional details of the AMR results 

for material, environment, AERM, and AMP combinations not consistent with or not addressed 

in the GALL Report. 

In LRA Tables 3.3.2-1 through 3.3.2-30, via Notes F–J, the applicant indicated which 

combinations of component type, material, environment, and AERM do not correspond to an 

item in the GALL Report. The applicant provided further information about how it will manage 

the aging effects. Specifically, Note F indicates that the material for the AMR item component is 

not evaluated in the GALL Report. Note G indicates that the environment for the AMR item 

component and material is not evaluated in the GALL Report. Note H indicates that the aging 

effect for the AMR item component, material, and environment combination is not evaluated in 

the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the 

item component, material, and environment combination is not applicable. Note J indicates that 

neither the component nor the material and environment combination for the item is evaluated in 

the GALL Report. 
Aging Management Review Results 

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For component type, material, and environment combinations not evaluated in the GALL 

Report, the staff reviewed the applicant’s evaluation to determine if the applicant has 

demonstrated that it will adequately manage the effects of aging so that the intended function(s) 

will be maintained consistent with the CLB for the period of extended operation. The following 

sections document the staff’s evaluation. 

3.3.2.3.1 Fuel Handling and Storage System—Summary of Aging Management Review—

License Renewal Application Table 3.3.2-1 

The staff reviewed LRA Table 3.3.2-1, which summarizes the results of AMR evaluations for the 

fuel-handling and storage system component groups. 

The staff’s review did not find any items indicating plant-specific Notes F–J, where the 

combination of component type, material, environment, and AERM does not correspond to an 

item in the GALL Report. 

Ser Section 3.0.2.1 documents the staff’s evaluation of the items with Notes A–E. 

3.3.2.3.2 Spent Fuel Pool Cooling and Cleanup System—Summary of Aging Management 

Review—License Renewal Application Table 3.3.2-2 

The staff reviewed LRA Table 3.3.2-2, which summarizes the results of AMR evaluations for the 

spent fuel pool cooling and cleanup system component groups. 

In LRA Tables 3.3.2-2, 3.3.2-7, and 3.3.2-20 the applicant stated that the Bolting Integrity 

Program manages stainless steel closure bolting exposed to treated borated water and raw 

water, and carbon steel closure bolting exposed to diesel fuel oil, for loss of preload. The AMR 

items cite generic Note G, indicating that the environment is not in the GALL Report for the 

component, material, and environment. 

The staff noted that for each of the AMR results, the closure bolting is in a liquid environment, 

and the bolted fittings have the same environment both internally and externally. The staff also 

noted that in such an environment visual examination during system walkdowns would not 

readily detect indications of leakage around the bolted joints. By letter dated April 28, 2010, the 

staff issued RAI 3.3.2-2 asking that the applicant explain what activities of the Bolting Integrity 

Program it will use to detect loss of preload for closure bolting in a liquid environment. The staff 

also asked the applicant to clarify if there are any indirect indicators that may identify reduction 

of preload for closure bolting in the liquid environments. 

In its response, dated May 21, 2010, the applicant stated that for the submerged bolting in the 

spent fuel pool cooling and cleanup system and the diesel fuel oil storage and transfer system, 

the AMSE Section XI, Subsections IWB, IWC, and IWD Program manages the inspection of 

safety related bolting and supplements the Bolting Integrity Program. The applicant also stated 

that for these bolting components, inspections detect loss of material due to corrosion and 

evidence of leakage. The applicant further stated that the extent and schedule of ASME 

Section XI, Subsections IWB, IWC, and IWD Program inspections, combined with periodic 

system walkdowns, assure detection of leakage before the leakage becomes excessive. In 

addition, any unusual indications of system performance, such as reduced ability to hold 

pressure or pump and piping vibration or noise, observed during periodic system walkdowns 

and pressure testing are identified and entered into the Corrective Action Program. The 

applicant stated that inability to successfully complete an ASME Code Section XI pressure test 

or observation of unusual indications of system performance would be used as indicators to 

reveal a potential loss of preload or other aging effects for closure bolting. The applicant’s 

response also indicated that additional direct inspections are not performed for the stainless 

steel closure bolting exposed to raw water in the essential spray system and that indirect 

indicators such as unusual changes in system performance would be used indirectly to detect 

reduction of preload for these components. 
Aging Management Review Results 

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The staff notes that the applicant has adequately addressed loss of preload in bolting 

components exposed to a liquid environment by crediting additional ASME Code Section XI 

inspections, where they are applicable, and by using indirect performance indicators to aid in 

detecting loss of bolting preload, if ASME inspections are not required. The staff finds these 

inspection methods, together with control of bolting preload during design and maintenance 

activities, acceptable to manage loss of preload in these bolting components exposed to a liquid 

environment. 

In LRA Tables 3.3.2-2 and 3.3.2-8, the applicant stated that the Water Chemistry and One-Time 

Inspection Programs manage the stainless steel fuel pool cooling and reactor hot leg sample 

cooler heat exchangers exposed to treated borated water for reduction of heat transfer. The 

AMR item cites generic Note H, indicating that for the items, the aging effect is not in the GALL 

Report for this component, material, and environment combination. The items associated with 

the stainless steel fuel pool cooling and reactor hot leg sample cooler heat exchangers exposed 

to treated borated water, Tables 3.2.2-2 and 3.3.2-8 cite plant specific notes 2 and 1, 

respectively, which state, “Reduction in heat transfer due to fouling is a potential aging effect for 

stainless steel heat exchanger components in treated borated water. This non-GALL Report 

item is based upon the component, material, aging effects, and aging management program 

combination of GALL Report item VII.E1-4.” 

The staff reviewed all AMR result items in the GALL Report where the component and material 

is stainless steel heat exchangers exposed to treated borated water and noted that these items 

relate to SPR Section 3.3.2.2.2. This is inconsequential since the associated GALL Report 

items recommend that the Water Chemistry Program, verified by the One-Time Inspection 

Program, manages aging, and the applicant selected the same programs to manage aging. 

SER Sections 3.0.3.2.1 and 3.0.3.1.6 document the staff’s evaluation of the applicant’s Water 

Chemistry and a One-Time Inspection Programs, respectively. 

For those items that apply to LRA Section 3.3.2.2.2, the staff determines that the LRA contains 

appropriate AMR line items to ensure consistency with the GALL Report and that the applicant 

has demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

3.3.2.3.3 Essential Cooling Water System—Summary of Aging Management Review—

License Renewal Application Table 3.3.2-3 

The staff reviewed LRA Table 3.3.2-3, which summarizes the results of AMR evaluations for the 

essential cooling water system component groups. 

In LRA Tables 3.3.2-3, 3.3.2-4, 3.3.2-5, 3.3.2-7, 3.3.2-21, 3.3.2-22, 3.3.2-23, 3.3.2-27, 3.3.2-28, 

and 3.3.2-30, the applicant stated that the Boiling Integrity Program manages stainless steel 

closure bolting exposed to plant indoor air for loss of preload. The AMR items cite generic 

Note G, indicating that the environment is not in the GALL Report for this component and 

material. Some of the AMR items also cite plant-specific note 1, indicating that loss of preload 

is considered to be applicable for all closure bolting. 

SER Section 3.0.3.2.3 documents the staff’s evaluation of the applicant’s Bolting Integrity 

Program. The staff noted that the mechanisms identified in the GALL Report as causing loss of 

preload in carbon steel bolts are thermal effects, gasket creep, and self-loosening, which are not 

all dependent on the material or the environment. The staff also noted that activities in the 

Bolting Integrity Program that control and manage loss of preload are effective for various 

bolting materials and environments. The staff further noted that the GALL Report, item VII.I-5 

(AP-26) recommends using the Bolting Integrity Program to manage the aging effect of loss of 

preload in carbon steel bolts exposed to air-indoor uncontrolled. 
Aging Management Review Results 

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On the basis that the GALL Report recommends the Bolting Integrity Program for managing loss 

of preload in carbon steel bolting exposed to air-indoor uncontrolled, and the Bolting Integrity 

Program’s activities for managing loss of preload are applicable for other bolting materials and 

similar environments, the staff finds the applicant’s use of the Bolting Integrity Program to 

manage loss of preload in stainless steel bolting exposed to plant indoor air to be acceptable. 

In LRA Tables 3.3.2-3, 3.3.2-10, 3.3.2-11, and 3.3.2-22, the applicant stated that aluminum 

chambers, carbon steel heat exchanger (seal injection), piping, strainer, and tank, cast iron 

pump and flow indicator, and stainless steel valve components exposed to closed-cycle cooling 

water, borated water leakage, and potable water are managed for loss of material by the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The 

AMR items cite generic Note G, indicating that for the item(s) the environment is not in the 

GALL Report for this component and material 

The staff reviewed the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program, and SER Section 3.0.3.2.15 documents its evaluation. The staff 

finds the applicant’s proposal to manage aging using the Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program acceptable because the applicant will: (1) conduct 

visual inspections during periodic maintenance, predictive maintenance, surveillance testing and 

corrective maintenance to detect loss of material for the steel, copper alloy, cast iron, aluminum 

and stainless steel components exposed to borated water leakage, potable water, or 

closed-cycle cooling water: (2) remedy deficiencies per the applicant’s Corrective Action 

Program; and (3) within 10 years prior to extended operation will review all systems within the 

scope of the program for aging effects to provide reasonable assurance that their intended 

functions will remain through the next inspection cycle. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.3.4 Essential Chilled Water System—Summary of Aging Management Review—License 

Renewal Application Table 3.3.2-4 

The staff reviewed LRA Table 3.3.2-4, which summarizes the results of AMR evaluations for the 

essential chilled water system component groups. 

In LRA Tables 3.3.2-4, 3.3.2-10, and 3.3.2-21, the applicant stated that calcium silicate and 

mineral wool insulation exposed to borated water leakage have no AERM and no proposed 

AMP. The AMR items cite generic Note J. 

The staff reviewed the associated items in the LRA and noted that the applicant only included 

piping insulation in scope for license renewal for those systems where the insulation has an 

intended function. The staff also noted that both calcium silicate and mineral wool insulation 

materials can experience loss of insulating properties when exposed to moisture, due to effects 

such as compression of the material or change in material properties, but that proper jacketing 

of the insulation can be effective at preventing moisture intrusion. The staff further noted that 

both materials can retain moisture well after exposure, prolonging the contact time of the 

moisture with the piping being insulated. The staff confirmed that the affected piping is jacketed 

with overlapping seams, such that moisture intrusion is not a concern. The staff finds the 

applicant’s determination that calcium silicate and mineral wool insulation in this environment 

have no AERM acceptable because these materials perform well when exposed to air and are 

properly jacketed to prevent moisture intrusion. 
Aging Management Review Results 

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On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combination not addressed in the GALL 

Report. The staff finds that the applicant demonstrated that the effects of aging for these 

components will be adequately manage so that their 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 Tables 3.3.2-4, 3.3.2-5, and 3.3.2-6, the applicant stated that the Closed-Cycle Cooling 

Water System Program manages the nickel-alloy flexible hoses, exposed internally to 

closed-cycle cooling water, for loss of material. The AMR items cite generic Note G. 

The staff reviewed the associated items in the LRA and confirmed that the applicant has 

identified the correct aging effects for this component, material, and environmental combination 

because, similar to GALL Report AMR item VII.C2-10, these components are also subject to 

loss of material when exposed to closed-cycle cooling water. The staff noted that the conditions 

required for cracking, due to a variety of mechanisms (SCC, PWSCC, IASCC and IGSCC), such 

as high fluid temperatures, do not exist for these components when exposed to the closed-cycle 

cooling water in this system. 

SER Section 3.0.3.2.5 documents the staff’s evaluation of the applicant’s Closed-Cycle Cooling 

Water System Program. The staff noted that this program includes maintenance of system 

corrosion inhibitor concentrations to minimize aging effects and periodic testing and inspections 

to evaluate system and component performance. The staff noted that controlling the chemistry 

of the closed-cycle cooling water will create an environment that is not conducive to corrosion. 

Furthermore, the applicant’s program includes periodic inspection processes such as visual, 

eddy current, and ultrasonic examinations. The program also includes periodic testing methods, 

such as functional demonstrations, monitoring, and thermal and hydraulic performance testing, 

to confirm the effectiveness of the chemistry control and ensure that degradation is not 

occurring. The staff finds the applicant’s proposal to manage aging using the Closed-Cycle 

Cooling Water System Program acceptable because the applicant is controlling the chemistry of 

the water to create an environment that is not conducive for degradation, and it will perform 

periodic inspections or testing methods, as described above, to confirm the effectiveness of the 

chemistry control. 

In LRA Table 3.3.2-4, the applicant stated that, for sight gauges made of glass exposed to dry 

gas, there is no aging effect and no proposed AMP. The AMR item cites generic Note G, 

indicating that for the item, the environment is not in the GALL Report for this component and 

material. 

The staff noted that in LRA Table 3.0-1 the applicant described dry gas as dry air and inert or 

non-reactive gases, including compressed instrument air, nitrogen, oxygen, hydrogen, helium, 

halon, or freon. The staff finds the applicant’s proposal acceptable because the GALL Report 

does not identify an aging effect for any glass material exposed to any environment (e.g., 

lubricating oil, air, treated borated water). The dry gas environment is less aggressive than the 

examples in the GALL Report; therefore, no AMP is required. 

SER Section 3.3.2.3.3 documents the staff’s evaluation for the Bolting Integrity Program, 

managing the stainless steel closure bolting, exposed to plant indoor air, for loss of preload, 

citing generic Note G. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 
Aging Management Review Results 

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3.3.2.3.5 Normal Chilled Water System—Summary of Aging Management Review—License 

Renewal Application Table 3.3.2-5 

The staff reviewed LRA Table 3.3.2-5, which summarizes the results of AMR evaluations for the 

normal chilled water system component groups. 

SER Section 3.3.2.3.3 documents the staff’s evaluation for the Bolting Integrity Program 

managing stainless steel closure bolting, exposed to plant indoor air, for loss of preload, citing 

generic Note G. 

SER Section 3.3.2.3.4 documents the staff’s evaluation for nickel-alloy components, exposed to 

closed-cycle cooling water, being managed for loss of material by the Closed-Cycle Cooling 

Water System Program, with generic Note G. 

3.3.2.3.6 Nuclear Cooling Water System—Summary of Aging Management Review—License 

Renewal Application Table 3.3.2-6 

The staff reviewed LRA Table 3.3.2-6, which summarizes the results of AMR evaluations for the 

nuclear cooling water system component groups. 

SER Section 3.3.2.3.4 documents the staff’s evaluation for the Closed-Cycle Cooling Water 

System Program managing nickel-alloy components, exposed to closed-cycle cooling water, for 

loss of material, with generic Note G. 

3.3.2.3.7 Essential Spray Pond System—Summary of Aging Management Review—License 

Renewal Application Table 3.3.2-7 

The staff reviewed LRA Table 3.3.2-7, which summarizes the results of AMR evaluations for the 

ESP system component groups. 

In LRA Tables 3.3.2-7, 3.3.2-30, and 3.3.2-31, the applicant stated that the piping and piping 

components (valve, strainer, flow indicator, tubing) and a corrosion test rack made of PVC 

exposed to plant indoor air (external) and raw or secondary water (internal) do not have an 

AERM and do not require an AMP. In LRA Table 3.3.2-19, the applicant stated that piping 

made of fiberglass reinforced plastic exposed to a buried environment (external) and raw water 

(internal) does not have an AERM and does not require an AMP. In LRA Table 3.3.2-22, the 

applicant stated that piping made of polyethylene exposed to plant indoor air (external) or a 

buried environment (external) and to raw water (internal) does not have an AERM and does not 

require an AMP. In LRA Table 3.3.2-23, the applicant stated that thermoplastic demineralizers 

exposed to plant indoor air (external) and demineralized water (internal) do not have an AERM 

and do not require an AMP. The AMR items cite Note F, indicating that the GALL Report does 

not evaluate the component, material, and environment combinations. 

The staff noted that for the evaluated components in the ESP system (Table 3.3.2-7), fire 

protection system (Table 3.3.2-19), domestic water system (Table 3.3.2-22), demineralized 

water system (Table 3.3.2-23), and oily waste and non radioactive waste system 

(Table 3.3.2-31)—none of these systems are high-temperature and high-pressure systems. 

The staff confirmed that the components are used in applications where sustained exposure to 

ultraviolet light, high radiation, and ozone concentrations is not expected. The staff also notes 

that, based on its review of technical literature (e.g., Roff, 1956), current industry research, and 

operating experience related to PVC, polyethylene, thermo plastics, and fiberglass-reinforced 

plastic piping and piping components, in the absence of specific environmental stressors such 

as ultraviolet light, high radiation, or ozone concentrations, piping components made of these 

materials do not exhibit aging effects of concern during the period of extended operation. For 

the PVC components from Table 3.3.2 30, “Miscellaneous Auxiliary Systems In-Scope ONLY 

based on Criterion 10 CFR 54.4(a)(2),” that are exposed to secondary water, the staff notes that 

these items are located in the secondary chemical control system and, based on plant drawings, 
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located in a cold lab in the auxiliary building. The staff also notes that these items would not be 

exposed to direct ultraviolet lighting, high radiation, or ozone. Therefore, the staff finds the 

applicant’s proposal acceptable because the subject components have no aging effects that 

cause degradation during the period of extended operation. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that their intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

In LRA Tables 3.3.2-7, 3.3.2-9, 3.3.2-22, and 3.3.2-30, the applicant stated that the Bolting 

Integrity Program manages copper alloy and copper alloy with greater than 8-percent aluminum 

closure bolting exposed to plant indoor for loss of preload. The AMR items cite generic Notes F 

and G, indicating that the material is not in the GALL Report for this component. 

SER Section 3.0.3.2.3 documents the staff’s evaluation of the applicant’s Bolting Integrity 

Program. The staff noted that the mechanisms identified in the GALL Report as causing loss of 

preload in carbon steel bolts are thermal effects, gasket creep, and self-loosening and that 

these mechanisms can cause loss of preload in copper alloy bolts. The staff also noted that 

activities in the Bolting Integrity Program that control and manage loss of preload are effective 

for other metal bolting materials. The staff further noted that the GALL Report, item VII.I-5 

(AP-26) recommends using the Bolting Integrity Program to manage loss of preload in carbon 

steel bolts exposed to air-indoor uncontrolled. The staff finds the applicant’s use of the Bolting 

Integrity Program to manage loss of preload in copper alloy and copper alloy with greater than 

8-percent aluminum bolting acceptable because it is consistent with the GALL Report 

recommendations for managing loss of preload in carbon steel bolting. In addition, the Bolting 

Integrity Program’s activities for managing loss of preload are applicable for other metal bolting 

materials. 

In LRA Tables 3.3.2-7, 3.3.2-10, 3.3.2-13, 3.3.2-19, 3.3.2-23, 3.3.2-24, 3.3.2-27, 3.4.2-2, 

and 3.5.2-10, the applicant stated that for stainless steel and CASS components exposed to 

atmosphere or weather conditions, there are no AERM and that no AMP will be implemented. 

The applicant referenced generic Note G for these items, indicating that the environment is not 

listed in the GALL Report for this material and component combination. 

The staff reviewed all AMR results in the GALL Report where the material is stainless steel and 

the aging effect is loss of material and confirmed that there are no entries for this environment in 

the GALL Report for the component and material. However, the staff noted that the GALL 

Report does include AMR results for stainless steel components exposed to indoor uncontrolled 

air and that the GALL Report recommends no AMP be used because there is no aging effect for 

this material and environment combination. The staff also noted that the climate at this location 

is dry and arid with high average temperatures (68–108 degrees F) throughout the year and low 

average rainfall (8–10 inches per year), making the aging effects of the atmosphere or weather 

at this location similar to those of indoor uncontrolled air. The staff finds the applicant’s 

determination that no AMP is required acceptable because stainless steel components exposed 

to the atmosphere or weather would not be expected to experience an aging effect at this 

location. 

In LRA Table 3.3.2-7, the applicant stated that for nickel-alloy spray nozzles exposed to 

atmosphere or weather, there is no aging effect and no proposed AMP. The AMR item cites 

generic Note G. The applicant also stated, in its plant-specific notes 4 and 5, that these 

nickel-alloy components are located outside with an uncontrolled external air environment and 

are not exposed to aggressive chemical species. Furthermore, the plant outdoor environment is 
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not subject to industry air pollution or saline environment and alternate wetting and drying has 

shown a tendency to “wash” the surface material rather than concentrate contaminants. 

The staff reviewed the associated items in the LRA and confirmed that no aging effect is 

applicable for this component, material, and environment because austenitic materials such as 

nickel alloys are not subject to loss of material or cracking when exposed to this environment, 

and these materials are used as corrosion-resistant replacement materials where other 

materials have degraded. The staff noted that corrosion-resistant materials, such as austenitic 

and martensitic stainless steels and high strength nickel base alloys, offer good protection 

against loss of material. The staff also noted that the conditions required for cracking, due to a 

variety of mechanisms (SCC, PWSCC, IASCC and IGSCC), to occur such as being exposed to 

an aqueous solution (reactor coolant or other corrosive solutions) and high temperatures, do not 

exist on the surfaces of these components when exposed to atmosphere or weather. The staff 

noted the applicant’s definition of atmosphere or weather in LRA Table 3.0-1, “Mechanical 

Environments,” states, in part, that there is no exposure to salt spray or other aggressive 

contaminants. Based on its review, the staff finds the applicant’s determination acceptable 

because nickel alloys are highly corrosion-resistant, and these components are not exposed to 

an environment that contains salt spray or other contaminants that create an environment 

conducive to loss of material or corrosion. In addition, these components are not subject to the 

conditions required to induce cracking. 

SER Section 3.3.2.3.2 documents the staff’s evaluation of the Bolting Integrity Program, citing 

generic Note G, managing stainless steel closure bolting exposed to raw water for loss of 

preload. 

SER Section 3.3.2.3.3 documents the staff’s evaluation of the Bolting Integrity Program, citing 

generic Note G, managing stainless steel closure bolting exposed to plant indoor air for loss of 

preload. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.3.8 Nuclear Sampling System—Summary of Aging Management Review—License 

Renewal Application Table 3.3.2-8 

The staff reviewed LRA Table 3.3.2-8, which summarizes the results of AMR evaluations for the 

nuclear sampling system component groups. 

Section 3.3.2.3.2 documents the staff’s evaluation for stainless steel heat exchanger 

components exposed to treated borated water managed by the Water Chemistry and One-Time 

Inspection Programs for reduction of heat transfer, with generic Note H. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.3.9 Compressed Air System—Summary of Aging Management Review—License 

Renewal Application Table 3.3.2-9 

The staff reviewed LRA Table 3.3.2-9, which summarizes the results of AMR evaluations for the 

compressed air system component groups. 
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SER Section 3.3.2.3.7 documents the staff’s evaluation for copper alloy and copper alloy with 

greater than 8 percent aluminum closure bolting exposed to plant indoor air being managed for 

loss of preload by the Bolting Integrity Program, citing generic Notes F and G. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.3.10 Chemical and Volume Control System—Summary of Aging Management Review—

License Renewal Application Table 3.3.2-10 

The staff reviewed LRA Table 3.3.2-10, which summarizes the results of AMR evaluations for 

the CVCS component groups. 

In LRA Tables 3.3.2-4, 3.3.2-10, and 3.3.2-21, the applicant stated that calcium silicate and 

mineral wool insulation exposed to borated water leakage have no AERM and no proposed 

AMP. The AMR items cite generic Note J. Section 3.3.2.3.4 documents the staff’s review. 

In LRA Table 3.3.2-10, the applicant stated that for flow indicators and sight gauges made of 

glass exposed to borated water leakage (external) there is no aging effect and no proposed 

AMP. The AMR items cite generic Note G, indicating that for the items, the environment is not 

in the GALL Report for this component and material. 

The staff reviewed all AMR result items in the GALL Report where the material is glass, and 

confirmed that for this environment, there are no entries in the GALL Report for this component 

and material. The staff notes that for glass components, the GALL Report does list a treated 

water environment in contrast to borated water leakage, but this is non consequential to the 

evaluation because the GALL Report items state that there is no aging effect and no 

recommended AMP. 

The staff finds the applicant’s proposal acceptable because glass, in an environment of borated 

water leakage, is expected to have the same aging effects as glass in an environment of treated 

borated water. The GALL Report states that there are no AERMs for glass piping components 

in a treated borated water environment. 

In LRA Table 3.3.2-10, the applicant stated that for nickel-alloy piping exposed to borated water 

leakage there is no aging effect and no proposed AMP. The AMR items cite generic Note G. 

The staff reviewed the associated items in the LRA and confirmed that no aging effect is 

applicable for this component, material, and environment because austenitic materials such as 

nickel alloys are not subject to loss of material or cracking when exposed to this environment, 

and these materials are used as corrosion-resistant replacement materials where other 

materials have degraded. The staff noted that according to EPRI NP-5769, "Degradation and 

Failure of Bolting in Nuclear Power Plants, Volumes 1 and 2,” April 1988, corrosion-resistant 

materials, such as austenitic and martensitic stainless steels and high strength nickel base 

alloys, offer good protection against loss of material due to boric acid corrosion. The staff also 

noted that the conditions required for cracking due to a variety of mechanisms (SCC, PWSCC, 

IASCC and IGSCC) to occur, such as being exposed to an aqueous solution (reactor coolant or 

other corrosive solutions) and high temperatures, do not exist on the surfaces of these 

components when exposed to borated water leakage. Therefore, the staff finds no AMP is 

necessary for nickel alloys in a borated water leakage environment. 

SER Section 3.3.2.3.3 documents the staff’s evaluation for aluminum, carbon steel, copper 

alloy, cast iron, and stainless steel components exposed to closed-cycle cooling water, borated 

water leakage, and potable water, with an aging effect of loss of material managed by the 
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Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program, that 

cite generic Note G. 

SER Section 3.3.2.3.7 documents the staff’s evaluation for stainless steel and CASS 

components exposed to atmosphere or weather conditions, where there are no AERM and no 

AMP, citing generic Note G. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.3.11 Control Building Heating, Ventilation, and Air Conditioning System—Summary of 

Aging Management Review—License Renewal Application Table 3.3.2-11 

The staff reviewed LRA Table 3.3.2-11, which summarizes the results of AMR evaluations for 

the control building HVAC system component groups. 

SER Section 3.3.2.3.3 documents the staff’s evaluation for aluminum, carbon steel, copper 

alloy, cast iron, and stainless steel components exposed to closed-cycle cooling water, borated 

water leakage, and potable water, with an aging effect of loss of material managed by the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program, that 

cite generic Note G. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.3.12 Auxiliary Building Heating, Ventilation, and Air Conditioning System—Summary of 

Aging Management Review—License Renewal Application Table 3.3.2-12 

The staff reviewed LRA Table 3.3.2-12, which summarizes the results of AMR evaluations for 

the auxiliary building HVAC system component groups. The staff’s review did not find any items 

indicating plant-specific Notes F–J, where the combination of component type, material, 

environment, and AERM does not correspond to an item in the GALL Report. 

SER Section 3.0.2.1 documents the staff’s evaluation of the items with Notes A–E. 

3.3.2.3.13 Fuel Building Heating, Ventilation, and Air Conditioning System—Summary of Aging 

Management Review—License Renewal Application Table 3.3.2-13 

The staff reviewed LRA Table 3.3.2-13, which summarizes the results of AMR evaluations for 

the fuel building HVAC system component groups. 

In LRA Tables 3.3.2-13, 3.3.2-17, 3.3.2-19, 3.3.2-20, 3.3.2-23, and 3.3.2-24, the applicant 

stated that carbon steel closure bolting exposed to atmosphere or weather are managed for loss 

of preload by the Bolting Integrity Program. The AMR items cite generic Note G, indicating that 

the environment is not in the GALL Report for this component and material. The AMR items 

also cite plant-specific note 1, indicating that loss of preload is considered to be applicable for all 

closure bolting. 

SER Section 3.0.3.2.3 documents the staff’s evaluation of the applicant’s Bolting Integrity 

Program. The staff noted that the mechanisms identified in the GALL Report as causing loss of 

preload in carbon steel bolts are thermal effects, gasket creep, and self-loosening, which are not 

all dependent on the environment. The staff also noted that activities in the Bolting Integrity 

Program that control and manage loss of preload are effective for various bolting environments. 
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The staff further noted that the GALL Report, item VII.I-5 (AP-26) recommends using the Bolting 

Integrity Program to manage the aging effect of loss of preload in carbon steel bolts exposed to 

air-indoor uncontrolled. 

On the basis that the GALL Report recommends the Bolting Integrity Program for managing loss 

of preload in carbon steel bolting exposed to atmosphere or weather, and the Bolting Integrity 

Program’s activities for managing loss of preload are applicable for other similar bolting 

environments, the staff finds the applicant’s use of the Bolting Integrity Program to manage loss 

of preload in carbon steel bolting exposed to atmosphere or weather to be acceptable. 

SER Section 3.3.2.3.7 documents the staff’s evaluation for stainless steel and CASS 

components exposed to atmosphere or weather conditions, where there are no AERM and no 

AMP, that cite generic Note G. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.3.14 Containment Building Heating, Ventilation, and Air Conditioning System—Summary 

of Aging Management Review—License Renewal Application Table 3.3.2-14 

The staff reviewed LRA Table 3.3.2-14, which summarizes the results of AMR evaluations for 

the containment building HVAC system component groups. 

The staff’s review did not find any items, indicating plant-specific Notes F–J, where the 

combination of component type, material, environment, and AERM does not correspond to an 

item in the GALL Report. 

SER Section 3.0.2.1 documents the staff’s evaluation of the items with Notes A–E. 

3.3.2.3.15 Diesel Generator Building Heating, Ventilation, and Air Conditioning System—

Summary of Aging Management Review—License Renewal Application 

Table 3.3.2-15 

The staff reviewed LRA Table 3.3.2-15, which summarizes the results of AMR evaluations for 

the diesel generator building HVAC system component groups. 

The staff’s review did not find any items, indicating plant-specific Notes F–J, where the 

combination of component type, material, environment, and AERM does not correspond to an 

item in the GALL Report. 

SER Section 3.0.2.1 documents the staff’s evaluation of the items with Notes A–E. 

3.3.2.3.16 Radwaste Building Heating, Ventilation, and Air Conditioning System—Summary of 

Aging Management Review—License Renewal Application Table 3.3.2-16 

The staff reviewed LRA Table 3.3.2-16, which summarizes the results of AMR evaluations for 

the radwaste building HVAC system component groups. 

The staff’s review did not find any items, indicating plant-specific Notes F–J, where the 

combination of component type, material, environment, and AERM does not correspond to an 

item in the GALL Report. 

SER Section 3.0.2.1 documents the staff’s evaluation of the items with Notes A–E. 
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3.3.2.3.17 Turbine Building Heating, Ventilation, and Air Conditioning System—Summary of 

Aging Management Review—License Renewal Application Table 3.3.2-17 

The staff reviewed LRA Table 3.3.2-17, which summarizes the results of AMR evaluations for 

the turbine building HVAC system component groups. 

In LRA Tables 3.3.2-17, 3.3.2-19, 3.3.2-20, 3.3.2-24, and 3.3.2-28, the applicant stated that the 

aluminum dampers, flame arrestors, valves, vents, and heat exchangers exposed to 

atmosphere or weather (external and internal) are managed for loss of material by the External 

Surfaces Monitoring Program. The AMR items cite generic Note G, indicating that for the item 

the environment is not in the GALL Report for this component and material. SER 

Section 3.0.3.2.14 documents the staff’s evaluation of the applicant’s External Surfaces 

Monitoring Program. The staff noted that all items but one (flame arrestor) are exposed to 

external air. For the excepted item, the applicant has cited plant-specific note 4, which states 

that these items are vented or open to the outside atmosphere so the distinction between 

internal and external is not relevant for aging purposes. 

By letter dated December 29, 2009, the staff issued RAI B2.1.20-2 asking the applicant provide 

additional information on the detection, monitoring, and trending aging effects on hardware 

made of aluminum. By letter dated February 19, 2010, the applicant responded stating that 

aluminum due to its oxide formed on its surface exhibits a good resistance to corrosion except 

when exposed to halide or chloride-aerated solutions. In the mild environment to which 

aluminum components are exposed, the applicant also stated that “...rapid and aggressive 

corrosion of aluminum is not anticipated and visual inspection [performed] for loss of material 

and general corrosion, degraded material or physical conditions, and chipping, cracking, flaking, 

oxidizing, or missing paint and coatings as defined in plant procedures will identify degradation 

deficiencies prior to the loss of intended function.” In addition, the applicant further stated that 

plant procedures require that degradation deficiencies be documented and evaluated and 

corrective actions taken in accordance with standards or site-specific methods. The staff finds 

the applicant’s proposal to manage aging using the External Surfaces Monitoring Program 

acceptable because the applicant assures that aluminum is not exposed to detrimental 

environments and, if material degradation becomes evident, it will document and address the 

degradation through existing plant procedures before the loss of intended functions. 

SER Section 3.3.2.3.13 documents the staff’s evaluation for carbon steel closure bolting 

exposed to atmosphere or weather and fuel oil managed for loss of preload by the Bolting 

Integrity Program, citing generic Note G. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.3.18 Miscellaneous Site Structure and Spray Pond Pump House Heating, Ventilation, 

and Air Conditioning System—Summary of Aging Management Review—License 

Renewal Application Table 3.3.2-18 

The staff reviewed LRA Table 3.3.2-18, which summarizes the results of AMR evaluations for 

the miscellaneous site structures and spray pond pump house HVAC system component 

groups. 

The staff’s review did not find any items, indicating plant-specific Notes F–J, where the 

combination of component type, material, environment, and AERM does not correspond to an 

item in the GALL Report. 

SER Section 3.0.2.1 documents the staff’s evaluation of the items with Notes A–E. 
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3.3.2.3.19 Fire Protection System—Summary of Aging Management Review—License 

Renewal Application Table 3.3.2-19 

The staff reviewed LRA Table 3.3.2-19, which summarizes the results of AMR evaluations for 

the fire protection system component groups. 

In LRA Tables 3.3.2-19 and 3.3.2-21, the applicant stated that copper alloy with greater than 

15-percent zinc piping and valve components exposed to wetted gas are managed for loss of 

material by the Selective Leaching of Materials Program. The applicant cited generic Note G, 

indicating that the environment is not in the GALL Report for this component and material 

combination. 

SER Section 3.0.3.2.11 documents the staff’s evaluation of the applicant’s Selective Leaching of 

Materials Program. The staff noted that the GALL Report, in the definitions section, states that 

copper alloys with greater than 15-percent zinc are susceptible to selective leaching. The staff 

finds the applicant’s use of Selective Leaching of Materials Program acceptable because it uses 

visual inspection and mechanical methods to determine if loss of material due to selective 

leaching is occurring and, if signs of selective leaching are present, it performs metallurgical 

examinations and additional inspections. 

In LRA Tables 3.3.2-19, 3.3.2-22, and 3.3.2-24, the applicant stated that copper alloys and 

copper alloys with Zinc greater than15 percent for piping, piping components, sight gauges, 

strainers, and valves exposed to atmosphere or weather (external and internal) are managed for 

loss of material by the External Surfaces Monitoring Program. The AMR items cite generic Note 

G in all but two of the valve items, indicating that for these items the environment is not in the 

GALL Report for this component and material. The two valve items listed as Note B, should be 

more appropriately listed as G, because for these items the environment is not in the GALL 

Report for this component and material. SER Section 3.0.3.2.14 documents the staff’s 

evaluation of the applicant’s External Surfaces Monitoring Program. The staff noted in 

NUREG-1833, “Technical Bases for Revision to the License Renewal Guidance Documents” 

that copper alloys in dried air environment or in an indoor uncontrolled air environment exhibit 

no aging effects and no AMPS are designated. The staff also noted that NUREG-1833 states 

that comprehensive tests, conducted over a 20-year period under the supervision of ASTM, 

have confirmed the suitability of copper and copper alloys for atmospheric exposure as cited in 

Metals Handbook, Volume 13, “Corrosion,” American Society for Metals, 1987. The staff finds 

the applicant’s proposal to manage aging using the External Surfaces Monitoring Program 

acceptable because PVNGS is located in AZ, where the climate is extremely dry. Hence, 

according to NUREG-1833, no aging effects should be anticipated, and the applicant will still 

manage aging effects in the hardware through visual inspections crediting the External Surfaces 

Monitoring Program. 

In LRA Table 3.3.2-19, the applicant stated that for copper alloy valves internally exposed to 

plant indoor air there is no aging effect and no proposed AMP. The AMR item cites generic 

Note G, indicating that the environment is not in the GALL Report for this component and 

material. The staff reviewed all AMR result items in the GALL Report where the material is 

copper alloy internally exposed to plant indoor air and confirmed that there are no aging effect 

entries in the GALL Report for this component, material, and environment combination. 

The staff notes that the applicant’s definition for the environment of plant indoor air as “indoor air 

on systems with temperatures higher than the dew point” is the same as the GALL Report 

definition for “air-indoor uncontrolled” in Table XI.D. The staff also notes that copper alloy 

valves are subject to the same aging effects (or lack of aging effects) on both the internal and 

external surface of the component exposed to a plant indoor air environment. The staff further 

notes that GALL Report, item VIII.I-2 identifies no aging effect or AMP for copper alloy 

components exposed to uncontrolled indoor air (external). Since the LRA components are 
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similar to other GALL Report items for the material and environment (i.e., GALL Report, item 

VIII.I-2, where the AERM is listed as “none,” the AMP is listed as “none,” and no further 

evaluation is required), the staff concurs that the effect of plant indoor air on the internal surface 

of copper alloy valves will not result in aging that will be of concern during the period of 

extended operation. 

In LRA Table 3.3.2-19, the applicant stated that the Fire Protection Program manages 

thermo-lag fire barrier seals, externally exposed to plant indoor air, for loss of material and 

cracking. The AMR items cite generic Note J, indicating that neither the component nor the 

material and environment combination is evaluated in the GALL Report. 

The staff reviewed the applicant’s Fire Protection Program, and SER Section 3.0.3.2.7 

documents its evaluation. The staff noted that the applicant’s Fire Protection Program provides 

for visual inspection of fire barriers once every 18 months for detection of cracking and loss of 

material. The staff also noted that thermo-lag is primarily used to provide fire barriers for cable 

trays and conduits. The staff finds the applicant’s proposal to manage aging using the Fire 

Protection Program acceptable because the program performs visual inspections of fire barriers 

that are capable of detecting loss of material and cracking for thermo-lag fire barriers. 

SER Section 3.3.2.3.13 documents the staff’s evaluation for carbon steel closure bolting 

exposed to atmosphere or weather and fuel oil managed for loss of preload by the Bolting 

Integrity Program, citing generic Note G. 

SER Section 3.3.2.3.7 documents the staff’s evaluation for PVC, fiberglass, and polyethylene 

piping and piping components exposed to plant indoor air, buried external environments, and 

raw water internal environment with no aging effects and no AMP, citing generic Note F. 

SER Section 3.3.2.3.7 documents the staff’s evaluation for stainless steel and CASS 

components exposed to atmosphere or weather conditions, where there are no AERM and no 

AMP, citing generic Note G. 

SER Section 3.3.2.3.17 documents the staff’s evaluation for aluminum dampers, flame 

arrestors, valves, vents, and heat exchangers exposed to atmosphere or weather (external and 

internal) and managed for loss of material corrosion by the External Surfaces Monitoring 

Program with generic Note G. 

3.3.2.3.20 Diesel Generator Fuel Oil Storage and Transfer System—Summary of Aging 

Management Review—License Renewal Application Table 3.3.2-20 

The staff reviewed LRA Table 3.3.2-20, which summarizes the results of AMR evaluations for 

the diesel generator fuel oil storage and transfer system component groups. 

SER Section 3.3.2.3.2 documents the staff’s evaluation for stainless steel closure bolting 

exposed to treated borated water managed for loss of preload by the Bolting Integrity Program, 

citing generic Note G. 

SER Section 3.3.2.3.13 documents the staff’s evaluation for carbon steel closure bolting 

exposed to atmosphere or weather and fuel oil managed for loss of preload by the Bolting 

Integrity Program, citing generic Note G. 

SER Section 3.3.2.3.17 documents the staff’s evaluation for aluminum dampers, flame 

arrestors, valves, vents, and heat exchangers exposed to atmosphere or weather (external and 

internal), managed for loss of material corrosion by the External Surfaces Monitoring Program, 

citing generic Note G. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 
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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). 

3.3.2.3.21 Diesel Generator—Summary of Aging Management Review—License Renewal 

Application Table 3.3.2-21 

The staff reviewed LRA Table 3.3.2-21, which summarizes the results of AMR evaluations for 

the diesel generator component groups. 

In LRA Tables 3.3.2-4, 3.3.2-10, and 3.3.2-21, the applicant stated that calcium silicate and 

mineral wool insulation exposed to borated water leakage have no AERM and no proposed 

AMP. The AMR items cite generic Note J. SER Section 3.3.2.3.4 documents the staff’s review. 

In LRA Tables 3.3.2-21, 3.3.2-28, and 3.4.2-3, the applicant stated that the aluminum heat 

exchanger (governor oil cooler), valve, and filter exposed to lubricating oil are managed for loss 

of material by the Lubricating Oil Analysis and One-Time Inspection Programs. The AMR items 

cite generic Note G, indicating that for the items, the environment is not in the GALL Report for 

this component and material. 

The staff also reviewed the applicant’s Lubricating Oil Analysis and One-Time Inspection 

Programs, and SER Sections 3.0.3.2.16 and 3.0.3.1.6 document their evaluations, respectively. 

The staff finds the applicant’s proposed AMPs acceptable because the Lubricating Oil Analysis 

Program will control contaminates within limits to preclude loss of material, and the One-Time 

Inspection Program will verify the effectiveness of the Lubricating Oil Analysis Program by 

verifying that loss of material is not occurring. 

In LRA Table 3.3.2-21, the applicant stated that for nickel-alloy valves exposed internally to dry 

gas there is no aging effect and no proposed AMP. The AMR item cites generic Note G. 

The staff reviewed the associated items in the LRA and confirmed that no aging effect is 

applicable for this component, material, and environment because austenitic materials such as 

nickel alloys are not subject to loss of material or cracking when exposed to this environment, 

and these materials are used as corrosion-resistant replacement materials where other 

materials have degraded. The staff noted that corrosion-resistant materials, such as austenitic 

and martensitic stainless steels and high strength nickel base alloys, offer good protection 

against loss of material. The staff also noted that the conditions required for cracking due to a 

variety of mechanisms (SCC, PWSCC, IASCC and IGSCC) to occur, such as being exposed to 

an aqueous solution (reactor coolant or other corrosive solutions) and high temperatures, do not 

exist on the surfaces of these components when exposed to dry gas. The staff noted that GALL 

Report, AMR item IV.E-1 states that nickel alloys exposed to air-indoor uncontrolled is not 

subject to an aging effect requiring management. The staff noted that an air-indoor uncontrolled 

environment is more aggressive than a dry gas environment because it is possible for 

condensation to occur in an air-indoor uncontrolled environment. The staff finds the applicant’s 

determination acceptable because nickel alloy is a highly corrosion-resistant material and it is 

not subject to conditions where cracking is possible. In addition, this component is exposed to a 

less aggressive environment when compared to GALL Report, AMR item IV.E-1, for which there 

is no AERM. 

SER Section 3.3.2.3.3 documents the staff’s evaluation for stainless steel closure bolting 

exposed to plant indoor air managed for loss of preload by the Bolting Integrity Program, citing 

generic note G. 

SER Section 3.3.2.3.19 documents the staff’s evaluation for copper alloy with greater than 

15-percent zinc piping and valve components exposed to wetted gas managed for loss of 

material for by the Selective Leaching of Materials Program, citing generic Note G. 
Aging Management Review Results 

 3-265 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.3.22 Domestic Water System—Summary of Aging Management Review—License 

Renewal Application Table 3.3.2-22 

The staff reviewed LRA Table 3.3.2-22, which summarizes the results of AMR evaluations for 

the domestic water system component groups. 

In LRA Tables 3.3.2-22 and 3.3.2-24, the applicant stated that copper alloy sight gauges, 

strainers, and valves exposed to atmosphere or weather are managed for loss of material by the 

External Surfaces Monitoring Program. The applicant cited generic Note G, indicating that the 

environment is not in the GALL Report for this component and material combination. 

SER Section 3.0.3.2.14 documents the staff’s evaluation of the applicant’s External Surfaces 

Monitoring Program. The applicant stated that the External Surfaces Monitoring Program 

conducts visual inspections on external surfaces to detect aging effects that could result in a 

loss of component intended function. The staff finds the applicant’s use of the External 

Surfaces Monitoring Program acceptable because this program conducts visual inspections that 

are capable of detecting loss of material on the external surfaces of the components being 

managed. 

In LRA Tables 3.3.2-22 and 3.3.2-30, the applicant stated that copper alloy piping, pumps, 

strainers, and valves exposed to potable water are managed for loss of material by the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The 

applicant cited generic Note G, indicating that the environment is not in the GALL Report for this 

component and material combination. 

SER Section 3.0.3.1.15 documents the staff’s evaluation of the applicant’s Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program. The applicant stated that 

the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program 

conducts visual inspections during periodic maintenance, predictive maintenance, surveillance 

testing, and corrective maintenance and is capable of detecting loss of material that could result 

in a loss of component intended function. The staff finds the applicant’s use of Internal Surfaces 

in Miscellaneous Piping and Ducting Components Program to manage loss of material for these 

components acceptable because it uses visual inspection to detect loss of material. 

SER Section 3.3.2.3.7 documents the staff’s evaluation for copper alloy and copper alloy with 

greater than 8-percent aluminum closure bolting exposed to plant indoor air managed for loss of 

preload by the Bolting Integrity Program, citing generic Notes F and G. 

SER Section 3.3.2.3.3 documents the staff’s evaluation for stainless steel closure bolting 

exposed to plant indoor air managed for loss of preload by the Bolting Integrity Program, citing 

generic Note G. 

SER Section 3.3.2.3.19 documents the staff’s evaluation for copper alloys and copper alloys 

with zinc greater than 15-percent piping, piping components, sight gauges, strainers, and valves 

exposed to atmosphere or weather (external and internal) managed for loss of material by the 

External Surfaces Monitoring Program, citing generic Note G. 

SER Section 3.3.2.3.7 documents the staff’s evaluation for PVC, fiberglass, and polyethylene 

piping and piping components exposed to plant indoor air, buried external environments, and 

raw water internal environment with no aging effects and no AMP, citing generic Note F. 
Aging Management Review Results 

 3-266 

SER Section 3.3.2.3.3 documents the staff’s evaluation for aluminum, carbon steel, copper 

alloy, cast iron, and stainless steel components exposed to closed-cycle cooling water, borated 

water leakage, and potable water, with an aging effect of loss of material managed by the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program, 

citing generic Note G. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.3.23 Demineralized Water System—Summary of Aging Management Review—License 

Renewal Application Table 3.3.2-23 

The staff reviewed LRA Table 3.3.2-23, which summarizes the results of AMR evaluations for 

the demineralized water system component groups. 

SER Section 3.3.2.3.3 documents the staff’s evaluation for stainless steel closure bolting 

exposed to plant indoor air managed for loss of preload by the Bolting Integrity Program, citing 

generic Note G. 

SER Section 3.3.2.3.13 documents the staff’s evaluation for carbon steel closure bolting 

exposed to atmosphere or weather and fuel oil managed for loss of preload by the Bolting 

Integrity Program, citing generic Note G. 

SER Section 3.3.2.3.7 documents the staff’s evaluation for stainless steel and CASS 

components exposed to atmosphere or weather conditions, where there are no AERM and no 

AMP, that cite generic Note G. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.3.24 Water Reclamation Facility Fuel System—Summary of Aging Management 

Review—License Renewal Application Table 3.3.2-24 

The staff reviewed LRA Table 3.3.2-24, which summarizes the results of AMR evaluations for 

the WRF fuel system component groups. 

In LRA Table 3.3.2-24, the applicant stated that for sight gauges made of glass exposed to 

atmosphere or weather (external) there is no aging effect and no proposed AMP. The AMR 

item cites generic Note G, indicating that for the item, the environment is not in the GALL Report 

for this component and material. 

The staff noted that in LRA Table 3.0-1, the applicant described atmosphere weather as moist, 

ambient temperatures, humidity, and exposure to weather, including precipitation and wind, with 

temperature extremes of 11 degrees F to 121 degrees F. The staff finds the applicant’s 

proposal acceptable because the GALL Report does not identify an aging effect for any glass 

material exposed to any environment (e.g., lubricating oil, air, treated borated water) and the 

atmosphere weather environment is less aggressive than the examples in the GALL Report; 

therefore, no AMP is required. 

SER Section 3.3.2.3.13 documents the staff’s evaluation for carbon steel closure bolting 

exposed to atmosphere or weather and fuel oil managed for loss of preload by the Bolting 

Integrity Program, citing generic Note G. 
Aging Management Review Results 

 3-267 

SER Section 3.3.2.3.19 documents the staff’s evaluation for copper alloys and copper alloys 

with Zinc greater than 15-percent piping, piping components, sight gauges, and valves exposed 

to atmosphere or weather (external and internal) managed for loss of material by the External 

Surfaces Monitoring Program with generic Note G. 

SER Section 3.3.2.3.7 documents the staff’s evaluation for stainless steel and CASS 

components exposed to atmosphere or weather conditions, where there are no AERM and no 

AMP, citing generic Note G. 

SER Section 3.3.2.3.17 documents the staff’s evaluation for aluminum dampers, flame 

arrestors, valves, vents, and heat exchangers exposed to atmosphere or weather (external and 

internal) managed for loss of material corrosion by the External Surfaces Monitoring Program 

with generic Note G. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.3.25 Service Gases (Nitrogen and Hydrogen) System—Summary of Aging Management 

Review—License Renewal Application Table 3.3.2-25 

The staff reviewed LRA Table 3.3.2-25, which summarizes the results of AMR evaluations for 

the service gases (N2

 and H2) system component groups. 

The staff’s review did not find any items indicating plant-specific Notes F–J, where the 

combination of component type, material, environment, and AERM does not correspond to an 

item in the GALL Report. 

SER Section 3.0.2.1 documents the staff’s evaluation of the items with Notes A–E. 

3.3.2.3.26 Gaseous Radwaste System—Summary of Aging Management Review—License 

Renewal Application Table 3.3.2-26 

The staff reviewed LRA Table 3.3.2-26, which summarizes the results of AMR evaluations for 

the gaseous radwaste system component groups. 

The staff’s review did not find any items indicating plant-specific Notes F–J, where the 

combination of component type, material, environment, and AERM does not correspond to an 

item in the GALL Report. 

SER Section 3.0.2.1 documents the staff’s evaluation of the items with Notes A–E. 

3.3.2.3.27 Radioactive Waste Drains System—Summary of Aging Management Review—

License Renewal Application Table 3.3.2-27 

The staff reviewed LRA Table 3.3.2-27, which summarizes the results of AMR evaluations for 

the radioactive waste drains system component groups. 

SER Section 3.3.2.3.3 documents the staff’s evaluation for stainless steel closure bolting 

exposed to plant indoor air managed for loss of preload by the Bolting Integrity Program, citing 

generic Note G. 

SER Section 3.3.2.3.7 documents the staff’s evaluation for stainless steel and CASS 

components exposed to atmosphere or weather conditions, where there are no AERM and no 

AMP, that cite generic Note G. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 
Aging Management Review Results 

 3-268 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.3.28 Station Blackout Generator—Summary of Aging Management Review—License 

Renewal Application Table 3.3.2-28 

The staff reviewed LRA Table 3.3.2-28, which summarizes the results of AMR evaluations for 

the SBO generator component groups. 

SER Section 3.3.2.3.3 documents the staff’s evaluation for stainless steel closure bolting 

exposed to plant indoor air managed for loss of preload by the Bolting Integrity Program, citing 

generic Note G. 

SER Section 3.3.2.3.17 documents the staff’s evaluation for aluminum dampers, flame 

arrestors, valves, vents, and heat exchangers exposed to atmosphere or weather (external and 

internal) managed for loss of material corrosion by the External Surfaces Monitoring Program 

with generic Note G. 

SER Section 3.3.2.3.21 documents the staff’s evaluation for aluminum heat exchanger 

(governor oil cooler), valve, and filter exposed to lubricating oil and managed for loss of material 

by the Lubricating Oil Analysis and One-Time Inspection Programs with generic Note G. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.3.29 Cranes, Hoists, and Elevators—Summary of Aging Management Review—License 

Renewal Application Table 3.3.2-29 

The staff reviewed LRA Table 3.3.2-29, which summarizes the results of AMR evaluations for 

the cranes, hoists, and elevators component groups. 

The staff’s review did not find any items indicating plant-specific Notes F–J, where the 

combination of component type, material, environment, and AERM does not correspond to an 

item in the GALL Report. 

SER Section 3.0.2.1 documents the staff’s evaluation of the items with Notes A–E. 

3.3.2.3.30 Miscellaneous Auxiliary Systems In-Scope Only for Criterion Under Title 10, 

Part 54.4(a)(2) of the Code of Federal Regulations—Summary of Aging 

Management Review—License Renewal Application Table 3.3.2-30 

The staff reviewed LRA Table 3.3.2-30, which summarizes the results of AMR evaluations for 

the miscellaneous auxiliary systems in-scope only for criterion 10 CFR 54.4(a)(2) component 

groups. 

SER Section 3.3.2.3.7 documents the staff’s evaluation for copper alloy and copper alloy with 

greater than 8-percent aluminum closure bolting exposed to plant indoor air managed for loss of 

preload by the Bolting Integrity Program, citing generic Notes F and G. 

SER Section 3.3.2.3.3 documents the staff’s evaluation for stainless steel closure bolting 

exposed to plant indoor air managed for loss of preload by the Bolting Integrity Program, citing 

generic Note G. 

SER Section 3.3.2.3.22 documents the staff’s evaluation for copper alloy piping, pumps, 

strainers, and valves exposed to potable water managed for loss of material by the Inspection of 
Aging Management Review Results 

 3-269 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program, citing generic 

Note G. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.3.31 Auxiliary Systems—Summary of Aging Management Evaluation—Oily Waste and 

Non-Radioactive Waste System—License Renewal Application Table 3.3.2-31 

SER Section 3.3.2.3.7 documents the staff’s evaluation for copper alloy and copper alloy with 

greater than 8-percent aluminum closure bolting exposed to plant indoor air managed for loss of 

preload by the Bolting Integrity Program, citing generic Notes F and G. 

SER Section 3.3.2.3.3 documents the staff’s evaluation for stainless steel closure bolting 

exposed to plant indoor air managed for loss of preload by the Bolting Integrity Program, citing 

generic Note G. 

SER Section 3.3.2.3.3 documents the staff’s evaluation for aluminum, carbon steel, copper 

alloy, cast iron, and stainless steel components exposed to closed-cycle cooling water, borated 

water leakage and potable water, with an aging effect of loss of material managed by the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program, 

citing generic Note G. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.3 Conclusion 

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the auxiliary systems components 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). 

3.4 Aging Management of Steam and Power Conversion Systems

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

steam and power conversion systems components and component groups of the following 

systems: 

 main steam system 

 condensate storage and transfer system 

 auxiliary feedwater (AFW) system 

3.4.1 Summary of Technical Information in the Application 

LRA Section 3.4 provides AMR results for the steam and power conversion systems 

components and component groups. LRA Table 3.4.1, “Summary of Aging Management 

Evaluations in Chapter VIII of NUREG-1801 [GALL Report] for Steam and Power Conversion 

Systems,” is a summary comparison of the applicant’s AMRs with those evaluated in the GALL 

Report for the steam and power conversion systems components and component groups. 
Aging Management Review Results 

 3-270 

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry 

operating experience in the determination of AERMs. The plant-specific evaluation included 

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 provided sufficient information 

to demonstrate that it will adequately manage the effects of aging for the steam and power 

conversion systems components within the scope of license renewal and subject to an AMR, 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 reviewed AMRs to ensure the applicant’s claim that certain 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 identified the appropriate GALL Report AMRs. SER Section 3.0.3 documents 

the staff’s evaluations of the AMPs, and SER Section 3.4.2.1 details the staff’s evaluation. 

The staff also reviewed AMRs 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 SRP-LR Section 3.4.2.2 acceptance criteria. SER Section 3.4.2.2 documents the 

staff’s evaluations. 

The staff also conducted a technical review of the remaining AMRs not consistent with or not 

addressed in the GALL Report. The technical review evaluated if the applicant noted all 

plausible aging effects and if the aging effects listed were appropriate for the materialenvironment combinations specified. SER Section 3.4.2.3 documents the staff’s evaluations. 

For SSCs that the applicant claimed were not applicable or required no aging management, the 

staff reviewed the AMR items and the plant’s operating experience to verify the applicant’s 

claims. 

Table 3.4-1 summarizes the staff’s evaluation of components, aging effects or mechanisms, and 

AMPs listed in LRA Section 3.4 and addressed in the GALL Report. 

Table 3.4-1. Staff Evaluation for Steam and Power Conversion Systems Components 

in the GALL Report 

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Steel piping, piping 

components, and piping 

elements exposed to steam 

or treated water 

(3.4.1-1) 

Cumulative fatigue 

damage 

TLAA, evaluated 

in accordance 

with 

10 CFR 54.21(c)

Yes TLAA Consistent 

with GALL 

Report. See 

SER Section 

3.4.2.2.1. 

Steel piping, piping 

components, and piping 

elements exposed to steam 

(3.4.1-2) 

Loss of material due 

to general, pitting 

and crevice 

corrosion 

Water Chemistry 

and One-Time 

Inspection 

Yes Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.4.2.2.5(3). 
Aging Management Review Results 

 3-271 

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Steel heat exchanger 

components exposed to 

treated water 

(3.4.1-3) 

Loss of material due 

to general, pitting 

and crevice 

corrosion 

Water Chemistry 

and One-Time 

Inspection 

Yes Water 

Chemistry and 

One-Time 

Inspection 

Consistent 

with GALL 

Report. See 

SER Section 

3.4.2.2.2(1). 

Steel piping, piping 

components, and piping 

elements exposed to treated 

water 

(3.4.1-4) 

Loss of material due 

to general, pitting 

and crevice 

corrosion 

Water Chemistry 

and One-Time 

Inspection 

Yes Water 

Chemistry and 

One-Time 

Inspection 

Consistent 

with GALL 

Report. See 

SER Section 

3.4.2.2.2(1). 

Steel heat exchanger 

components exposed to 

treated water 

(3.4.1-5) 

Loss of material due 

to general, pitting, 

crevice, and 

galvanic corrosion 

Water Chemistry 

and One-Time 

Inspection 

Yes Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.4.2.1.1. 

Steel and stainless steel 

tanks exposed to treated 

water 

(3.4.1-6) 

Loss of material due 

to general (steel 

only) pitting and 

crevice corrosion 

Water Chemistry 

and One-Time 

Inspection 

Yes Water 

Chemistry and 

One-Time 

Inspection 

Consistent 

with GALL 

Report. See 

SER Section 

3.4.2.2.7(1). 

Steel piping, piping 

components, and piping 

elements exposed to 

lubricating oil 

(3.4.1-7) 

Loss of material due 

to general, pitting 

and crevice 

corrosion 

Lubricating Oil 

Analysis and 

One-Time 

Inspection 

Yes Lubricating Oil 

Analysis and 

One-Time 

Inspection 

Consistent 

with GALL 

Report. See 

SER Section 

3.4.2.2.2(2). 

Steel piping, piping 

components, and piping 

elements exposed to raw 

water 

(3.4.1-8) 

Loss of material due 

to general, pitting, 

crevice, and MIC 

and fouling 

Plant specific Yes Not Applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.4.2.2.3. 

Stainless steel and copper 

alloy heat exchanger tubes 

exposed to treated water 

(3.4.1-9) 

Reduction of heat 

transfer due to 

fouling 

Water Chemistry 

and One-Time 

Inspection 

Yes Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.4.2.2.4(1). 

Steel, stainless steel, and 

copper alloy heat exchanger 

tubes exposed to lubricating 

oil 

(3.4.1-10) 

Reduction of heat 

transfer due to 

fouling 

Lubricating Oil 

Analysis and 

One-Time 

Inspection 

Yes Lubricating Oil 

Analysis and 

One-Time 

Inspection 

Consistent 

with GALL 

Report. See 

SER Section 

3.4.2.2.4(2). 

Buried steel piping, piping 

components, piping elements, 

and tanks (with or without 

coating or wrapping) exposed 

to soil 

(3.4.1-11) 

Loss of material due 

to general, pitting, 

crevice, and MIC 

Buried Piping 

and Tanks 

Surveillance 

or 

Buried Piping 

and Tanks 

Inspection 

No

Yes 

Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.4.2.2.5(1). 
Aging Management Review Results 

 3-272 

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Steel heat exchanger 

components exposed to 

lubricating oil 

(3.4.1-12) 

Loss of material due 

to general, pitting, 

crevice, and MIC 

Lubricating Oil 

Analysis and 

One-Time 

Inspection 

Yes Lubricating Oil 

Analysis and 

One-Time 

Inspection 

Consistent 

with GALL 

Report. See 

SER Section 

3.4.2.2.5(2). 

Stainless steel piping, piping 

components, piping elements 

exposed to steam 

(3.4.1-13) 

Cracking due to 

SCC 

Water Chemistry 

and One-Time 

Inspection 

Yes Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.4.2.1.1. 

Stainless steel piping, piping 

components, piping elements, 

tanks, and heat exchanger 

components exposed to 

treated water > 60°C 

(> 140°F) 

(3.4.1-14) 

Cracking due to 

SCC 

Water Chemistry 

and One-Time 

Inspection 

Yes Water 

Chemistry and 

One-Time 

Inspection 

Consistent 

with GALL 

Report. See 

SER Section 

3.4.2.2.6. 

Aluminum and copper alloy 

piping, piping components, 

and piping elements exposed 

to treated water 

(3.4.1-15) 

Loss of material due 

to pitting and crevice 

corrosion 

Water Chemistry 

and One-Time 

Inspection 

Yes Water 

Chemistry and 

One-Time 

Inspection 

Consistent 

with GALL 

Report. See 

SER Section 

3.4.2.2.7(1). 

Stainless steel piping, piping 

components, and piping 

elements; tanks, and heat 

exchanger components 

exposed to treated water 

(3.4.1-16) 

Loss of material due 

to pitting and crevice 

corrosion 

Water Chemistry 

and One-Time 

Inspection 

Yes Water 

Chemistry and 

One-Time 

Inspection 

Consistent 

with GALL 

Report. See 

SER Section 

3.4.2.2.7(1). 

Stainless steel piping, piping 

components, and piping 

elements exposed to soil 

(3.4.1-17) 

Loss of material due 

to pitting and crevice 

corrosion 

Plant specific Yes Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.4.2.2.7(2). 

Copper alloy piping, piping 

components, and piping 

elements exposed to 

lubricating oil 

(3.4.1-18) 

Loss of material due 

to pitting and crevice 

corrosion 

Lubricating Oil 

Analysis and 

One-Time 

Inspection 

Yes Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.4.2.2.7(3). 

Stainless steel piping, piping 

components, piping elements, 

and heat exchanger 

components exposed to 

lubricating oil 

(3.4.1-19) 

Loss of material due 

to pitting, crevice, 

and MIC 

Lubricating Oil 

Analysis and 

One-Time 

Inspection 

Yes Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.4.2.2.8. 

Steel tanks exposed to air -

outdoor (external) 

(3.4.1-20) 

Loss of material, 

general, pitting, and 

crevice corrosion 

Aboveground 

Steel Tanks 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.4.2.1.1. 
Aging Management Review Results 

 3-273 

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

High-strength steel closure 

bolting exposed to air with 

steam or water leakage 

(3.4.1-21) 

Cracking due to 

cyclic loading, SCC 

Bolting Integrity No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.4.2.1.1. 

Steel bolting and closure 

bolting exposed to air with 

steam or water leakage, air - 

outdoor (external), or air - 

indoor uncontrolled (external); 

(3.4.1-22) 

Loss of material due 

to general, pitting 

and crevice 

corrosion; loss of 

preload due to 

thermal effects, 

gasket creep, and 

self-loosening 

Bolting Integrity No Bolting 

Integrity 

Consistent 

with GALL 

Report. 

Stainless steel piping, piping 

components, and piping 

elements exposed to closedcycle cooling water > 60°C 

(> 140°F) 

(3.4.1-23) 

Cracking due to 

SCC 

Closed-Cycle 

Cooling Water 

System 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.4.2.1.1. 

Steel heat exchanger 

components exposed to 

closed cycle cooling water 

(3.4.1-24) 

Loss of material due 

to general, pitting, 

crevice, and 

galvanic corrosion 

Closed-Cycle 

Cooling Water 

System 

No Closed-Cycle 

Cooling Water 

System 

Consistent 

with GALL 

Report. 

Stainless steel piping, piping 

components, piping elements, 

and heat exchanger 

components exposed to 

closed cycle cooling water 

(3.4.1-25) 

Loss of material due 

to pitting and crevice 

corrosion 

Closed-Cycle 

Cooling Water 

System 

No Closed-Cycle 

Cooling Water 

System 

Consistent 

with GALL 

Report. 

Copper alloy piping, piping 

components, and piping 

elements exposed to closed 

cycle cooling water 

(3.4.1-26) 

Loss of material due 

to pitting, crevice, 

and galvanic 

corrosion 

Closed-Cycle 

Cooling Water 

System 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.4.2.1.1. 

Steel, stainless steel, and 

copper alloy heat exchanger 

tubes exposed to closed cycle 

cooling water 

(3.4.1-27) 

Reduction of heat 

transfer due to 

fouling 

Closed-Cycle 

Cooling Water 

System 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.4.2.1.1. 

Steel external surfaces 

exposed to air - indoor 

uncontrolled (external), 

condensation (external), or air 

outdoor (external) 

(3.4.1-28) 

Loss of material due 

to general corrosion 

External 

Surfaces 

Monitoring 

No External 

Surfaces 

Monitoring 

Consistent 

with GALL 

Report. 

Steel piping, piping 

components, and piping 

elements exposed to steam 

or treated water 

(3.4.1-29) 

Wall thinning due to 

FAC 

FAC No FAC Consistent 

with GALL 

Report. 
Aging Management Review Results 

 3-274 

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Steel piping, piping 

components, and piping 

elements exposed to air 

outdoor (internal) or 

condensation (internal) 

(3.4.1-30) 

Loss of material due 

to general, pitting, 

and crevice 

corrosion 

Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Consistent 

with GALL 

Report. 

Steel heat exchanger 

components exposed to raw 

water 

(3.4.1-31) 

Loss of material due 

to general, pitting, 

crevice, galvanic, 

and MIC and fouling 

Open-Cycle 

Cooling Water 

System 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.4.2.1.1. 

Stainless steel and copper 

alloy piping, piping 

components, and piping 

elements exposed to raw 

water 

(3.4.1-32) 

Loss of material due 

to pitting, crevice, 

and MIC 

Open-Cycle 

Cooling Water 

System 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.4.2.1.1. 

Stainless steel heat 

exchanger components 

exposed to raw water 

(3.4.1-33) 

Loss of material due 

to pitting, crevice, 

and MIC and fouling 

Open-Cycle 

Cooling Water 

System 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.4.2.1.1. 

Steel, stainless steel, and 

copper alloy heat exchanger 

tubes exposed to raw water 

(3.4.1-34) 

Reduction of heat 

transfer due to 

fouling 

Open-Cycle 

Cooling Water 

System 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.4.2.1.1. 

Copper alloy > 15% Zn 

piping, piping components, 

and piping elements exposed 

to closed cycle cooling water, 

raw water, or treated water 

(3.4.1-35) 

Loss of material due 

to selective leaching

Selective 

Leaching of 

Materials 

No Selective 

Leaching of 

Materials 

Consistent 

with GALL 

Report. 

Gray cast iron piping, piping 

components, and piping 

elements exposed to soil, 

treated water, or raw water 

(3.4.1-36) 

Loss of material due 

to selective leaching

Selective 

Leaching of 

Materials 

No Selective 

Leaching of 

Materials 

Consistent 

with GALL 

Report. 

Steel, stainless steel, and 

nickel-based alloy piping, 

piping components, and 

piping elements exposed to 

steam 

(3.4.1-37) 

Loss of material due 

to pitting and crevice 

corrosion 

Water Chemistry No Water 

Chemistry 

Consistent 

with GALL 

Report. 

Steel bolting and external 

surfaces exposed to air with 

borated water leakage 

(3.4.1-38) 

Loss of material due 

to boric acid 

corrosion 

Boric Acid 

Corrosion 

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.4.2.1.1. 
Aging Management Review Results 

 3-275 

Component Group (GALL 

Report Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Stainless steel piping, piping 

components, and piping 

elements exposed to steam 

(3.4.1-39) 

Cracking due to 

SCC 

Water Chemistry No Water 

Chemistry 

Consistent 

with GALL 

Report. 

Glass piping elements 

exposed to air, lubricating oil, 

raw water, and treated water 

(3.4.1-40) 

None None NA None Consistent 

With GALL 

Report. 

Stainless steel, copper alloy, 

and nickel-alloy piping, piping 

components, and piping 

elements exposed to air - 

indoor uncontrolled (external) 

(3.4.1-41) 

None None NA None Consistent 

with GALL 

Report. 

Steel piping, piping 

components, and piping 

elements exposed to air - 

indoor controlled (external) 

(3.4.1-42) 

None None NA Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.4.2.1.1. 

Steel and stainless steel 

piping, piping components, 

and piping elements in 

concrete 

(3.4.1-43) 

None None NA None Consistent 

with GALL 

Report. 

Steel, stainless steel, 

aluminum, and copper alloy 

piping, piping components, 

and piping elements exposed 

to gas 

(3.4.1-44) 

None None NA None Consistent 

with GALL 

Report. 

 

The staff’s review of the steam and power conversion systems component groups followed any 

one of several approaches. One approach, documented in SER Section 3.4.2.1, reviewed AMR 

results for components that the applicant indicated are consistent with the GALL Report and 

require no further evaluation. Another approach, documented in SER Section 3.4.2.2, reviewed 

AMR results for components that the applicant indicated are consistent with the GALL Report 

and for which further evaluation is recommended. A third approach, documented in SER 

Section 3.4.2.3, reviewed AMR results for components that the applicant indicated are not 

consistent with, or not addressed in, the GALL Report. SER Section 3.0.3 documents the staff’s 

review of AMPs credited to manage or monitor aging effects of the steam and power conversion 

systems components. 

3.4.2.1 Aging Management Review Results Consistent with the Generic Aging Lessons 

Learned Report 

LRA Section 3.4.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the steam and power conversion systems components: 

 Bolting Integrity Program 
Aging Management Review Results 

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 External Surfaces Monitoring Program 

 FAC Program 

 One-Time Inspection Program 

 Water Chemistry Program 

LRA Tables 3.4.2-1 through 3.4.2-3 summarize AMRs for the steam and power conversion 

systems components and indicate AMRs claimed to be consistent with the GALL Report. 

The staff audited and reviewed the information in the LRA. The staff did not repeat its review of 

the matters described in the GALL Report; however, the staff did verify that the material 

presented in the LRA was applicable and that the applicant identified the appropriate GALL 

Report AMRs. 

The staff reviewed the LRA to confirm that the applicant provided a brief description of the 

system, components, materials, and environments; stated that the applicable aging effects were 

reviewed and evaluated in the GALL Report; and identified those aging effects for the steam 

and power conversion systems components that are subject to an AMR. On the basis of its 

review, the staff determines that, for AMRs not requiring further evaluation, as identified in LRA 

Table 3.4.1, the applicant’s references to the GALL Report are acceptable and no further staff 

review is required. 

3.4.2.1.1 Aging Management Review Results Identified as Not Applicable 

LRA Table 3.4.1, items 3.4.1.5 and 3.4.1.13 discuss the applicant’s determination that these 

items are applicable only to BWRs. The staff verified that these items do not apply because the 

units are a PWR design. Based on this determination, the staff finds that the applicant has 

provided an acceptable basis for concluding AMR items 3.4.1.5 and 3.4.1.13 are not applicable. 

LRA Table 3.4.1, item 3.4.1.20 addresses steel tanks exposed to outdoor air (external). The 

applicant stated that this item is not applicable because there are no steel tanks in the 

condensate or AFW systems that are exposed to the outdoor air (external) environment. The 

staff reviewed LRA Sections 2.3.4 and 3.4 and confirmed that the applicant’s LRA does not 

have any AMR results for the condensate storage and transfer and AFW systems that include 

steel tanks exposed to outdoor air (external). The staff also reviewed the applicant’s information 

in the UFSAR and confirmed that no in-scope steel tanks exposed to outdoor air (external) are 

present in the condensate storage and transfer and AFW systems. Therefore, the staff finds the 

applicant’s determination acceptable. 

LRA Table 3.4.1, item 3.4.1.21 addresses high-strength steel closure bolting exposed to air with 

steam or water leakage in the steam and power conversion systems. The GALL Report 

recommends use of AMP XI.M18, “Bolting Integrity,” to manage cracking due to cyclic loading or 

SCC for this component group. The applicant stated that this item is not applicable because 

high-strength closure bolting is not used in the steam and power conversion systems. The staff 

reviewed LRA Sections 2.3.4 and 3.4 and the UFSAR and confirmed that the applicant’s LRA 

does not have any AMR results for the steam and power conversion systems that include 

high-strength steel closure bolting exposed to air with steam or water leakage. During its review 

of operating experience and applicant interviews associated with the Bolting Integrity Program, 

the staff did not find any evidence of high-strength steel closure bolting in the steam and power 

conversion systems. Based on its review of the LRA, UFSAR, and the applicant’s Bolting 

Integrity Program, the staff confirmed that there is no high-strength steel closure bolting 

exposed to air with steam or water leakage in the steam and power conversion systems and, 

therefore, it finds the applicant’s determination acceptable. 

LRA Table 3.4.1, item 3.4.1.23 addresses stainless steel piping, piping components, and piping 

elements exposed to closed-cycle cooling water greater than 60 degrees C (140 degrees F). 

The GALL Report recommends use of AMP XI.M21, “Closed-Cycle Cooling Water,” to manage 
Aging Management Review Results 

 3-277 

cracking due to SCC for this component group. The applicant stated that this item is not 

applicable because it has no in-scope stainless steel piping, piping components, and piping 

elements exposed to closed-cycle cooling water greater than 60 degrees C (140 degrees F) in 

the condensate, blowdown, or AFW systems. The staff reviewed LRA Sections 2.3.4 and 3.4 

and confirmed that the applicant’s LRA does not have any AMR results for the steam and power 

conversion system that include stainless steel piping, piping components, and piping elements 

exposed to closed-cycle cooling water greater than 60 degrees C (140 degrees F). Further, the 

staff identifies no closed-cycle cooling water environment within the steam and power 

conversion system. The staff reviewed the applicant’s UFSAR and confirmed that no in-scope 

stainless steel piping, piping components, and piping elements exposed to closed-cycle cooling 

water greater than 60 degrees C (140 degrees F) are present in the steam and power 

conversion system. Therefore, the staff finds the applicant’s determination acceptable. 

LRA Table 3.4.1, item 3.4.1.26 addresses copper alloy piping, piping components, and piping 

elements exposed to closed-cycle cooling water. The GALL Report recommends use of AMP 

XI.M21, “Closed-Cycle Cooling Water,” to manage loss of material due to pitting, crevice, and 

galvanic corrosion for this component group. The applicant stated that this item is not 

applicable because it has no in-scope copper alloy components exposed to closed-cycle cooling 

water in the condensate, blowdown, or AFW systems. The staff reviewed LRA Sections 2.3.4 

and 3.4 and confirmed that the applicant’s LRA does not have any AMR results for the steam 

and power conversion system that include copper alloy piping, piping components, and piping 

elements exposed to closed-cycle cooling water. The staff reviewed the applicant’s UFSAR and 

confirmed that no in-scope copper alloy piping, piping components, and piping elements 

exposed to closed-cycle cooling water are present in the steam and power conversion system 

and, therefore, it finds the applicant’s determination acceptable. 

LRA Table 3.4.1, item 3.4.1.27 addresses steel, stainless steel, and copper alloy heat 

exchanger tubes exposed to closed-cycle cooling water. The GALL Report recommends use of 

AMP XI.M21, “Closed-Cycle Cooling Water,” to manage reduction of heat transfer due to fouling 

for this component group. The applicant stated that this item is not applicable because it has no 

in-scope copper alloy components exposed to closed-cycle cooling water in the condensate, 

blowdown, or AFW systems. The staff reviewed LRA Sections 2.3.4 and 3.4 and confirmed that 

the applicant’s LRA does not have any AMR results for the steam and power conversion system 

that include steel, stainless steel, and copper alloy heat exchanger tubes exposed to 

closed-cycle cooling water. The staff reviewed the applicant’s UFSAR and confirmed that no 

in-scope steel, stainless steel, and copper alloy heat exchanger tubes exposed to closed-cycle 

cooling water are present in the steam and power conversion system; therefore, it finds the 

applicant’s determination acceptable. 

LRA Table 3.4.1, item 3.4.1.31 addresses steel heat exchanger components exposed to raw 

water. The GALL Report recommends use of AMP XI.M20, “Open-Cycle Cooling Water,” to 

manage loss of material due to pitting, crevice, and MIC and fouling for this component group. 

The applicant stated that this item is not applicable because it has no in-scope steel heat 

exchanger components exposed to raw water in the condensate, blowdown, or AFW systems. 

The staff reviewed LRA Sections 2.3.4 and 3.4 and confirmed that the applicant’s LRA does not 

have any AMR results for the steam and power conversion systems that include steel heat 

exchanger components exposed to raw water. The staff reviewed the applicant’s UFSAR and 

confirmed that no in-scope steel heat exchanger components exposed to raw water are present 

in the steam and power conversion systems and, therefore, it finds the applicant’s determination 

acceptable. 

LRA Table 3.4.1, item 3.4.1.32 addresses stainless steel and copper alloy piping, piping 

components, and piping elements exposed to raw water. The GALL Report recommends use of 

AMP XI.M20, “Open-Cycle Cooling Water,” to manage loss of material due to pitting, crevice 
Aging Management Review Results 

 3-278 

and MIC, for this component group. The applicant stated that this item is not applicable 

because it has no in-scope stainless steel or copper alloy components exposed to raw water in 

the steam turbine, condensate, blowdown, or AFW systems. The staff reviewed LRA 

Sections 2.3.4 and 3.4 and confirmed that the applicant’s LRA does not have any AMR results 

for the steam and power conversion systems that include stainless steel and copper alloy 

piping, piping components, and piping elements exposed to raw water. The staff reviewed the 

applicant’s UFSAR and confirmed that no in-scope stainless steel and copper alloy piping, 

piping components, and piping elements exposed to raw water are present in the steam and 

power conversion systems; therefore, it finds the applicant’s determination acceptable. 

LRA Table 3.4.1, item 3.4.1.33 addresses stainless steel heat exchanger components exposed 

to raw water. The GALL Report recommends use of AMP XI.M20, “Open-Cycle Cooling Water,” 

to manage loss of material due to pitting, crevice, and MIC and fouling for this component 

group. The applicant stated that this item is not applicable because it has no in-scope stainless 

steel heat exchanger components exposed to raw water in the condensate, blowdown, or AFW 

systems. The staff reviewed LRA Sections 2.3.4 and 3.4 and confirmed that the applicant’s 

LRA does not have any AMR results for the steam and power conversion systems that include 

stainless steel heat exchanger components exposed to raw water. The staff reviewed the 

applicant’s UFSAR and confirmed that no in-scope stainless steel heat exchanger components 

exposed to raw water are present in the steam and power conversion systems; therefore, it 

finds the applicant’s determination acceptable. 

LRA Table 3.4.1, item 3.4.1.34 addresses steel, stainless steel, and copper alloy heat 

exchanger tubes exposed to raw water. The GALL Report recommends use of AMP XI.M20, 

“Open-Cycle Cooling Water,” to manage reduction of heat transfer due to fouling for this 

component group. The applicant stated that this item is not applicable because it has no 

in-scope steel, stainless steel, and copper alloy heat exchanger tubes exposed to raw water in 

the condensate, blowdown, or AFW systems. The staff reviewed LRA Sections 2.3.4 and 3.4 

and confirmed that the applicant’s LRA does not have any AMR results for the steam and power 

conversion systems that include steel, stainless steel, and copper alloy heat exchanger tubes 

exposed to raw water. The staff reviewed the applicant’s UFSAR and confirmed that no 

in-scope steel, stainless steel, and copper alloy heat exchanger tubes exposed to raw water are 

present in the steam and power conversion systems; therefore, it finds the applicant’s 

determination acceptable. 

LRA Table 3.4.1, item 3.4.1.38 addresses steel bolting and external surfaces exposed to air with 

borated water leakage. The GALL Report recommends use of AMP XI.M10, “Boric Acid 

Corrosion,” to manage loss of material due to boric acid corrosion for this component group. 

The applicant stated that this item is not applicable because there are no in-scope steel bolting 

and external surfaces exposed to borated water leakage in the steam and power conversion 

systems. The staff reviewed LRA Sections 2.3.4 and 3.4 and confirmed that the applicant’s 

LRA does not have any AMR results in-scope steel bolting and external surfaces exposed to 

borated water leakage in the steam and power conversion systems. The staff also reviewed the 

applicant’s information in the UFSAR associated with Table 3.4.1, item 3.4.1-38 and confirmed 

that no steel bolting and external surfaces exposed to air with borated water are present in the 

in the steam and power conversion systems; therefore, it finds the applicant’s determination 

acceptable. 

LRA Table 3.4.1, item 3.4.1.42 addresses steel piping, piping components, and piping elements 

exposed to air-indoor controlled (external). The applicant stated that this item is not applicable 

because it has no in-scope steel components exposed to indoor controlled air in the steam and 

power conversion systems. The staff noted that LRA Table 3.0-1 includes air-indoor controlled 

within its definition of the plant indoor air environment. The staff reviewed LRA Sections 2.3.4 

and 3.4 and noted that there are multiple examples of carbon steel components exposed to 
Aging Management Review Results 

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plant indoor air in the steam and power conversion systems. Examples include Table 3.4.2-1, 

accumulator and piping managed for loss of material by the External Surfaces Monitoring 

Program and closure bolting managed for loss of material by the Bolting Integrity Program. The 

staff also noted that SRP-LR Table 3.4.1, item 3.4.1.42, GALL Report item SP-1, states that 

steel piping, piping components, and piping elements exposed to air-indoor controlled (external) 

have no AERM and no recommended AMP. The staff finds the applicant’s determination 

acceptable because the SRP-LR and GALL Report state that there is no AERM or 

recommended AMP for this material and environment combination, and the applicant has 

designated AMPs to manage aging for some steel components exposed to air-indoor controlled 

(external) beyond the requirements of the GALL Report. 

3.4.2.2 Aging Management Review Results Consistent with the Generic Aging Lessons 

Learned Report for Which Further Evaluation Is Recommended 

In LRA Section 3.4.2.2, the applicant further evaluates aging management, as recommended by 

the GALL Report, for the steam and power conversion systems components and provides 

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 fouling 

 reduction of heat transfer due to fouling 

 loss of material due to general, pitting, crevice, and MIC 

 cracking due to SCC 

 loss of material due to pitting and crevice corrosion 

 loss of material due to pitting, crevice, and MIC 

 loss of material due to general, pitting, crevice, and galvanic corrosion 

 QA for aging management of nonsafety-related components 

For component groups evaluated in the GALL Report, for which the applicant claimed 

consistency with the report and for which the report recommends further evaluation, the staff 

reviewed the applicant’s evaluation to determine if it adequately addressed the issues further 

evaluated. In addition, the staff reviewed the applicant’s further evaluations against the criteria 

contained in SRP-LR Section 3.4.2.2. The staff’s review of the applicant’s further evaluation 

follows. 

3.4.2.2.1 Cumulative Fatigue Damage 

In LRA Section 3.4.2.2.1, the applicant stated the evaluation of fatigue is a TLAA as defined in 

10 CFR 54.3 and is evaluated in accordance with 10 CFR 54.21(c)(1). PVNGS piping designed 

to ASME III Class 2, Class 3, and ANSI B31.1 assumes a reduction in the allowable secondary 

stress range if more than 7,000 full-range thermal cycles are expected in a design lifetime. LRA 

Section 4.3.5 describes the evaluation of these cyclic-design TLAAs. The applicant further 

stated the main steam safety valves are ASME III Class 2 components designed with a Class 1 

fatigue analysis, and LRA Section 4.3.2.12 describes the evaluation of this TLAA. 

The staff reviewed LRA Section 3.4.2.2.1 against the criteria in SRP-LR Section 3.4.2.2.1, which 

states that Fatigue is a TLAA as defined in 10 CFR 54.3. TLAAs are required to be evaluated in 

accordance with 10 CFR 54.21(c)(1). Section 4.3, “Metal Fatigue Analysis,” of this SRP-LR 

addresses this TLAA separately. The staff finds the applicant’s AMR results are consistent with 

the recommendations of the GALL Report and SRP-LR, except for in the following areas. 

The staff noted that Summary Description, in LRA Section 4.3.5, states that the implicit fatigue 

analyses discussed in the section are applicable to all ASME Code Class 2 and 3 and ANSI 

B31.1 piping, piping components, and piping elements. The staff noted that it is not clear if the 
Aging Management Review Results 

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LRA includes all corresponding AMR items for applicable ASME Code Class 2 and 3 or 

ANSI B31.1 piping, piping components, and piping elements within the scope for license 

renewal. The staff also noted that this includes those components in the ESF Systems (LRA 

Section 3.2), Auxiliary Systems (LRA Section 3.3), and the Steam and Power Conversion 

Systems (LRA Section 3.4). By letter dated July 21, 2010, the staff issued RAI 4.3-13 

requesting the applicant clarify if the LRA includes all applicable AMR items with an aging effect 

of cumulative fatigue damage for those components scoped into license renewal. If not, the 

staff asked that the applicant to justify why the LRA does not include all corresponding AMR 

items on cumulative fatigue damage for applicable ASME Code Class 2 and 3 or ANSI B31.1 

piping, piping components, and piping elements within the scope for license renewal. The 

applicant must identify all component types that are within the scope of the implicit fatigue 

analyses for ASME Code Class 2 and 3 components and B31.1 components in LRA Section 

4.3.5 and should, therefore, be within the scope of applicable component-specific AMR items on 

cumulative fatigue damage. The staff previously identified this as Open Item 4.3-1. 

In its response dated August 12, 2010, the applicant stated that for the steam and power 

conversion systems no additions are required because LRA Tables 3.4.2-1 and 3.4.2-3 include 

AMR items with an aging effect of cumulative fatigue damage. The staff reviewed LRA 

Tables 3.4.2-1 and 3.4.2-3 and confirmed that they contain applicable AMR line items 

associated with the aging effect of cumulative fatigue damage for piping, piping components 

and piping elements. 

Based on its review, the staff finds the applicant’s response to RAI 4.3-13, Part 3, related to 

LRA Section 3.4.2.2.1 acceptable because the applicant confirmed that no additional AMR 

items associated with ASME Code Class 2 and 3 or ANSI B31.1 piping, piping components, and 

piping elements were subject to aging management review per 10 CFR Part 54.21(a)(1). In 

addition, the staff confirmed that the applicant has included AMR line items associated with 

ASME Code Class 2 and 3 or ANSI B31.1 piping, piping components, and piping elements with 

an aging effect of cumulative fatigue damage in LRA Tables 3.4.2-1 and 3.4.2-3. The staff’s 

concern described in RAI 4.3-13 is resolved and this part of Open Item 4.3-1 is closed. 

Based on its review, the staff concludes that the applicant’s proposal to manage cumulative 

fatigue damage in ASME III Class 2, Class 3, and ANSI B31.1 components meets the SRP-LR 

Section 3.4.2.2.1 criteria. For those items that apply to LRA Section 3.4.2.2.1, the staff 

determines that the LRA is consistent with the GALL Report. The applicant has demonstrated 

that it will adequately manage the effects of aging so that the intended function(s) will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). SER Section 4.3 documents the staff’s review of the applicant’s evaluation 

of the TLAA for these components. 

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

The staff reviewed LRA Section 3.4.2.2.2 against the following criteria in SRP-LR 

Section 3.4.2.2.2: 

 LRA Section 3.4.2.2.2.1 refers to Table 3.4.1, items 3.4.1.3 and 3.4.1.4, and addresses 

steel piping, piping components, piping elements, and heat exchangers exposed to 

treated water and steel piping, piping components, and piping elements exposed to 

steam which are managed for the loss of material due to general, pitting, and crevice 

corrosion by the Water Chemistry and One-Time Inspection Programs. The applicant 

addressed the further evaluation criteria of the SRP-LR by stating that the above 

programs will manage the above aging effect for carbon steel and gray cast iron 

components exposed to secondary water and demineralized water. The applicant noted 

that the one-time inspection will include selected components at susceptible locations 

(e.g., stagnant flow locations) where contaminants could accumulate. 
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 The staff reviewed LRA Section 3.4.2.2.2.1 against the criteria in SRP-LR 

Section 3.4.2.2.2.1, which states that loss of material due to general, pitting, and crevice 

corrosion could occur for steel piping, piping components, piping elements, tanks, and 

heat exchangers exposed to treated water and for steel piping, piping components, and 

piping elements exposed to steam. The SRP-LR notes that monitoring and control of 

water chemistry does not preclude this aging effect in locations with stagnant flow 

conditions. It continues by stating that the applicant should verify the effectiveness of 

the Water Chemistry Control Program and that a one-time inspection at susceptible 

locations is an acceptable method. 

 SER Sections 3.0.3.2.1 and 3.0.3.1.6 document the staff’s evaluation of the applicant’s 

Water Chemistry and One-Time Inspection Programs, respectively. In its review of 

components associate with the items 3.4.1.3 and 3.4.1.4, the staff finds the applicant’s 

proposal to manage aging using the above programs acceptable because the Water 

Chemistry Program limits the concentrations of chemical species known to cause 

corrosion and adds chemical species known to inhibit degradation. In addition, the 

One-Time Inspection Program verifies the effectiveness of the Water Chemistry Program 

and evaluates aging effects, including loss of material. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.2.1 criteria. For those items that apply to LRA 

Section 3.4.2.2.2.1, the staff determines that the LRA is consistent with the GALL 

Report. In addition, the applicant has demonstrated that it will adequately manage the 

effects of aging so that the intended function(s) will be maintained consistent with the 

CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 LRA Section 3.4.2.2.2.2 refers to LRA Table 3.4.1, item 3.4.1.7 and addresses carbon 

steel piping, piping components, and piping elements exposed to lubricating oil, which 

are managed for loss of material due to general, pitting, and crevice corrosion by the 

Lubricating Oil Analysis and the One-Time Inspection Programs. The applicant 

addressed the further evaluation criteria of the SRP-LR by stating that it will include a 

one-time inspection of selected components at susceptible locations where 

contaminants, such as water, could accumulate. 

 The staff reviewed LRA Section 3.4.2.2.2.2 against the criteria in SRP-LR 

Section 3.4.2.2.2.2 which states that loss of material due to general, pitting, and crevice 

corrosion could occur for steel piping, piping components, and piping elements exposed 

to lubricating oil. SRP-LR Section 3.4.2.2.2.2 further states that the existing AMP relies 

on the periodic sampling and analysis of lubricating oil to maintain contaminants within 

acceptable limits and, therefore, preserves an environment that is not conducive to 

corrosion. Further, the applicant verifies the effectiveness of the Lubricating Oil Program 

through a one-time inspection of selected components at susceptible locations to ensure 

that corrosion is not occurring and that the component’s intended function will be 

maintained during the period of extended operation. In addition, the GALL Report 

recommends a further evaluation of programs to manage corrosion by verifying their 

effectiveness with a one-time inspection of selected components at susceptible 

locations. 

 The staff reviewed the applicant’s Lubricating Oil Analysis Program and One-Time 

Inspection Program in SER Sections 3.0.3.2.17 and 3.0.3.1.6, respectively. In its review 

of the components associated with the LRA items listed above, the staff finds the 

applicant’s proposal to manage aging effects using the Lubricating Oil Analysis and 

One-Time Inspection Programs acceptable because: (1) the Lubricating Oil Analysis 

Program provides for periodic sampling of lubricating oil to maintain contaminants at 

acceptable limits to preclude loss of material; (2) the applicant will perform one-time 
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inspections of select steel piping, piping components, and piping elements exposed to 

lubricating oil for loss of material due to general, pitting, and crevice corrosion to verify 

the effectiveness of the Lubricating Oil Analysis Program in applicable steam and power 

conversion systems, following the GALL Report recommendation that the “One Time 

Inspection” is an acceptable AMP to verify the effectiveness of the applicant’s 

Lubricating Oil Analysis Program. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.2.2 criteria. For those items that apply to LRA 

Section 3.4.2.2.2.2, the staff determines that the LRA is consistent with the GALL 

Report. Further, the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

Based on the programs identified above, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.2 criteria. For those items that apply to LRA Section 3.4.2.2.2, the staff 

determines that the LRA is consistent with the GALL Report. The staff also finds that the 

applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the 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, Crevice, and Microbiologically-Influenced 

Corrosion and Fouling 

LRA Section 3.4.2.2.3 refers to Table 3.4.1, item 3.4.1.8, and addresses the loss of material due 

to general, pitting, crevice, and MIC and fouling of steel piping, piping components, and piping 

elements exposed to raw water. The applicant indicated that these items are not applicable 

because there are no AFW system components within scope of license renewal exposed to raw 

water. The staff reviewed LRA Sections 2.3.4 and 3.4, and confirmed that the applicant’s LRA 

does not have any AMR results for the steam and power conversion systems that include steel 

piping, piping components, and piping elements exposed to raw water. The staff reviewed the 

applicant’s UFSAR and confirmed that no in-scope steel piping, piping components, and piping 

elements exposed to raw water are present in the AFW system; therefore, it finds the applicant’s 

determination acceptable. 

3.4.2.2.4 Reduction of Heat Transfer Due to Fouling 

The staff reviewed LRA Section 3.4.2.2.4 against the following criteria in SRP-LR 

Section 3.4.2.2.4: 

 LRA Section 3.4.2.2.4.1 refers to Table 3.4.1, item 3.1.4.9, and addresses the reduction 

of heat transfer due to fouling of stainless steel and copper alloy heat exchanger tubes 

exposed to treated water. The applicant stated that this item is not applicable because 

PVNGS has no in-scope stainless steel or copper alloy heat exchangers with an 

intended function of heat transfer, exposed to treated water in the condensate, SG 

blowdown, or AFW systems. The staff reviewed LRA Sections 2.3.4 and 3.4 and 

confirmed that the applicant’s LRA does not have any stainless steel or copper alloy 

heat exchanger tubes exposed to treated water in the steam and power conversion 

systems with an intended function of heat transfer. The staff also reviewed the UFSAR 

to verify the same. Based on its review of the LRA and UFSAR, the staff confirmed that 

PVNGS does not have any in-scope heat exchangers constructed of stainless steel or 

copper alloy with an intended function of heat transfer exposed to treated water in the 

steam and power conversion systems and, therefore, it finds the applicant’s 

determination acceptable. 
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 LRA Section 3.4.2.2.4.2 refers to Table 3.4.1, item 3.4.1.10, and addresses the 

reduction of heat transfer due to fouling for steel, stainless steel, or copper alloy heat 

exchanger tubes in lubricating oil. The LRA states that the Lubricating Oil Analysis 

Program and the One-Time Inspection Program will manage this aging effect. The 

applicant also stated that the one-time inspection will include selected components at 

susceptible locations where contaminants, such as water, could accumulate. 

 The staff reviewed LRA Section 3.4.2.2.4.2 against the criteria in SRP-LR 

Section 3.4.2.2.4, item 2, which states that monitoring and control of lubricating oil 

chemistry mitigates the reduction of heat transfer due to fouling, but the control of 

lubricating oil contaminants may not always have been adequate to preclude corrosion. 

It continues by stating that the effectiveness of the lubricating oil contaminant control 

should be verified and that a one-time inspection of susceptible components is an 

acceptable method to ensure that reduction of heat transfer is not occurring. 

 The staff reviewed the applicant’s Lubricating Oil Analysis and One-Time Inspection 

Programs in SER Sections 3.0.3.2.17 and 3.0.3.1.6, respectively. The staff noted that 

the applicant periodically samples lubricating oil to maintain contaminants within 

acceptable limits, which will preclude loss of heat transfer due to fouling. The staff also 

noted that the applicant will conduct one-time inspections for fouling of select stainless 

steel and copper alloy heat exchanger tubes in applicable steam and power conversion 

systems exposed to lubricating oil to verify the effectiveness of the Lubricating Oil 

Analysis Program. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.4.2 criteria. For those items that apply to LRA 

Section 3.4.2.2.4.2, the staff determines that the LRA is consistent with the GALL 

Report. The applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

Based on the programs identified above, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.4 criteria. For those items that apply to LRA Section 3.4.2.2.4, the staff 

determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB 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 

The staff reviewed LRA Section 3.4.2.2.5 against the following criteria in SRP-LR 

Section 3.4.2.2.5: 

 LRA Section 3.4.2.2.5.1 refers to Table 3.4.1, item 3.4.1.11, and addresses the loss of 

material due to general, pitting, crevice, and MIC in steel piping, piping components, 

piping elements, and tanks exposed to soil. The applicant stated that these items are 

not applicable because the condensate and AFW systems do not contain steel piping, 

piping components, piping elements, and tanks exposed to soil. The staff reviewed LRA 

Sections 2.3.4 and 3.4 and confirmed that the applicant’s LRA does not have any AMR 

results for the condensate and AFW systems that include steel piping, piping 

components, piping elements, and tanks exposed to soil. The staff reviewed the 

applicant’s UFSAR and confirmed that no in-scope steel piping, piping components, 

piping elements, and tanks exposed to soil are present in the condensate and AFW 

systems and, therefore, it finds the applicant’s determination acceptable. 
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 LRA Section 3.4.2.2.5 refers to LRA Table 3.4.1, item 3.4.1.12 and addresses steel heat 

exchanger components exposed to lubricating which are managed for loss of material 

due to general, pitting, crevice, and MIC by the Lubricating Oil Analysis and the 

One-Time Inspection Programs. The applicant addressed the further evaluation criteria 

of the SRP-LR by stating that it will include a one-time inspection of selected 

components at susceptible locations where contaminants, such as water, could 

accumulate. 

 The staff reviewed LRA Section 3.4.2.2.5.2 against the criteria in SRP-LR 

Section 3.4.2.2.5, item 2, which states that loss of material due to general, pitting, 

crevice corrosion, and MIC could occur for steel heat exchanger components exposed to 

lubricating oil. SRP-LR Section 3.4.2.2.5.2 further states that the existing AMP relies on 

the periodic sampling and analysis of lubricating oil to maintain contaminants within 

acceptable limits and, therefore, it preserves an environment that is not conducive to 

corrosion. The applicant verifies the effectiveness of the Lubricating Oil Program 

through a one-time inspection of selected components at susceptible locations to ensure 

that corrosion is not occurring and that the component’s intended function will be 

maintained during the period of extended operation. In addition, the GALL Report 

recommends a further evaluation of programs to manage corrosion by verifying their 

effectiveness with a one-time inspection of selected components at susceptible 

locations. 

 The staff reviewed the applicant’s Lubricating Oil Analysis Program and One-Time 

Inspection Program in SER Sections 3.0.3.2.17 and 3.0.3.1.6, respectively. In its review 

of the components associated with the LRA items listed above, the staff finds the 

applicant’s proposal to manage aging effects using the Lubricating Oil Analysis and 

One-Time Inspection programs acceptable because: (1) the Lubricating Oil Analysis 

Program provides for periodic sampling of lubricating oil to maintain contaminants at 

acceptable limits to preclude loss of material; (2) the applicant will conduct one-time 

inspections of select steel heat exchanger components exposed to lubricating oil for loss 

of material due to general, pitting, crevice, and MIC to verify the effectiveness of the 

Lubricating Oil Analysis Program in applicable auxiliary systems, following the GALL 

Report recommendation that the “One Time Inspection” is an acceptable AMP to verify 

the effectiveness of the applicant’s Lubricating Oil Analysis Program. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.5.2 criteria. For those items that apply to LRA 

Section 3.4.2.2.5.2, the staff determines that the LRA is consistent with the GALL Report 

and that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 LRA Table 3.4.1, item 3.4.1.2 addresses loss of material due to general, pitting, and 

crevice corrosion in steel piping, piping components, and piping elements exposed to 

steam. The applicant stated that this item is not applicable because there are no 

in-scope steel components exposed to steam in the steam turbine or extraction steam 

systems. The staff reviewed LRA Sections 2.3.4 and 3.4 as well as the UFSAR and 

confirmed that the steam turbine and extraction steam functions are not related to 

maintaining the pressure boundary, but rather to electrical signals associated with an 

anticipated transient without scram event and de-energization of the heater drain pumps 

(fire protection function). The staff notes that the applicant chose to address the 

pressure boundary function of main steam and AFW aging management by 

items 3.4.1.37 and 3.4.1.29. Item 3.4.1.37 addresses loss of material due to pitting and 

crevice corrosion in steel, stainless steel, and nickel-based alloy piping, piping 
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components, and piping elements exposed to steam by the Water Chemistry Program 

(consistent with GALL). Item 3.4.1.29 addresses FAC by the Flow-Accelerated Program 

for both the main steam and AFW systems, which will conduct general corrosion 

inspections of these lines during the period of extended operation (consistent with 

GALL). The staff finds the applicant’s determination, that AMR item 3.4.1.2 is not 

applicable, acceptable because the in-scope pressure boundary functions of main steam 

and AFW are adequately managed for aging by items 3.4.1.37 and 3.4.1.29. 

Based on the programs identified above, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.5 criteria. For those items that apply to LRA Section 3.4.2.2.5, the staff 

determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

3.4.2.2.6 Cracking Due to Stress Corrosion Cracking 

LRA Section 3.4.2.2.6 refers to LRA Table 3.4.1, item 3.4.1.14, and addresses stainless steel 

piping, piping components, piping elements, and heat exchanger components exposed to 

secondary water (internal) which are managed for cracking due to SCC by the Water Chemistry 

Program and One-Time Inspection Program. The applicant addressed the further evaluation 

criteria of the SRP-LR by stating that the Water Chemistry Program and the One-Time 

Inspection Program will manage cracking due to SCC for stainless steel components exposed 

to secondary water. The applicant stated the one-time inspection will include selected 

components at susceptible locations. 

The staff reviewed LRA Section 3.4.2.2.6 against the criteria in SRP-LR Section 3.4.2.2.6, which 

states that cracking due to SCC could occur for stainless steel piping, piping components, 

piping elements, tanks, and heat exchangers components exposed to treated water greater than 

60 degrees C (140 degrees F). The SRP-LR also indicates that cracking due to SCC could 

occur for stainless steel piping, piping components, and piping elements exposed to steam, and 

the existing management program relies on the monitoring and control of the water chemistry. 

The SRP-LR further indicates that a one-time inspection should augment the Water Chemistry 

Program to verify the absence of cracking. 

SER Sections 3.0.3.2.1 and 3.0.3.1.6 document the staff’s evaluation of the applicant’s Water 

Chemistry Program and One-Time Inspection Program, respectively. The staff noted that the 

Water Chemistry Program controls the chemical environment to ensure that the aging effects 

due to contaminants are limited by managing the primary and secondary water. The staff also 

noted that this program is effective in creating an environment that is not conducive for cracking 

to occur in areas of intermediate and high-flow where thorough mixing takes place and the 

monitoring samples are representative of actual conditions. The staff noted that the applicant’s 

One-Time Inspection Program will conduct NDE inspections of a representative group of 

components in order to provide verification of the effectiveness of the Water Chemistry Program 

in low-flow and stagnant areas. The applicant’s proposal to manage the SCC of stainless steel 

components is consistent with GALL Report, item VIII.B1-5. In its review of components 

associated with item 3.4.1.14, the staff finds the applicant’s proposal to manage aging using the 

Water Chemistry Program and One-Time Inspection Program acceptable because the Water 

Chemistry Program will create an environment that is not conducive for cracking to occur and 

the One-Time Inspection Program will verify the effectiveness of the water chemistry and the 

applicant’s use of these programs is consistent with the GALL Report. 

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.6. For those items that apply to LRA Section 3.3.2.2.6, the staff 

determines that the LRA is consistent with the GALL Report and that the applicant has 
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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 

as required by 10 CFR 54.21(a)(3). 

3.4.2.2.7 Loss of Material Due to Pitting and Crevice Corrosion 

The staff reviewed LRA Section 3.4.2.2.7 against the following criteria in SRP-LR 

Section 3.4.2.2.7: 

 LRA Section 3.4.2.2.7 refers to LRA Table 3.4.1, items 3.4.1.6, 3.4.1.15, and 3.4.1.16 

and addresses steel, stainless steel, aluminum, and copper alloy piping, piping 

components, and piping elements and stainless steel tanks and heat exchanger 

components exposed to treated water managed for loss of material due to pitting and 

crevice corrosion by the Water Chemistry Program, augmented by the One-Time 

Inspection Program. The applicant addressed the further evaluation criteria of the 

SRP-LR by stating that it will use the Water Chemistry Program and One-Time 

Inspection Program to manage loss of material for stainless steel and copper alloy 

components exposed to secondary water and demineralized water. There were no 

aluminum AMR items used, so this metal is not addressed. The applicant also stated 

that the One-Time Inspection Program will include selected components at locations 

where contaminants could accumulate, such as stagnant flow areas. 

 The staff reviewed LRA Section 3.4.2.2.7.1 against the criteria in SRP-LR 

Section 3.4.2.2.7, item 1, which states that loss of material due to pitting and crevice 

corrosion could occur for stainless steel, aluminum, and copper alloy piping, piping 

components, and piping elements, and stainless steel tanks and heat exchanger 

components exposed to treated water. The SRP-LR also states that the GALL Report 

recommends further evaluation of a plant-specific AMP. 

 In its review of components associated with item 3.4.1.15, the staff noted that in LRA 

Table 3.3.2-4, the applicant referred to this item number and GALL Report item VIII.A-5 

for copper alloy with greater than 15-percent zinc piping exposed to demineralized 

water. The staff also noted that LRA Table 3.3.2-4 is for the emergency chilled water 

system, which is a closed-cycle cooling water system, and that this component is also 

susceptible to loss of material due to selective leaching. It was unclear to the staff why 

the applicant referenced item 3.4.1.15 instead of item 3.3.1-84 and GALL Report item 

VII.C2-7, which recommends the Selective Leaching of Materials Program to manage 

loss of material due to selective leaching for these components exposed to treated 

water. The staff issued RAI 3.3.2-1 requesting that the applicant clarify how the Water 

Chemistry and One-Time Inspection Programs will be used to manage loss of material 

due to selective leaching. 

 In its response, dated March 1, 2010, the applicant stated that the copper alloy with 

greater than 15-percent zinc components exposed to demineralized water are used to 

provide make-up water to the chilled water system. The applicant further stated that the 

components are susceptible to loss of material due to selective leaching and that LRA 

item 3.3.1.84 and GALL Report item VII.C2-7 are referenced in another AMR result for 

the same components and managed by the Selective Leaching of Materials Program. 

The staff finds the applicant’s response acceptable because the components are being 

appropriately managed for loss of material due to selective leaching. 

 SER Sections 3.0.3.2.1 and 3.0.3.1.6 document the staff’s evaluation of the applicant’s 

Water Chemistry and One-Time Inspection Programs, respectively. The staff finds the 

applicant’s use of the Water Chemistry and One-Time Inspection Programs acceptable 

because the Water Chemistry Program monitors and controls the concentration of 

contaminants in the water in order to minimize corrosion, and the One-Time Inspection 
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Program conducts inspections to verify the effectiveness of the Water Chemistry 

Program. 

 The staff concludes that the applicant’s programs meet SRP-LR Section 3.4.2.2.7, 

item 1 criteria. For those items that apply to LRA Section 3.4.2.2.7, item 1, the staff 

determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

 LRA Section 3.4.2.2.7 refers to Table 3.4.1, item 3.4.1.17, and addresses the loss of 

material due to pitting and crevice corrosion in stainless steel piping, piping components, 

and piping elements exposed to soil. The applicant stated that this item is not applicable 

because the condensate and AFW systems do not contain stainless steel piping, piping 

components, and piping elements exposed to soil. The staff reviewed LRA 

Sections 2.3.4 and 3.4 and confirmed that the applicant’s LRA does not have any AMR 

results for the condensate and AFW systems that include stainless steel piping, piping 

components, and piping elements exposed to soil. The staff reviewed the applicant’s 

UFSAR and confirmed that no in-scope stainless steel piping, piping components, and 

piping elements exposed to soil are present in the condensate and AFW systems and, 

therefore, finds the applicant’s determination acceptable. 

 LRA Section 3.4.2.2.7 refers to LRA Table 3.4.1, item 3.4.1.18 and addresses loss of 

material due to pitting and crevice corrosion of copper alloy piping, piping components, 

and elements exposed to lubricating oil. The GALL Report recommends use of 

AMPs XI.M39, “Lubricating Oil Analysis,” and XI.M32, “One-Time Inspection,” to manage 

loss of material due to pitting and crevice corrosion for this component group. The 

applicant stated that this item is not applicable because “PVNGS has no in-scope copper 

alloy components exposed to lube oil in the steam turbine, feedwater, condensate, or 

AFW systems, so the applicable GALL Report items were not used.” The staff reviewed 

LRA Sections 2.3.4 and 3.4 and confirmed that the applicant’s LRA does not have any 

AMR results for the referenced hardware and systems that include copper alloy 

components exposed to lube oil. The staff also reviewed the UFSAR to verify the same. 

Based on its review of the LRA and UFSAR, the staff confirmed that the applicant’s plant 

does not have any in-scope copper alloy piping and components exposed to lubricating 

oil in the referenced steam and power conversion systems and components, and 

therefore, it finds the applicant’s determination acceptable. 

Based on the programs identified above, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.7 criteria. For those items that apply to LRA Section 3.4.2.2.7, the staff 

determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

3.4.2.2.8 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion 

LRA Section 3.4.2.2.8 refers to LRA Table 3.4.1, item 3.4.1.19 and addresses stainless steel 

piping, piping components, piping elements, and heat exchanger components exposed to 

lubricating oil. The GALL Report recommends use of AMPs XI.M39, “Lubricating Oil Analysis,” 

and XI.M32, “One-Time Inspection,” to manage for loss of material due to pitting, crevice, and 

MIC for this component group. The applicant stated that this item is not applicable because 

“PVNGS has no in-scope stainless steel components exposed to lube oil in the steam turbine, 

feedwater, condensate, or AFW systems, so the applicable GALL Report items were not used.” 

The staff reviewed LRA Sections 2.3.4 and 3.4 and confirmed that the applicant’s LRA does not 
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have any AMR results for the referenced hardware that include stainless steel piping, piping 

components, piping elements, and heat exchanger components exposed to lubricating oil. The 

staff also reviewed the UFSAR to verify the same. Based on its review of the LRA and UFSAR, 

the staff confirmed that the applicant’s plant does not have any in-scope stainless steel piping, 

piping components, piping elements, and heat exchanger components exposed to lubricating oil 

in the referenced steam and power conversion SCs, and therefore, it finds the applicant’s 

determination acceptable. 

3.4.2.2.9 Loss of Material Due to General, Pitting, Crevice, and Galvanic Corrosion 

LRA Section 3.4.2.2.9 addresses the loss of material due to general, pitting, crevice, and 

galvanic corrosion for steel heat exchanger components exposed to treated water. The only 

Table 3.4-1 item is item 3.4.1.5, which is addressed in SER Section 3.4.2.1.1. 

3.4.2.2.10 Quality Assurance for Aging Management of Nonsafety-Related Components 

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA program. 

3.4.2.3 Aging Management Review Results Not Consistent with or Not Addressed in 

the Generical Aging Lessons Learned Report 

In LRA Tables 3.4.2-1 through 3.4.2-3, the staff reviewed additional details of the AMR results 

for material, environment, AERM, and AMP combinations not consistent with or not addressed 

in the GALL Report. 

In LRA Tables 3.4.2-1 through 3.4.2-3, via Notes F–J, the applicant indicated that combinations 

of component type, material, environment, and AERM do not correspond to an item in the GALL 

Report. The applicant provided further information about how it will manage the aging effects. 

Specifically, Note F indicates that the material for the AMR item component is not evaluated in 

the GALL Report. Note G indicates that the environment for the AMR item component and 

material is not evaluated in the GALL Report. Note H indicates that the aging effect for the AMR 

item component, material, and environment combination is not evaluated in the GALL Report. 

Note I indicates that the aging effect identified in the GALL Report for the item component, 

material, and environment combination is not applicable. Note J indicates that neither the 

component nor the material and environment combination for the item is evaluated in the GALL 

Report. 

For component type, material, and environment combinations not evaluated in the GALL 

Report, the staff reviewed the applicant’s evaluation to determine if the applicant has 

demonstrated that it will adequately manage the effects of aging so that the intended function(s) 

will be maintained consistent with the CLB for the period of extended operation. The following 

sections document the staff’s evaluation. 

3.4.2.3.1 Main Steam System—Summary of Aging Management Review—License Renewal 

Application 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 Tables 3.3.2-4, 3.3.2-10, 3.3.2.-21, 3.4.2-1, and 3.4.2-3, the applicant stated that 

calcium silicate and mineral wool insulation exposed to borated water leakage have no AERM 

and no proposed AMP. The AMR items cite generic Note J. SER Section 3.3.2.3.4 documents 

the staff’s review. 

In LRA Tables 3.4.2-1, 3.4.2-2, and 3.4.2-3, the applicant stated that stainless steel closure 

bolting exposed to plant indoor air and carbon steel closure bolting exposed to atmosphere or 

weather are managed for loss of preload by the Bolting Integrity Program. The AMR items cite 

generic Note G, indicating that the environment is not in the GALL Report for this component 
Aging Management Review Results 

 3-289 

and material. The AMR items also cite plant-specific note 1, indicating that loss of preload is 

considered to be applicable for all closure bolting. 

SER Section 3.0.3.2.3 documents the staff’s evaluation of the applicant’s Bolting Integrity 

Program. The staff noted that the mechanisms identified in the GALL Report as causing loss of 

preload in carbon steel bolts are thermal effects, gasket creep, and self-loosening, which are not 

all dependent on the bolting material or environment. The staff also noted that activities in the 

Bolting Integrity Program that control and manage loss of preload are effective for various 

bolting materials. The staff further noted that the GALL Report, item VIII.H-5 (S-33) 

recommends using the Bolting Integrity Program to manage the aging effect of loss of preload in 

carbon steel bolts exposed to air-indoor uncontrolled. Because the GALL Report recommends 

the Bolting Integrity Program for managing loss of preload in carbon steel bolting exposed to 

air-indoor uncontrolled, and the Bolting Integrity Program’s activities for managing loss of 

preload are applicable for other bolting materials and environments, the staff finds the 

applicant’s use of the Bolting Integrity Program to manage loss of preload in stainless steel 

closure bolting exposed to plant indoor air and in carbon steel bolting exposed to atmosphere or 

weather to be acceptable. 

In LRA Table 3.4.2-1, the applicant stated that, for nickel-alloy flexible hoses exposed internally 

to dry gas, there is no aging effect and no proposed AMP. The AMR items cite generic Note G. 

The staff reviewed the associated items in the LRA and confirmed that no aging effect is 

applicable for this component, material, and environment because austenitic materials such as 

nickel alloys are not subject to loss of material or cracking when exposed to this environment, 

and these materials are used as corrosion-resistant replacement materials where other 

materials have degraded. The staff noted that corrosion-resistant materials, such as austenitic 

and martensitic stainless steels and high-strength nickel-based alloys, offer good protection 

against loss of material. The staff also noted that the conditions required for cracking due to a 

variety of mechanisms (SCC, PWSCC, IASCC and IGSCC) to occur, such as being exposed to 

an aqueous solution (reactor coolant or other corrosive solutions) and high temperatures, do not 

exist on the surfaces of these components when exposed to dry gas. The staff noted that 

GALL, AMR item IV.E-1 states that nickel alloy exposed to air-indoor uncontrolled is not subject 

to an AERM. The staff noted that an air-indoor uncontrolled environment is more aggressive 

than a dry gas environment because it is possible for condensation to occur in an air-indoor 

uncontrolled environment. The staff finds the applicant’s determination acceptable because 

nickel alloy is a highly corrosion-resistant material, it is not subject to conditions where cracking 

is possible, and it is exposed to a less aggressive environment when compared to GALL AMR 

item IV.E-1, for which there is no AERM. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.4.2.3.2 Condensate Storage and Transfer System—Summary of Aging Management 

Review—License Renewal Application Table 3.4.2-2 

The staff reviewed LRA Table 3.4.2-2, which summarizes the results of AMR evaluations for the 

condensate storage and transfer system component groups. 

SER Section 3.4.2.3.1 documents the staff’s evaluation for stainless steel closure bolting 

exposed to plant indoor air and carbon steel closure bolting exposed to atmosphere or weather 

managed for loss of preload by the Bolting Integrity Program, citing generic Note G. 
Aging Management Review Results 

 3-290 

SER Section 3.3.2.3.7 documents the staff’s evaluation for stainless steel components exposed 

to atmosphere or weather conditions, where there are no AERM and no AMP, citing generic 

Note G. 

In LRA Table 3.4.2-2, the applicant stated that the Boiling Integrity Program manages stainless 

steel closure bolting, exposed to atmosphere or weather, for loss of preload. The AMR items 

cite generic Note G, indicating that the environment is not in the GALL Report for this 

component and material. The AMR items also cite plant-specific note 1, indicating that loss of 

preload is considered to be applicable for all closure bolting. The staff reviewed all AMR results 

in the GALL Report where the aging effect is loss of preload and confirmed there are no AMR 

results for stainless steel bolting where the environment is atmosphere or weather. 

SER Section 3.0.3.2.3 documents the staff’s evaluation of the applicant’s Bolting Integrity 

Program. The staff noted that the mechanisms identified in the GALL Report as causing loss of 

preload in carbon steel bolts are thermal effects, gasket creep, and self-loosening, which are not 

all dependent on the bolting material or environment. The staff also noted that activities in the 

Bolting Integrity Program that control and manage loss of preload are effective for various 

bolting materials. The staff further noted that the GALL Report item VIII.H-5 recommends using 

the Bolting Integrity Program to manage the aging effect of loss of preload in carbon steel bolts 

exposed to air-indoor uncontrolled. Since the GALL Report recommends the Bolting Integrity 

Program for managing loss of preload in carbon steel bolting exposed to uncontrolled indoor air, 

and the Bolting Integrity Program’s activities for managing loss of preload are applicable for 

other bolting materials and environments, the staff finds the applicant’s use of the Bolting 

Integrity Program to manage loss of preload in stainless steel closure bolting exposed to 

atmosphere or weather to be acceptable. 

In LRA Table 3.4.2-2, the applicant stated that stainless steel valves exposed externally to 

atmosphere or weather have no AERM, and it will not implement an AMP for these components. 

The AMR items cite generic Note G, indicating that the environment is not in the GALL Report 

for this component and material combination. 

The staff reviewed all AMR result lines in the GALL Report for this material and environment 

combination and noted that the GALL Report recommends that stainless steel components 

exposed to indoor uncontrolled air or air with borated water leakage have no AERM. The staff 

also noted that the climate at this location is dry and arid with high average temperatures (68 to 

108 degrees F) throughout the year and low average rainfall (8 to 10 inches per year), making 

the aging effects of the atmosphere or weather at this location similar to those of indoor 

uncontrolled air. The staff finds the applicant’s determination that no AMP is required 

acceptable because stainless steel components exposed to the atmosphere or weather would 

not be expected to experience an aging effect at this location. 

The staff finds that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function will be maintained consistent with the CLB for the period 

of extended operation, as required by 10 CFR 54.21(a)(3). 

3.4.2.3.3 Auxiliary Feedwater System—Summary of Aging Management Review—License 

Renewal Application Table 3.4.2-3 

The staff reviewed LRA Table 3.4.2-3, which summarizes the results of AMR evaluations for the 

AFW system component groups. 

In LRA Tables 3.3.2-4, 3.3.2-10, 3.3.2.-21, 3.4.2-1, and 3.4.2-3, the applicant stated that 

calcium silicate and mineral wool insulation exposed to borated water leakage have no AERM 

and no proposed AMP. The AMR items cite generic Note J. SER Section 3.3.2.3.4 documents 

the staff’s review. 
Aging Management Review Results 

 3-291 

In LRA Table 3.4.2-3, the applicant stated that the Water Chemistry and One-Time Inspection 

Programs manage the carbon steel AFW turbine oil cooler heat exchanger, exposed to 

secondary water, for reduction of heat transfer. The AMR item cites generic Note G, indicating 

that for the item, the environment is not in the GALL Report for this component and material. 

SER Sections 3.0.3.2.1 and 3.0.3.1.6 document the staff’s evaluation of the applicant’s Water 

Chemistry and a One-Time Inspection Programs, respectively. 

The staff finds the applicant’s proposal to manage aging using the Water Chemistry and 

One-Time Inspection Programs acceptable because the Water Chemistry Program will minimize 

the potential development and progress of heat exchanger fouling, and the One-Time Inspection 

Program will verify the effectiveness of the Water Chemistry Program using inspections with 

specific attributes related to the reduction of heat transfer. 

SER Section 3.4.2.3.1 documents the staff’s evaluation for stainless steel closure bolting 

exposed to plant indoor air and carbon steel closure bolting, exposed to atmosphere or weather, 

managed for loss of preload by the Bolting Integrity Program, citing generic Note G. 

SER Section 3.3.2.3.2.1 documents the staff’s evaluation for aluminum heat exchanger 

(governor oil cooler), valve, and filter exposed to lubricating oil and managed for loss of material 

by the Lubricating Oil Analysis and One-Time Inspection Programs with generic Note G. 

3.4.3 Conclusion 

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the steam and power conversion systems components 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). 

3.5 Aging Management of Structures and Component Supports

This section of the SER documents the staff’s review of the applicant’s AMR results for the SC 

supports of the following components: 

 containment building 

 control building 

 diesel generator building 

 turbine building 

 auxiliary building 

 radwaste building 

 main steam support structure 

 SBO generator structures 

 fuel building 

 spray pond and associated water control structures 

 tank foundations and shells 

 transformer foundations and electrical structures 

 yard structures (in-scope) 

 supports 

3.5.1 Summary of Technical Information in the Application 

LRA Section 3.5 provides AMR results for the SC supports groups. LRA Table 3.5-1, “Summary 

of Aging Management Evaluations in Chapters II and III of NUREG-1801 for Containments, 
Aging Management Review Results 

 3-292 

Structures, and Component Supports,” is a summary comparison of the applicant’s AMRs with 

those evaluated in the GALL Report for the SC supports groups. 

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry 

operating experience in the determination of AERMs. The plant-specific evaluation included 

Condition Reports and discussions with appropriate site personnel to identify AERMs. The 

applicant’s review of industry operating experience included a review of the GALL Report and 

operating experience issues identified since the issuance of the GALL Report. 

3.5.2 Staff Evaluation 

The staff reviewed LRA Section 3.5 to determine if the applicant provided sufficient information 

to demonstrate that the effects of aging for the SC supports 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 reviewed AMRs to confirm the applicant’s claim that certain 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 identified the appropriate GALL Report AMPs. SER Section 3.0.3 documents 

the staff’s evaluations of the AMPs, and SER Section 3.5.2.1 provides details of the staff’s 

evaluation. 

The staff also reviewed AMRs 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 SRP-LR Section 3.5.2.2 acceptance criteria. SER Section 3.5.2.2 documents the 

staff’s evaluations. 

The staff also conducted a technical review of the remaining AMRs not consistent with, or not 

addressed in, the GALL Report.5.2.3. 

For SSCs that the applicant claimed were not applicable or required no aging management, the 

staff reviewed the AMR items and the plant’s operating experience to verify the applicant’s 

claims. 

Table 3.5-1 summarizes the staff’s evaluation of components, aging effects or mechanisms, and 

AMPs listed in LRA Section 3.5 and addressed in the GALL Report. 
Aging Management Review Results 

 3-293 

Table 3.5-1. Staff Evaluation for Structures and Component Supports Components 

in the GALL Report 

Component Group 

(GALL Report 

Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

PWR Concrete (Reinforced and Prestressed) and Steel Containments 

Concrete elements: 

walls, dome, basemat, 

ring girder, buttresses, 

containment (as 

applicable) 

(3.5.1-1) 

Aging of accessible 

and inaccessible 

concrete areas due 

to aggressive 

chemical attack, and 

corrosion of 

embedded steel 

ISI (IWL) and for 

inaccessible 

concrete, an 

examination of 

representative 

samples of belowgrade concrete, and 

periodic monitoring 

of groundwater if 

environment is nonaggressive. A plantspecific program is 

to be evaluated if 

environment is 

aggressive. 

Yes, plant 

specific, if 

environment 

aggressive 

ISI (IWL) Consistent 

with GALL 

Report. See 

SER Section 

3.5.2.2.1(1). 

Concrete elements; All 

(3.5.1-2) 

Cracks and 

distortion due to 

increased stress 

levels from 

settlement 

Structures 

Monitoring Program. 

If a de-watering 

system is relied 

upon for control of 

settlement, then the 

licensee is to ensure 

proper functioning of 

the de-watering 

system through the 

period of extended 

operation 

Yes, if not 

within the 

scope of the 

applicant’s 

Structures 

Monitoring 

Program or 

a dewatering 

system is 

relied upon. 

Structures 

Monitoring 

Program 

Consistent 

with GALL 

Report. See 

SER Section 

3.5.2.2.1(2). 

Concrete elements: 

foundation, subfoundation 

(3.5.1-3) 

Reduction in 

foundation strength, 

cracking, differential 

settlement due to 

erosion of porous 

concrete 

subfoundation 

Structures 

Monitoring Program. 

If a de-watering 

system is relied 

upon to control 

erosion of cement 

from porous 

concrete 

subfoundations, then 

the licensee is to 

ensure proper 

functioning of the dewatering system 

through the period of 

extended operation 

Yes, if not 

within the 

scope of the 

applicant’s 

Structures 

Monitoring 

Program or 

a dewatering 

system is 

relied upon. 

Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.5.2.2.1(2). 

Concrete elements: 

dome, wall, basemat, 

ring girder, buttresses, 

containment, concrete 

fill-in annulus (as 

applicable) 

(3.5.1-4) 

Reduction of 

strength and 

modulus of concrete 

due to elevated 

temperature 

A plant-specific AMP

is to be evaluated. 

Yes, plantspecific if 

temperature 

limits are 

exceeded. 

Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.5.2.2.1(3). 
Aging Management Review Results 

 3-294 

Component Group 

(GALL Report 

Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Steel elements: 

drywell; torus; drywell 

head; embedded shell 

and sand pocket 

regions; drywell support 

skirt; torus ring girder; 

downcomers; liner 

plate, ECCS suction 

header, support skirt, 

region shielded by 

diaphragm floor, 

suppression chamber 

(as applicable) 

(3.5.1-5) 

Loss of material due 

to general, pitting 

and crevice 

corrosion 

ISI (IWE) and

10 CFR Part 50, 

Appendix J 

Yes, if 

corrosion is 

significant 

for 

inaccessible 

areas 

Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.5.2.1.1. 

Steel elements: steel 

liner, liner anchors, 

integral attachments 

(3.5.1-6) 

Loss of material due 

to general, pitting 

and crevice 

corrosion 

ISI (IWE) and

10 CFR Part 50, 

Appendix J 

Yes, if 

corrosion is 

significant 

for 

inaccessible 

areas 

ISI (IWE), and 

10 CFR 50, 

Appendix J 

Consistent 

with GALL 

Report. See 

SER Section 

3.5.2.2.1(4). 

Prestressed 

containment tendons 

(3.5.1-7) 

Loss of prestress 

due to relaxation, 

shrinkage, creep, 

and elevated 

temperature 

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c) 

Yes, TLAA. TLAA Consistent 

with GALL 

Report. See 

SER Section 

3.5.2.2.1(5). 

Steel and stainless 

steel elements: vent 

line, vent header, vent 

line bellows; 

downcomers 

(3.5.1-8) 

Cumulative fatigue 

damage (CLB 

fatigue analysis 

exists) 

TLAA evaluated in 

accordance with 

10 CFR 54.21(c) 

Yes, TLAA Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.5.2.1.1. 

Steel, stainless steel 

elements, dissimilar 

metal welds: 

penetration sleeves, 

penetration bellows; 

suppression pool shell, 

unbraced downcomers 

(3.5.1-9) 

Cumulative fatigue 

damage (CLB 

fatigue analysis 

exists) 

TLAA evaluated in 

accordance with 

10 CFR 54.21(c) 

Yes, TLAA TLAA Consistent 

with GALL 

Report. See 

SER Section 

3.5.2.2.1(6). 

Stainless steel 

penetration sleeves, 

penetration bellows, 

dissimilar metal welds 

(3.5.1-10) 

Cracking due to 

SCC 

ISI (IWE) and 

10 CFR Part 50, 

Appendix J and 

additional 

appropriate 

examinations & 

evaluations for 

bellows assemblies 

and dissimilar metal 

welds 

Yes, 

detection of 

aging is to 

be evaluated

Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.5.2.2.1(7). 
Aging Management Review Results 

 3-295 

Component Group 

(GALL Report 

Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Stainless steel vent line 

bellows 

(3.5.1-11) 

Cracking due to 

SCC 

ISI (IWE) and 

10 CFR Part 50, 

Appendix J and 

additional 

appropriate 

examinations & 

evaluations for 

bellows assemblies 

and dissimilar metal 

welds 

Yes, 

detection of 

aging is to 

be evaluated

Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.5.2.1.1. 

Steel, stainless steel 

elements, dissimilar 

metal welds: 

penetration sleeves, 

penetration bellows; 

suppression pool shell, 

unbraced downcomers 

(3.5.1-12) 

Cracking due to 

cyclic loading 

ISI (IWE) and 

10 CFR Part 50, 

Appendix J 

supplemented to 

detect fine cracks 

Yes, 

detection of 

aging is to 

be evaluated

TLAA GALL Report 

items not 

used. 

Evaluated as 

a TLAA. See 

SER Sections 

3.5.2.2.1(8) 

and 4.6. 

Steel, stainless steel 

elements, dissimilar 

metal welds: torus; 

vent line; vent header; 

vent line bellows; 

downcomers 

(3.5.1-13) 

Cracking due to 

cyclic loading 

ISI (IWE) and 

10 CFR Part 50, 

Appendix J 

supplemented to 

detect fine cracks 

Yes, 

detection of 

aging is to 

be evaluated

Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.5.2.1.1. 

Concrete elements: 

dome, wall, basemat 

ring girder, buttresses, 

containment (as 

applicable) 

(3.5.1-14) 

Loss of material 

(scaling, cracking, 

and spalling) due to 

freeze-thaw 

ISI (IWL). 

Evaluation is needed 

for plants that are 

located in moderate 

to severe weathering 

conditions 

(weathering index > 

100 day-inch/yr) 

(NUREG-1557) 

Yes, for 

inaccessible 

areas of 

plants 

located in 

moderate to 

severe 

weathering 

conditions 

ISI (IWL) Consistent 

with GALL 

Report. See 

SER Section 

3.5.2.2.1(9). 

Concrete elements: 

walls, dome, basemat, 

ring girder, buttresses, 

containment, concrete 

fill-in annulus (as 

applicable) 

(3.5.1-15) 

Cracking due to 

expansion and 

reaction with 

aggregate; increase 

in porosity, 

permeability due to 

leaching of calcium 

hydroxide 

ISI (IWL) for 

accessible areas. 

None for 

inaccessible areas if 

concrete was 

constructed in 

accordance with the 

recommendations in 

ACI 201.2R 

Yes, if 

concrete 

was not 

constructed 

as stated in 

inaccessible 

areas. 

ISI (IWL) Consistent 

with GALL 

Report. See 

SER Section 

3.5.2.2.1(10). 

Seals, gaskets, and 

moisture barriers 

(3.5.1-16) 

Loss of sealing and 

leakage through 

containment due to 

deterioration of joint 

seals, gaskets, and 

moisture barriers 

(caulking, flashing, 

and other sealants) 

ISI (IWE) and 

10 CFR Part 50, 

Appendix J 

No ISI (IWE), and 

10 CFR 50, 

Appendix J 

Consistent 

with GALL 

Report. 
Aging Management Review Results 

 3-296 

Component Group 

(GALL Report 

Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Personnel airlock, 

equipment hatch and 

CRD hatch locks, 

hinges, and closure 

mechanisms 

(3.5.1-17) 

Loss of leak 

tightness in closed 

position due to 

mechanical wear of 

locks, hinges and 

closure mechanisms 

10 CFR Part 50, 

Appendix J and 

Plant TS 

No 10 CFR 50, 

Appendix J 

and Plant TS 

Consistent 

with GALL 

Report. 

Steel penetration 

sleeves and dissimilar 

metal welds; personnel 

airlock, equipment 

hatch and CRD hatch 

(3.5.1-18) 

Loss of material due 

to general, pitting, 

and crevice 

corrosion 

ISI (IWE) and 

10 CFR Part 50, 

Appendix J 

No ISI (IWE), and 

10 CFR 50, 

Appendix J 

Consistent 

with GALL 

Report. 

Steel elements: 

stainless steel 

suppression chamber 

shell (inner surface) 

(3.5.1-19) 

Cracking due to 

SCC 

ISI (IWE) and 

10 CFR Part 50, 

Appendix J 

No Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.5.2.1.1. 

Steel elements: 

suppression chamber 

liner (inner surface) 

(3.5.1-20) 

Loss of material due 

to general. pitting, 

and crevice 

corrosion 

ISI (IWE) and 

10 CFR Part 50, 

Appendix J 

No Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.5.2.1.1. 

Steel elements: drywell 

head and downcomer 

pipes 

(3.5.1-21) 

Fretting or lock up 

due to mechanical 

wear 

ISI (IWE) No Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.5.2.1.1. 

Prestressed 

containment: tendons 

and anchorage 

components 

(3.5.1-22) 

Loss of material due 

to corrosion 

ISI (IWL) No ISI (IWL) Consistent 

with GALL 

Report. 

Safety-Related and Other Structures and Component Supports 

All Groups except 

Group 6: interior and 

above grade exterior 

concrete 

(3.5.1-23) 

Cracking, loss of 

bond, and loss of 

material (spalling, 

scaling) due to 

corrosion of 

embedded steel 

Structures 

Monitoring Program 

Yes, if not 

within scope 

of the 

applicant’s 

structures 

monitoring 

program 

Structures 

Monitoring 

Program 

Consistent 

with GALL 

Report. See 

SER Section 

3.5.2.2.2(1). 

All Groups except 

Group 6: interior and 

above grade exterior 

concrete 

(3.5.1-24) 

Increase in porosity 

and permeability, 

cracking, loss of 

material (spalling, 

scaling) due to 

aggressive chemical 

attack 

Structures 

Monitoring Program 

Yes, if not 

within scope 

of the 

applicant’s 

structures 

monitoring 

program 

Structures 

Monitoring 

Program 

Consistent 

with GALL 

Report. See 

SER Section 

3.5.2.2.2(1). 
Aging Management Review Results 

 3-297 

Component Group 

(GALL Report 

Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

All Groups except 

Group 6: steel 

components: all 

structural steel 

(3.5.1-25) 

Loss of material due 

to corrosion 

Structures 

Monitoring Program. 

If protective coatings 

are relied upon to 

manage the effects 

of aging, the 

structures monitoring 

program is to include 

provisions to 

address protective 

coating monitoring 

and maintenance 

Yes, if not 

within the 

scope of the 

applicant’s 

Structures 

Monitoring 

Program 

Structures 

Monitoring 

Program 

Consistent 

with GALL 

Report. See 

SER Section 

3.5.2.2.2(1). 

All Groups except 

Group 6: accessible 

and inaccessible 

concrete: foundation 

(3.5.1-26) 

Loss of material 

(spalling, scaling) 

and cracking due to 

freeze-thaw 

Structures 

Monitoring Program. 

Evaluation is needed 

for plants that are 

located in moderate 

to severe weathering 

conditions 

(weathering index 

> 100 day-inch/yr) 

(NUREG-1557) 

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or 

for 

inaccessible 

areas of 

plants 

located in 

moderate to 

severe 

weathering 

conditions 

Structures 

Monitoring 

Program 

Consistent 

with GALL 

Report. See 

SER Section 

3.5.2.2.2(1). 

All Groups except 

Group 6: accessible 

and inaccessible 

interior/exterior 

concrete 

(3.5.1-27) 

Cracking due to 

expansion due to 

reaction with 

aggregates 

Structures 

Monitoring Program. 

None for 

inaccessible areas if 

concrete was 

constructed in 

accordance with the 

recommendations in 

ACI 201.2R-77 

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or 

concrete 

was not 

constructed 

as stated for 

inaccessible 

areas. 

Structures 

Monitoring 

Program 

Consistent 

with GALL 

Report. See 

SER Section 

3.5.2.2.2(1). 

Groups 1-3, 5-9: All 

(3.5.1-28) 

Cracks and 

distortion due to 

increased stress 

levels from 

settlement 

Structures 

Monitoring Program. 

If a de-watering 

system is relied 

upon for control of 

settlement, then the 

licensee is to ensure 

proper functioning of 

the de-watering 

system through the 

period of extended 

operation 

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering 

system is 

relied upon. 

Structures 

Monitoring 

Program 

Consistent 

with GALL 

Report. See 

SER Section 

3.5.2.2.2(1). 
Aging Management Review Results 

 3-298 

Component Group 

(GALL Report 

Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Groups 1-3, 5-9: 

foundation 

(3.5.1-29) 

Reduction in 

foundation strength, 

cracking, differential 

settlement due to 

erosion of porous 

concrete 

subfoundation 

Structures 

Monitoring Program. 

If a de-watering 

system is relied 

upon for control of 

settlement, then the 

licensee is to ensure 

proper functioning of 

the de-watering 

system through the 

period of extended 

operation 

Yes, if not 

within the 

scope of the 

applicant’s 

Structures 

Monitoring 

Program. 

Structures 

Monitoring 

Program 

Not applicable 

to PVNGS. 

See SER 

Section 

3.5.2.2.2(1). 

Group 4: Radial beam 

seats in BWR drywell; 

RPV support shoes for 

PWR with nozzle 

supports; SG supports 

(3.5.1-30) 

Lock-up due to wear ISI (IWF) or 

Structures 

Monitoring Program 

Yes, if not 

within the 

scope of the 

ISI or 

structures 

monitoring 

Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.5.2.2.2(1). 

Groups 1-3, 5, 7-9: 

below-grade concrete 

components, such as 

exterior walls below 

grade and foundation 

(3.5.1-31) 

Increase in porosity 

and permeability, 

cracking, loss of 

material (spalling, 

scaling), aggressive 

chemical attack; 

cracking, loss of 

bond, and loss of 

material (spalling, 

scaling), corrosion of 

embedded steel 

Structures 

Monitoring Program. 

Examination of 

representative 

samples of belowgrade concrete, and 

periodic monitoring 

of groundwater, if 

the environment is 

non-aggressive. A 

plant-specific 

program is to be 

evaluated if 

environment is 

aggressive. 

Yes, plantspecific, If 

environment 

is 

aggressive 

Structures 

Monitoring 

Program 

Consistent 

with GALL 

Report. See 

SER Section 

3.5.2.2.2(2). 

Groups 1-3, 5, 7-9: 

exterior above and 

below grade reinforced 

concrete foundations 

(3.5.1-32) 

Increase in porosity 

and permeability, 

and loss of strength 

due to leaching of 

calcium hydroxide 

Structures 

Monitoring Program 

for accessible areas. 

None for 

inaccessible areas if 

concrete was 

constructed in 

accordance with the 

recommendations in 

ACI 201.2R-77 

Yes, if 

concrete 

was not 

constructed 

as stated for 

inaccessible 

areas 

Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.5.2.2.2(2). 

Groups 1-5: concrete 

(3.5.1-33) 

Reduction of 

strength and 

modulus due to 

elevated 

temperature 

Plant-specific Yes, plantspecific if 

temperature 

limits are 

exceeded 

Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.5.2.2.2(3). 
Aging Management Review Results 

 3-299 

Component Group 

(GALL Report 

Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Group 6: concrete; all 

(3.5.1-34) 

Increase in porosity 

and permeability, 

cracking, loss of 

material due to 

aggressive chemical 

attack; cracking, loss 

of bond, loss of 

material due to 

corrosion of 

embedded steel. 

Inspection of WaterControl Structures or 

FERC/U.S. Army 

Corps of Engineers 

dam inspections and 

maintenance 

programs and for 

inaccessible 

concrete, an 

examination of 

representative 

samples of belowgrade concrete, and 

periodic monitoring 

of groundwater, if 

the environment is 

non-aggressive. A 

plant-specific 

program is to be 

evaluated if 

environment is 

aggressive 

Yes. Plantspecific if 

environment 

is 

aggressive 

Inspection of 

Water-Control 

Structures 

Consistent 

with GALL 

Report. See 

SER Section 

3.5.2.2.2(4). 

Group 6: exterior 

above and below grade 

concrete foundation 

(3.5.1-35) 

Loss of material 

(spalling, scaling) 

and cracking due to 

freeze-thaw 

Inspection of WaterControl Structures or 

FERC/U.S. Army 

Corps of Engineers 

dam inspections and 

maintenance 

programs. 

Evaluation is needed 

for plants that are 

located in moderate 

to severe weathering 

conditions 

(weathering index 

> 100 day-inch/yr) 

(NUREG-1557) 

Yes, for 

inaccessible 

areas of 

plants 

located in 

moderate to 

severe 

weathering 

conditions. 

Inspection of 

water-control 

Structures 

Consistent 

with GALL 

Report. See 

SER Section 

3.5.2.2.2(4). 

Group 6: all accessible 

and inaccessible 

reinforced concrete 

(3.5.1-36) 

Cracking due to 

expansion/re-action 

with aggregates 

Accessible areas: 

Inspection of WaterControl Structures or 

FERC/U.S. Army 

Corps of Engineers 

dam inspections and 

maintenance 

programs. None for 

inaccessible areas if 

concrete was 

constructed in 

accordance with the 

recommendations in 

ACI 201.2R-77 

Yes, if 

concrete 

was not 

constructed 

as stated for 

inaccessible 

areas 

Inspection of 

Water-Control 

Structures 

Consistent 

with GALL 

Report. SER 

Section 

3.5.2.2.2(4). 
Aging Management Review Results 

 3-300 

Component Group 

(GALL Report 

Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Group 6: exterior 

above and below grade 

reinforced concrete 

foundation interior slab 

(3.5.1-37) 

Increase in porosity 

and permeability, 

loss of strength due 

to leaching of 

calcium hydroxide 

For accessible 

areas, Inspection of 

Water-Control 

Structures or 

FERC/U.S. Army 

Corps of Engineers 

dam inspections and 

maintenance 

programs. None for 

inaccessible areas if 

concrete was 

constructed in 

accordance with the 

recommendations in 

ACI 201.2R-77 

Yes, if 

concrete 

was not 

constructed 

as stated for 

inaccessible 

areas 

Inspection of 

Water-Control 

Structures 

Consistent 

with GALL 

Report. See 

SER Section 

3.5.2.2.2(4). 

Groups 7, 8: Tank 

Liners 

(3.5.1-38) 

Cracking due to 

SCC; loss of 

material due to 

pitting and crevice 

corrosion 

Plant-specific Yes Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.5.2.2.2(5). 

Support members; 

welds; bolted 

connections; support 

anchorage to building 

structure 

(3.5.1-39) 

Loss of material due 

to general and pitting 

corrosion 

Structures 

Monitoring Program 

Yes, if not 

within the 

scope of the 

applicant’s 

Structures 

Monitoring 

Program 

Structures 

Monitoring 

Program 

Consistent 

with GALL 

Report. See 

SER Section 

3.5.2.2.2(6). 

Building concrete at 

locations of expansion 

and grouted anchors; 

grout pads for support 

base plates 

(3.5.1-40) 

Reduction in 

concrete anchor 

capacity due to local 

concrete 

degradation/ service 

induced cracking or 

other concrete aging 

mechanisms or other 

con 

Structures 

Monitoring Program 

Yes, if not 

within the 

scope of the 

applicant’s 

Structures 

Monitoring 

Program 

Structures 

Monitoring 

Program 

Consistent 

with GALL 

Report. See 

SER Section 

3.5.2.2.2(6). 

Vibration isolation 

elements 

(3.5.1-41) 

Reduction or loss of 

isolation 

function/radiation 

hardening, 

temperature, 

humidity, sustained 

vibratory loading 

Structures 

Monitoring Program 

Yes, if not 

within the 

scope of the 

applicant’s 

Structures 

Monitoring 

Program. 

Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.5.2.2.2(6). 

Groups B1.1, B1.2, and 

B1.3: support 

members: anchor 

bolts, welds 

(3.5.1-42) 

Cumulative fatigue 

damage (CLB 

fatigue analysis 

exists) 

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c) 

Yes, TLAA Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.5.2.2.2(7) 

and 4.3.

Groups 1-3, 5, 6: all 

masonry block walls 

(3.5.1-43) 

Cracking due to 

restraint shrinkage, 

creep, and 

aggressive 

environment 

Masonry Wall 

Program 

No Masonry Wall 

Program 

Consistent 

with GALL 

Report. 
Aging Management Review Results 

 3-301 

Component Group 

(GALL Report 

Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Group 6 elastomer 

seals, gaskets, and 

moisture barriers 

(3.5.1-44) 

Loss of sealing due 

to deterioration of 

seals, gaskets, and 

moisture barriers 

(caulking, flashing, 

and other sealants) 

Structures 

Monitoring Program 

No Structures 

Monitoring 

Program 

Consistent 

with GALL 

Report. 

Group 6: exterior 

above and below grade 

concrete foundation; 

interior slab 

(3.5.1-45) 

Loss of material due 

to abrasion, 

cavitation 

Inspection of WaterControl Structures or 

FERC/U.S. Army 

Corps of Engineers 

dam inspections and 

maintenance 

No Inspection of 

Water-Control 

Structures 

Consistent 

with GALL 

Report. 

Group 5: Fuel pool 

Liners 

(3.5.1-46) 

Cracking due to 

SCC; loss of 

material due to 

pitting and crevice 

corrosion 

Water chemistry and 

monitoring of spent 

fuel pool water level 

and level of fluid in 

the leak chase 

channel 

No Water 

Chemistry and 

monitoring of 

spent fuel pool 

water level in 

accordance 

with TS and 

leakage from 

the leak chase 

channels 

Consistent 

with GALL 

Report. 

Group 6: all metal 

structural members 

(3.5.1-47) 

Loss of material due 

to general (steel 

only), pitting, and 

crevice corrosion 

Inspection of Water 

Control Structures 

Associated with 

Nuclear Power 

Plants. If protective 

coatings are relied 

upon to manage 

aging, protective 

coating monitoring 

and maintenance 

provisions should be 

included 

No Inspection of 

Water-Control 

Structures 

Consistent 

with GALL 

Report. 

Group 6: earthen water 

control structures - 

dams, embankments, 

reservoirs, channels, 

canals, and ponds 

(3.5.1-48) 

Loss of material, 

loss of form due to 

erosion, settlement, 

sedimentation, frost 

action, waves, 

currents, surface 

runoff, Seepage 

Inspection of watercontrol structures 

associated with 

nuclear power plants

No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.5.2.1.1. 

Support members: 

welds; bolted 

connections; support 

anchorage to building 

structures 

(3.5.1-49) 

Loss of material/ 

general, pitting, and 

crevice corrosion 

Water chemistry and 

ISI (IWF) 

No Not applicable Not applicable 

to PWRs. 

See SER 

Section 

3.5.2.1.1. 
Aging Management Review Results 

 3-302 

Component Group 

(GALL Report 

Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Groups B2, and B4: 

galvanized steel, 

aluminum, stainless 

steel support members; 

welds; bolted 

connections; support 

anchorage to building 

structure 

(3.5.1-50) 

Loss of material due 

to pitting and crevice 

corrosion 

Structures 

Monitoring Program 

No Structures 

Monitoring 

Program 

Consistent 

with GALL 

Report, 

except for the 

Class 2 and 3 

components 

under ASME 

Section XI, 

Subsection 

IWF. See 

SER Section 

3.5.2.1.4. 

Group B1.1: high 

strength low-alloy bolts 

(3.5.1-51) 

Cracking due to 

SCC; loss of 

material due to 

general corrosion 

Bolting Integrity No Bolting 

Integrity 

Consistent 

with GALL 

Report. 

Groups B2, and B4: 

sliding support bearings 

and sliding support 

surfaces 

(3.5.1-52) 

Loss of mechanical 

function due to 

corrosion, distortion, 

dirt, overload, fatigue 

due to vibratory and 

cyclic thermal loads 

Structures 

Monitoring Program 

No Structures 

Monitoring 

Program 

Consistent 

with GALL 

Report. 

Groups B1.1, B1.2, and 

B1.3: support 

members: welds; 

bolted connections; 

support anchorage to 

building structure 

(3.5.2-53) 

Loss of material due 

to general and pitting 

corrosion 

ISI (IWF) No ISI (IWF) Consistent 

with GALL 

Report. 

Groups B1.1, B1.2, and 

B1.3: Constant and 

variable load spring 

hangers; guides; stops 

(3.5.2-54) 

Loss of mechanical 

function to corrosion, 

distortion, dirt, 

overload, fatigue due 

to vibratory and 

cyclic thermal loads 

ISI (IWF) No ISI (IWF) Consistent 

with GALL 

Report. 

Steel, galvanized steel, 

and aluminum support 

members; welds; bolted 

connections; support 

anchorage to building 

structure 

(3.5.2-55) 

Loss of material due 

to boric acid 

corrosion 

Boric Acid Corrosion No Boric Acid 

Corrosion 

Consistent 

with GALL 

Report. 

Groups B1.1, B1.2, and 

B1.3: Sliding surfaces 

(3.5.2-56) 

Loss of mechanical 

function due to 

corrosion, distortion, 

dirt, overload, fatigue 

due to vibratory and 

cyclic thermal loads 

ISI (IWF) No ISI (IWF) Consistent 

with GALL 

Report. 
Aging Management Review Results 

 3-303 

Component Group 

(GALL Report 

Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Groups B1.1, B1.2, and 

B1.3: Vibration 

isolation elements 

(3.5.2-57) 

Reduction or loss of 

isolation function/ 

radiation hardening, 

temperature, 

humidity, sustained 

vibratory loading 

ISI (IWF) No Not applicable Not applicable 

to PVNGS. 

See SER 

Section 

3.5.2.1.1. 

Galvanized steel and 

aluminum support 

members; welds; bolted 

connections; support 

anchorage to building 

structure exposed to 

air-indoor uncontrolled 

(3.5.2-58) 

None None No None Consistent 

with GALL 

Report. 

Stainless steel support 

members; welds; bolted 

connections; support 

anchorage to building 

structure 

(3.5.2-59) 

None None No None Consistent 

with GALL 

Report. 

 

The staff’s review of the SC supports groups fell into three categories. One category, 

documented in SER Section 3.5.2.1, reviewed AMR results for components that the applicant 

indicated are consistent with the GALL Report and require no further evaluation. Another 

category, documented in SER Section 3.5.2.2, reviewed AMR results for components that the 

applicant indicated are consistent with the GALL Report and for which further evaluation is 

recommended. A third category, documented in SER Section 3.5.2.3, reviewed AMR results for 

components that the applicant indicated are not consistent with, or not addressed in, the GALL 

Report. Section 3.0.3 documents the staff’s review of AMPs credited to manage or monitor 

aging effects of the SC supports. 

3.5.2.1 Aging Management Review Results Consistent with the Generic Aging Lessons 

Learned Report 

LRA Section 3.5.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the SSCs and their commodity groups: 

 10 CFR Part 50, Appendix J Program 

 ASME Section XI, Subsection IWE Program 

 ASME Section XI, Subsection IWF Program 

 ASME Section XI, Subsection IWL Program 

 Bolting Integrity 

 Boric Acid Corrosion 

 Fire Protection Program 

 Masonry Wall Program 

 RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 

 Structures Monitoring Program 

 Water Chemistry Program 
Aging Management Review Results 

 3-304 

LRA Tables 3.5.2-1 through 3.5.2-14 summarize AMRs for the SC supports elements and 

indicate AMRs claimed to be consistent with the GALL Report. 

The staff audited and reviewed the information in the LRA. The staff did not repeat its review of 

the matters described in the GALL Report; however, the staff did verify that the material 

presented in the LRA was applicable and that the applicant identified the appropriate GALL 

Report AMRs. The staff’s evaluation follows. 

3.5.2.1.1 Aging Management Review Results Identified as Not Applicable 

In LRA Table 3.5.1, items 3.5.1.5, 3.5.1.8, 3.5.1.11, 3.5.1.13, 3.5.1.19 through 3.5.1.21, and 

3.5.1.49, the applicant states that the corresponding AMR items in the GALL Report are not 

applicable to PVNGS because the units are a PWR reactor design that incorporates a 

containment system consisting of a steel-lined prestressed cylindrical concrete structure with a 

hemispherical dome. The AMR items in the GALL Report are only applicable to steel and 

stainless steel elements of BWR designs. The staff verified that the stated AMR items in the 

GALL Report are only applicable to metallic components of BWR designs and are not applicable 

to the PVNGS LRA. Based on this determination, the staff finds that the applicant has provided 

an acceptable basis for concluding AMR items 3.5.1.5, 3.5.1.8, 3.5.1.11, 3.5.1.13, 3.5.1.19 

through 3.5.1.21, and 3.5.1.49 are not applicable. 

LRA Table 3.5.1, item 3.5.1.48 addresses loss of material or form due to erosion, settlement, 

sedimentation, frost action, waves, currents, surface runoff, and seepage of earthen 

water-control structures exposed to water. The GALL Report recommends the Inspection of 

Water-Control Structures AMP to ensure that the aging effect is adequately managed. The 

applicant stated that this item is not applicable because there are no earthen dams, 

embankments, reservoirs, channels, canals, or ponds in-scope for license renewal. The staff 

reviewed LRA Sections 2.4.10 and 3.5 and confirmed that the applicant’s LRA does not have 

any AMR results for earthen water-control structures. The staff also reviewed the UFSAR to 

verify the same. Based on its review of the LRA and UFSAR, the staff confirmed that the 

applicant’s plant does not have any in-scope earthen water-control structures; therefore, it finds 

the applicant’s determination acceptable. 

LRA Table 3.5.1, item 3.5.1.57 addresses reduction or loss of isolation function due to radiation 

hardening, temperature, humidity, or sustained vibratory loading of vibration isolation elements. 

The GALL Report recommends the “ASME Section XI, Subsection IWF” AMP to ensure that the 

aging effect is adequately managed. The applicant stated that this item is not applicable 

because there are no vibration isolation elements in-scope for license renewal. The staff 

reviewed LRA Sections 2.4.14 and 3.5 and confirmed that the applicant’s LRA does not have 

any AMR results for vibration isolation elements. The staff also reviewed the UFSAR to verify 

the same. Based on its review of the LRA and UFSAR, the staff confirmed that the applicant’s 

plant does not have any in-scope vibration isolation elements; therefore, it finds the applicants 

determination acceptable. 

3.5.2.1.2 Cracking Due to Restraint Shrinkage, Creep, and Aggressive Environment 

In LRA Tables 3.5.2-2, 3.5.2-4, 3.5.2-5, and 3.5.2-13, which reference item 3.5.1.43 and 

plant-specific note 1, the applicant credits the Masonry Wall Program and the Fire Protection 

Program for managing this aging effect and mechanism in a plant indoor air environment. The 

applicant also included plant-specific note 1 that states, “NUREG-1801 does not provide a line 

in which Concrete Masonry is inspected per the Fire Protection program.” 

The staff reviewed the AMR results that referenced Note E and plant-specific note 1. The staff 

determined, for these items, that the component type, material, environment, and aging effect 

are consistent with the corresponding line of the GALL Report; however, where the GALL 

Report recommends AMP XI.S5, “Masonry Wall Program,” the applicant has proposed using the 
Aging Management Review Results 

 3-305 

Masonry Wall Program and the Fire Protection Program. The LRA states that the intended 

functions related to this item include fire barrier, shelter and protection, and structural support. 

Appendix B of the LRA states that the Masonry Wall Program is part of the Structures 

Monitoring Program that implements structures monitoring requirements as specified by 

10 CFR 50.65. This program includes cracking of masonry walls and structural steel restraint 

systems of the masonry walls within scope of license renewal based on guidance provided in 

IE bulletin 80-11 and NRC IN 87-67. In Appendix B of the LRA, the applicant further states that 

it uses the Fire Protection Program to manage aging in the form of cracking, spalling, and loss 

of material by visual inspection, every 18 months, of the fire barrier walls, ceilings, and floors. 

Since the applicant uses the Masonry Wall Program, with inspections included as part of the 

Structures Monitoring Program, with periodic visual inspections of the fire barrier walls, floors, 

and ceilings also performed under the Fire Protection Program, the staff finds that the applicant 

addressed the AERM adequately. SER Sections 3.0.3.2.20 and 3.0.3.2.7 document the staff’s 

review of the Structures Monitoring Program and Fire Protection Program, respectively. 

3.5.2.1.3 Loss of Material Due to General (Steel Only), Pitting, and Crevice Corrosion 

In LRA Table 3.5.2-10, items that reference item 3.5.1.47 and plant-specific note 1, the 

applicant credits the Structures Monitoring Program for managing this aging effect/mechanism 

in atmosphere/weather, plant indoor air, and submerged environments. The applicant also 

included a plant-specific note that states “NUREG 1801, line III.A6-11 specifies RG 1.127 as the 

program for metal components in water-control structures. RG 1.127 does not address metal 

components, so the Structures Monitoring Program is used.” 

The staff reviewed the AMR results lines that referenced Note E and the plant-specific note and 

determined that, for these items, the component type, material, and aging effect are consistent 

with the corresponding line of the GALL Report. However, where the GALL Report 

recommends XI.S7, “Regulatory Guide 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants,” as the AMP, the applicant has proposed using the 

Structures Monitoring Program as the AMP for the carbon steel water-control structural 

components. Appendix B, Section B2.1.33, of the LRA states that the PVNGS Structures 

Monitoring Program includes, and is consistent with, the recommendations in GALL AMP XI.S7, 

is in compliance with the requirements of 10 CFR 50.65, and includes inspection and 

surveillance activities for water-control structures associated with emergency cooling water 

systems on a frequency of at least once every five years. 

Since the applicant has committed to an appropriate AMP with an inspection frequency 

commensurate with the GALL Report guidance, the staff finds these AMR results to be 

acceptable. SER Section 3.0.3.2.20 documents the staff’s review of the Structures Monitoring 

Program. 

3.5.2.1.4 Loss of Material/Pitting and Crevice Corrosion 

In LRA Table 3.5.2-14, the item that references item 3.5.1.50 and plant-specific note 1, the 

applicant credits the ASME Section XI, Subsection IWF Program for managing this aging effect 

and mechanism in atmosphere or weather environment. Plant-specific note 1 states 

“NUREG-1801 does not provide a line to evaluate stainless steel components outdoors under 

ASME Section XI, Subsection IWF.” 

The staff reviewed the AMR results lines that referenced Note E and plant-specific note 1 and 

determined, that the component type, material, and aging effect for these items are consistent 

with the corresponding line of the GALL Report. However, where the GALL Report 

recommends XI.S6, “Structures Monitoring Program” as the AMP for stainless steel ASME 2 

and 3 supports, the applicant has proposed using ASME Section XI, Subsection IWF as the 

program to manage loss of material, cracking, and loss of mechanical function that could result 
Aging Management Review Results 

 3-306 

in loss of intended function for Class 1, 2, and 3 component supports. The IWF Program 

requires visual inspections at a frequency that meets or exceeds the requirements of the 

Structures Monitoring Program. 

Since the applicant has committed to an appropriate AMP with an inspection frequency and 

method that meets or exceeds the GALL Report guidance, the staff finds these AMR results to 

be acceptable. SER Section 3.0.3.1.11 documents the staff’s review of the ASME Section XI, 

Subsection IWF Program. 

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 aging effects. On the basis of its review, the 

staff concludes that the AMR results, which the applicant claimed to be consistent with the 

GALL Report, are indeed consistent with the corresponding AMRs. Therefore, the staff 

concludes that the applicant has 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 during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.5.2.2 Aging Management Review Results Consistent with the Generic Aging Lessons 

Learned Report for Which Further Evaluation Is Recommended 

In LRA Section 3.5.2, the applicant further evaluates aging management, as recommended by 

the GALL Report, for the containments, structures, and component supports and provides 

information concerning how it will manage aging effects in the following three areas: 

(1) PWR and BWR Containments 

– aging of inaccessible concrete areas 

– cracks and distortion due to increased stress levels from settlement, reduction of 

foundation strength, cracking, and differential settlement due to erosion of porous 

concrete subfoundations if not covered by the Structures Monitoring Program 

– reduction of strength and modulus of concrete structures due to elevated 

temperature 

– loss of material due to general, pitting, and crevice corrosion 

– loss of prestress due to relaxation, shrinkage, creep, and elevated temperature 

– cumulative fatigue damage 

– cracking due to SCC 

– cracking due to cyclic loading 

– loss of material (scaling, cracking, and spalling) due to freeze-thaw 

– cracking due to expansion and reaction with aggregate and increase in porosity 

and permeability due to leaching of calcium hydroxide 

(2) Safety-Related and Other SC Supports 

– aging of structures not covered by the Structures Monitoring Program 

– aging management of inaccessible areas (below-grade inaccessible concrete 

areas of Groups 1–5 and 7–9 structures) 

– reduction of strength and modulus of concrete structures due to elevated 

temperature for Group 1–5 structures 
Aging Management Review Results 

 3-307 

– aging management of inaccessible areas for Group 6 structures (below-grade 

inaccessible concrete areas) 

– cracking due to stress corrosion and loss of material due to pitting and crevice 

corrosion for Group 7 and 8 stainless steel tank liners 

– aging of supports not covered by the Structures Monitoring Program 

– cumulative fatigue damage due to cyclic loading 

(3) QA for Aging Management of Nonsafety-Related Components 

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA program. 

3.5.2.2.1 Pressurized Water Reactor and Boiling Water Reactor Containments 

The staff reviewed LRA Section 3.5.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.1, which 

addresses several areas as follows: 

 Aging of Inaccessible Concrete Areas. LRA Section 3.5.2.2.1.1 states that reinforced 

concrete structures were designed, constructed, and inspected in accordance with ACI 

and ASTM standards to provide good quality, dense, well-cured, and low permeability 

concrete. Crack control is achieved through proper sizing, spacing, and distribution of 

reinforcing steel in accordance with ACI 318-71. Concrete structures are not subjected 

to groundwater for sustained periods. An engineering study was conducted to confirm 

that groundwater elevations are located below the lowest structures indicating that 

further evaluation for the effects of aggressive chemical attack and corrosion of 

embedded steel is not required. 

 The staff reviewed LRA Section 3.5.2.2.1.1 against the criteria in SRP-LR 

Section 3.5.2.2.1.1, which states that increases in porosity and permeability, cracking, 

loss of material (e.g., spalling, scaling) due to aggressive chemical attack, and cracking, 

loss of bond, and loss of material (e.g., spalling, scaling) due to corrosion of embedded 

steel could occur in inaccessible areas of PWR and BWR concrete and steel 

containments. The GALL report identifies ASME Section XI, Subsection IWL to manage 

these aging effects and recommends further evaluation of plant-specific programs to 

manage these aging effects for inaccessible areas if the environment is aggressive. 

 The staff confirmed that the ASME Section XI, Subsection IWL Program manages all 

accessible areas of the concrete containment building for cracking, loss of material, and 

increase in porosity and permeability. SER Section 3.0.3.1.10 documents the staff’s 

review of the ASME Section XI, Subsection IWL Program. SER Section 3.5.2.2.2 

documents the staff’s review of the applicant’s evaluation of aging management of 

inaccessible areas not covered here, including the containment-related concrete. 

 Cracks and Distortion Due to Increased Stress Levels from Settlement; Reduction of 

Foundation Strength, Cracking, and Differential Settlement Due to Erosion of Porous 

Concrete Subfoundations, if not Covered by the Structures Monitoring Program. LRA 

Section 3.5.2.2.1.2 states that further evaluation of settlement is not required because 

the concrete components are evaluated under the Structures Monitoring Program and 

no permanent de-watering system or porous concrete foundations exist at PVNGS. 

 The staff reviewed LRA Section 3.5.2.2.1.2 against the criteria in SRP-LR 

Section 3.5.2.2.1.2, which states that cracks and distortion due to increased stress levels 

from settlement and reduction in foundation strength, cracking, and differential 

settlement due to erosion of porous concrete subfoundations could occur. The GALL 

report identifies the Structures Monitoring Program to manage these aging effects and 
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no further evaluation is recommended if this activity is within scope of the Structures 

Monitoring Program. 

 The staff confirmed that the Structures Monitoring Program manages the monitoring for 

settlement of every major structure. SER Section 3.0.3.2.20 documents the staff’s 

review of the Structures Monitoring Program. The staff also confirmed that no 

permanent de-watering system or porous concrete foundations exist. The staff finds 

acceptable the applicant’s evaluation of this AERM in that it meets the criteria in SRP-LR 

Section 3.5.2.2.1.2. 

 Reduction of Strength and Modulus of Concrete Structures Due to Elevated 

Temperature. LRA Section 3.5.2.2.1.3 states that the reactor cavity cooling subsystem 

operates in conjunction with the containment normal cooling units and provides 

continuous cooling of the primary shield and reactor cavity to limit the concrete 

temperature to less than the specified limit of 150 degrees F (66 degrees C). The 

reactor cavity is monitored with four cavity high temperature alarm channels that are 

annunciated in the control room. Plant TS require that the containment average air 

temperature not exceed 117 degrees F (47 degrees C). High-temperature piping has 

been designed to limit the local concrete temperature to 200 degrees F (93 degrees C). 

In the case of piping carrying hot fluid, the pipe is insulated to prevent excessive 

concrete temperatures and to prevent excessive heat loss from the fluid. 

 The staff reviewed LRA Section 3.5.2.2.1.3 against the criteria in SRP-LR 

Section 3.5.2.2.1.3, which recommends further evaluation of the plant-specific AMP if 

any portion of the concrete containment components exceeds the specified temperature 

limits of 150 degrees F (66 degrees C) general and 200 degrees F (93 degrees C) local. 

 The staff finds the applicant’s evaluation acceptable in that this aging effect is not likely 

to develop because the containment concrete is kept below the allowable temperature 

limits. 

 Loss of Material Due to General, Pitting and Crevice Corrosion. LRA Section 3.5.2.2.1.4 

addresses loss of material due to general, pitting, and crevice corrosion for steel 

elements of accessible and inaccessible areas of containments. The LRA states that 

reinforced concrete structures were designed, constructed, and inspected in accordance 

with ACI and ASTM standards that provide good quality, dense, well-cured, and lowpermeability concrete. Concrete mixes were designed in accordance with ACI 211.1-74. 

The applicant uses the ASME Section XI, Subsection IWL Program to identify and 

manage any cracks in the concrete that could potentially provide a pathway for water to 

reach inaccessible portions of the steel containment liner. In the LRA, the applicant 

states that borated water spills are not common and, when detected, the applicant 

cleans them up promptly. The applicant notes that further evaluation for corrosion in 

inaccessible areas of the steel liner of the containment is not required. 

 The staff reviewed LRA Section 3.5.2.2.1.4 against the criteria in SRP-LR 

Section 3.5.2.2.1.4. The SRP-LR criteria state that loss of material due to general, 

pitting and crevice corrosion could occur in steel elements of accessible and 

inaccessible areas for all types of PWR and BWR containments. The existing program 

relies on ASME Section XI Subsection IWE, and 10 CFR Part 50, Appendix J to manage 

this aging effect. The GALL Report recommends further evaluation of plant-specific 

programs to manage this aging effect for inaccessible areas if corrosion is significant. 

GALL Report, item II.A1-11 states that for inaccessible areas (e.g., embedded steel shell 

or liner), loss of material due to corrosion is not significant if the following conditions are 

satisfied: 
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– Concrete meeting the specifications of ACI 318 or 349 and the guidance of ACI 

201.2R was used for the containment concrete in contact with the embedded 

containment shell or liner. 

– The concrete is monitored to ensure that it is free of penetrating cracks that 

provide a path for water seepage to the surface of the containment shell or liner. 

– The moisture barrier, at the junction where the shell or liner becomes embedded, 

is subject to aging management activities in accordance with ASME Section XI, 

Subsection IWE requirements. 

– Borated water spills and water ponding on the containment concrete floor is not 

common and, when detected, is cleaned up promptly. 

 The staff verified that the containment concrete is monitored for cracks by the IWL AMP 

and that water ponding is not common on the containment floor. SER 

Sections 3.0.3.2.20, 3.0.3.2.18, and 3.0.3.1.12 document the staff’s review of the 

applicant’s Structures Monitoring Program, ASME Section XI, Subsection IWE Program, 

and Appendix J Program, respectively. The staff also reviewed the UFSAR and verified 

that all concrete work was done in accordance with ACI 318; however, the LRA did not 

discuss the first condition adequately in that it did not provide a comparison of the 

recommendations in ACI 211.1-74 to the recommendations of ACI 201.2R. Therefore, 

by letter dated February 19, 2010, the staff issued RAI 3.5.2.2.1-1 requesting the 

applicant to discuss how the concrete in contact with the embedded steel liner complies 

with the guidance in ACI 201.2R. 

 By letter dated March 24, 2010, the applicant responded and explained that the in-scope 

concrete was designed and constructed in accordance with ACI 211.1-74, which 

provides procedures for designing concrete mixes that take into consideration 

requirements for placeability, consistency, strength, and durability. The applicant further 

explained that the recommendations of ACI 201 are incorporated throughout these 

procedures and referenced in the ACI 211.1-74 discussions of durability, 

air-entrainment, and water-cement ratios. 

 The staff reviewed the applicant’s response and found it acceptable because it explains 

that ACI 211.1-74 includes many of the recommendations included in ACI 201.2R. The 

staff independently reviewed both standards and noted that both recommend use of a 

low water-cement ratio and the proper use of air-entrainment. Since the applicant 

followed the guidance of ACI 318 and ACI 211.1, which references much of the 

guidance in ACI 201.2R, the staff finds the applicant’s response acceptable. The staff’s 

concern in RAI 3.5.2.2.1-1 is resolved. Since the applicant has explained how all four 

conditions are satisfied, the staff finds that corrosion is not significant for inaccessible 

areas, the criteria of SRP-LR Section 3.5.2.2.1.4 have been met, and further evaluation 

is not required. 

 Loss of Prestress Due to Relaxation, Shrinkage, Creep, and Elevated Temperature. 

Loss of prestress due to relaxation, shrinkage, creep, and elevated temperature is a 

TLAA, as defined in 10 CFR 54.3. TLAAs are required to be evaluated in accordance 

with 10 CFR 54.21. SER Section 4.5, “Concrete Containment Tendon Prestress 

Analysis,” documents the staff’s review of the applicant’s evaluation of this TLAA. 

 Cumulative Fatigue Damage. LRA Section 3.5.2.2.1.6 states that containment 

penetrations for the main steam, main feedwater, and recirculation sump suction 

penetrations are supported by TLAAs. The applicant further stated that there are no 

penetration bellows within the scope of license renewal. LRA Section 4.6.2 describes 
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the evaluation of the main steam and feedwater penetrations, while Section 4.6.3 

describes the evaluation of the recirculation sump suction penetrations. 

 The staff reviewed LRA Section 3.5.2.2.1.6 against the criteria in SRP-LR 

Section 3.5.2.2.1.6, which states that fatigue analyses of penetrations are TLAAs, as 

defined in 10 CFR 54.3. SER Section 4.6 separately addresses the evaluation of this 

TLAA. The staff also confirmed that there are no containment penetration bellows within 

the scope of license renewal. 

 Cracking Due to Stress Corrosion Cracking. LRA Section 3.5.2.2.1.7 states that PVNGS 

has no in-scope stainless steel penetration sleeves, penetration bellows, or dissimilar 

metal welds subject to SCC. The applicant stated that this AERM is not applicable. The 

staff confirmed that there are no in-scope stainless steel penetration sleeves, 

penetration bellows, or dissimilar metal welds subject to SCC. 

 On the basis of its review, the staff finds the applicant’s evaluation of the aging effect 

“cracking due to stress corrosion cracking” acceptable, because no in-scope stainless 

steel penetration sleeves, penetration bellows, or dissimilar metal welds subject to SCC 

exist at PVNGS. 

 Cracking Due to Cyclic Loading. In LRA Section 3.5.2.2.1.8, the applicant stated that 

this section was not applicable because fatigue of metal components is a TLAA, 

evaluated in accordance with 10 CFR 54.21(c), so it did not use the applicable GALL 

Report lines. 

 The staff reviewed LRA Section 3.5.2.2.1.8 against the criteria in SRP-LR 

Section 3.5.2.2.1.8, which states that cracking due to cyclic loading of the stainless steel 

shells (including welded joints) and penetrations (including penetration sleeves, 

dissimilar metal welds, and penetration bellows) could occur in PWR containments. The 

existing program relies on ASME Section XI, Subsection IWE and 10 CFR Part 50, 

Appendix J to manage this aging effect. However, VT-3 visual inspection may not detect 

fine cracks. The GALL Report recommends further evaluation for detection of this aging 

effect. 

 The staff reviewed the appropriate GALL Report items for this section and confirmed that 

they only apply if a CLB fatigue analysis does not exist. The staff reviewed the LRA and 

confirmed that the metal containment components within the scope of license renewal 

have a fatigue analysis and are reviewed as TLAAs. Therefore, the staff confirms no 

further evaluation is necessary for this section. SER Section 4.6 documents the staff’s 

review of the containment TLAAs. 

 Loss of Material (Scaling, Cracking, and Spalling) Due to Freeze–Thaw. LRA 

Section 3.5.2.2.1.9 states that loss of material due to freeze-thaw is not applicable. The 

applicant stated that PVNGS is located in a weathering region classified as negligible 

according to Figure 1 of ASTM C33-03; therefore, this AERM is not applicable. 

 The staff reviewed LRA Section 3.5.2.2.1.9 against the criteria in SRP-LR 

Section 3.5.2.2.1.9, which recommends further evaluation of loss of material due to 

freeze-thaw for plants with concrete containments located in moderate to severe 

weathering conditions. The staff finds acceptable the applicant’s evaluation that this 

aging effect is not applicable because the primary containment structural concrete is 

located in a weathering region classified as having negligible freeze-thaw effects. 

 Cracking Due to Expansion and Reaction with Aggregate, and Increase in Porosity and 

Permeability, Due to Leaching of Calcium Hydroxide. LRA Section 3.5.2.2.1.10 states 

that acceptance of aggregate materials was based, in part, on petrographic examination 
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in accordance with ASTM C295. Aggregate reactivity was evaluated in accordance with 

ASTM C289 and C227, and the reinforced concrete structures were designed, 

constructed, and inspected in accordance with ACI and ASTM standards that provide 

good quality, dense, well-cured, and low-permeability concrete. The applicant further 

stated that concrete mixes were designed in compliance with ACI 211.1-74 and that 

procedural controls were imposed on the concrete throughout the batching, mixing, and 

placing processes. The applicant also noted that the concrete structures are not 

subjected to flowing water, and an engineering study shows that the groundwater 

elevations are below the lowest structures. The applicant states that further evaluation 

for the effects of reaction with aggregates and leaching of calcium hydroxide are not 

required. 

 The staff reviewed LRA Section 3.5.2.2.1.10 against the criteria in SRP-LR 

Section 3.5.2.2.1.10, which states that cracking due to expansion and reaction with 

aggregate, and increase in porosity and permeability due to leaching of calcium 

hydroxide, could occur in concrete elements of concrete and steel containments. The 

GALL Report recommends further evaluation for concrete not constructed in accordance 

with the recommendations in ACI 201.2R-77. 

 The staff confirmed that the applicant uses the ASME Section XI, Subsection IWL 

Program to manage cracking, loss of material, and increase in porosity and permeability 

of the concrete containment building, and it evaluated the aggregate materials in 

accordance with appropriate ASTM standards. SER Section 3.0.3.1.10 documents the 

staff’s review of the applicant’s ASME Section XI, Subsection IWL Program. The staff 

also reviewed the UFSAR and verified that the applicant used ASTM C295 to evaluate 

the reactivity of the concrete aggregate. In its review, the staff noted that the applicant 

did not note that the concrete was constructed in accordance with the recommendations 

in ACI 201.2R. By letter dated February 19, 2010, the staff issued RAI 3.5.2.2.1-1 to ask 

if concrete was constructed using the recommendations provided in ACI 201.2R. 

 By letter dated March 24, 2010, the applicant responded and explained that the in-scope 

concrete was designed and constructed in accordance with ACI 211.1-74, which 

provides procedures for designing concrete mixes that consider ACI201 

recommendations for concrete placeability, consistency, strength, and durability. 

 The staff reviewed the applicant’s response and found it acceptable because it explains 

that the recommendations of ACI 201 are incorporated into the guidance of 

ACI 211.1 74. SER Section 3.5.2.2.1(4) provides a more detailed discussion of the 

staff’s review. The staff’s concern in RAI 3.5.2.2.1-1 is resolved. Since the reactivity of 

the aggregates has been evaluated using ASTM C295, and the concrete was 

constructed in accordance with the guidance in ACI 201.2R, the staff finds that the 

criteria of SRP-LR Section 3.5.2.2.1.10 have been met, and no further evaluation is 

required. 

 Based on the programs and analyses discussed above, the staff concludes that the 

applicant has met the criteria of SRP-LR Section 3.5.2.2.1. For those items that apply to 

LRA Section 3.5.2.2.1, the staff determines that the LRA is consistent with the GALL 

Report and the applicant has demonstrated that it will adequately manage the effects of 

aging so that the intended functions will be maintained consistent with the CLB during 

the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.5.2.2.2 Safety-Related and Other Structures and Component Supports 

The staff reviewed LRA Section 3.5.2.2.2 against the criteria in SRP-LR Section 3.5.2.2.2, 

covering several areas as addressed below. 
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 Aging of Structures Not Covered by Structures Monitoring Program. LRA 

Section 3.5.2.2.2.1 states that corrosion of embedded steel, aggressive chemical attack, 

loss of material due to corrosion, freeze-thaw, reaction with aggregates, and settlement 

are all aging effects that the Structures Monitoring Program evaluates. The LRA also 

states that further evaluation of erosion of porous concrete subfoundations is not 

required because PVNGS does not have porous concrete subfoundations. The LRA 

states that all in-scope sliding surfaces are evaluated under the Structures Monitoring 

Program or the ASME Section XI, Subsection IWF 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, which states that the GALL Report recommends further evaluation 

of certain structure and aging effect combinations if they are not covered by the 

structures monitoring program. These combinations include those listed below: 

– cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of 

embedded steel for Groups 1–5, 7, and 9 structures 

– increase in porosity and permeability, cracking, loss of material (spalling, scaling) 

due to aggressive chemical attack for Groups 1–5, 7, and 9 structures 

– loss of material due to corrosion for Groups 1–5, 7, and 8 structures 

– loss of material (spalling, scaling) and cracking due to freeze-thaw for Groups 1–

3, 5, and 7–9 structures 

– cracking due to expansion and reaction with aggregates for Groups 1–5 and 7–9 

structures 

– cracks and distortion due to increased stress levels from settlement for Groups 

1–3 and 5–9 structures 

– reduction in foundation strength, cracking, differential settlement due to erosion 

of porous concrete subfoundation for Groups 1–3 and 5–9 structures 

 The LRA further states that lock-up due to wear may occur for Lubrite radial beam seats 

in BWR drywells, RPV support shoes for PWRs with nozzle supports, SG supports, and 

other sliding support bearings and sliding support surfaces. The existing program relies 

on the Structures Monitoring Program to manage this aging effect. The GALL Report 

recommends further evaluation only for structure-aging effect combinations not within 

the ISI (IWF) or Structures Monitoring Programs. 

 The staff reviewed the LRA and confirmed that the listed aging effects are evaluated 

within the Structures Monitoring Program. The staff also verified that PVNGS does not 

have porous concrete subfoundations. Therefore, as noted in the GALL Report, no 

further evaluation has been conducted. 

 Aging Management of Inaccessible Areas (Below-Grade Inaccessible Concrete Areas of 

Groups 1-5, and 7-9 Structures). The staff reviewed LRA Section 3.5.2.2.2.2 against the 

following criteria in SRP-LR Section 3.5.2.2.2.2: 

– Loss of material (spalling, scaling) and cracking due to freeze-thaw could occur 

in below-grade inaccessible concrete areas of Groups 1–3, 5, and 7–9 

structures. 

 LRA Section 3.5.2.2.2.2.1 states that loss of material due to freeze-thaw is not 

applicable. The applicant stated that PVNGS is located in a weathering region 

classified as negligible according to Figure 1 of ASTM C33-03. Therefore, the 

applicant states that this AERM is not applicable. 
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 The staff reviewed LRA Section 3.5.2.2.2.1 against the criteria in SRP-LR 

Section 3.5.2.2.2.2.1, which recommends further evaluation of loss of material 

due to freeze-thaw for plants with concrete containments located in moderate to 

severe weathering conditions. The staff finds acceptable the applicant’s 

evaluation that this aging effect is not applicable because the concrete is located 

in a weathering region classified as negligible. 

– Cracking due to expansion and reaction with aggregates could occur in 

below-grade inaccessible concrete areas for Groups 1–5 and 7–9 structures. 

 In LRA Section 3.5.2.2.2.2.2, the applicant states that acceptance of aggregate 

materials was based, in part, on petrographic examination in accordance with 

ASTM C295 and aggregate reactivity was evaluated in accordance with ASTM 

C289 and C227. In LRA Section 3.5.2.2.1.10, the applicant stated that the 

reinforced concrete structures at PVNGS were designed, constructed, and 

inspected in accordance with ACI and ASTM standards that provide good quality, 

dense, well-cured, and low-permeability concrete. The applicant further states, in 

LRA Section 3.5.2.2.1.10, that concrete mixes were designed in compliance with 

ACI 211.1-74 and those procedural controls were imposed on the concrete 

throughout the batching, mixing, and placing processes. The applicant states 

that further evaluation for the effects of reaction with aggregates is not required. 

 The staff reviewed LRA Section 3.5.2.2.2.2.2 against the criteria in SRP-LR 

Section 3.5.2.2.2.2.2, which states that the GALL Report recommends further 

evaluation of inaccessible areas of these groups of structures if the concrete was 

not constructed in accordance with the recommendations in ACI 201.2R-77. 

GALL Report item III.A2-2 states that investigations, tests, and petrographic 

examinations of aggregates performed in accordance with ASTM C295-54 or 

ASTM C227-50 can demonstrate that the aggregate is not reactive within the 

reinforced concrete. If either of these conditions is met, the GALL Report notes 

that aging management is not necessary. 

 The staff found that the concrete mix design adequately addressed cracking due 

to expansion and reaction with aggregates. The LRA states that acceptance of 

aggregate materials was based, in part, on petrographic examination in 

accordance with ASTM C295, and aggregate reactivity was evaluated in 

accordance with ASTM C289 and C227. Also, the staff verified in the UFSAR 

that concrete work was done in accordance with ACI 318. 

 Based on its review, the staff finds that the aggregates used at PVNGS are 

nonreactive, and the concrete was constructed in accordance with the 

recommendations in ACI 318. Therefore, cracking due to expansion and 

reaction with aggregate in below-grade, inaccessible concrete areas for Groups 

1–5 and 7–9 structures are not aging effects for concrete elements, and no 

additional plant-specific program is required. 

– Cracks and distortion due to increased stress levels from settlement and 

reduction of foundation strength, cracking, and differential settlement due to 

erosion of porous concrete subfoundations could occur in below-grade 

inaccessible concrete areas of Groups 1–3, 5, and 7–9 structures. 

 In LRA Section 3.5.2.2.2.2.3, the applicant states that competent foundation 

materials are present to establish conservative design and construction criteria 

for support of the facilities with major structures founded on engineered backfill or 

undeformed basin sediments, with a minimum thickness in the power block areas 

of 200 feet. The applicant stated that these sediments are firm, consolidated, 
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continuous, and show no evidence of shears, faults, joints, folds, or other tectonic 

features. The LRA notes that the applicant has not constructed a permanent 

dewatering system and has monitored the settlement of all major structures at 

frequent years during the first three years after construction, followed by a 

monitoring frequency of five years. Results reported in the UFSAR through 

December 2003 show that the total post-construction recorded settlements are 

well below the 1.5-inch maximum specified in the UFSAR. The applicant states 

that further evaluation of settlement is not required because the concrete 

components are evaluated under the Structures Monitoring Program and no 

permanent de-watering system or porous concrete foundations exist. 

 The staff reviewed LRA Section 3.5.2.2.2.2.3 against the criteria in SRP-LR 

Section 3.5.2.2.2.2.3, which states that the GALL Report recommends 

verification of the continued functionality of the de-watering system during the 

period of extended operation if the plant’s CLB credits a de-watering system to 

control settlement. The GALL Report recommends no further evaluation if this 

activity, and these aging effects are included in the scope of the applicant’s 

Structures Monitoring Program. 

 The staff confirmed in program basis documents that the Structures Monitoring 

Program manages the monitoring for settlement of every major structure. SER 

Section 3.0.3.2.20 documents the staff’s review of the Structures Monitoring 

Program. The staff also confirmed that no permanent de-watering system or 

porous concrete foundations exist. The staff finds acceptable the applicant’s 

evaluation of this AERM because it meets the criteria in SRP-LR Section 

3.5.2.2.2.2.3. 

– Increase in porosity and permeability, cracking and loss of material (spalling, 

scaling) due to aggressive chemical attack and cracking, loss of bond, and loss 

of material (spalling, scaling) due to corrosion of embedded steel could occur in 

below-grade inaccessible concrete areas of Groups 1–3, 5, and 7–9 structures. 

 LRA Section 3.5.2.2.2.2.4 states that reinforced concrete structures were 

designed, constructed, and inspected in accordance with ACI and ASTM 

standards and procedural controls were utilized throughout the batching, mixing, 

and placement processes to provide for a good quality, dense, well-cured, and 

low-permeability concrete. The LRA further states that proper sizing, spacing, 

and distribution of reinforcing steel complied with ACI 318-71 requirements. 

Concrete structures were noted not to be subjected to groundwater for any 

sustained period, and an engineering study confirmed that the groundwater 

elevations are below the lowest structures. 

 The staff reviewed LRA Section 3.5.2.2.2.2.4 against the criteria in SRP-LR 

Section 3.5.2.2.2.2.4, which states that the GALL Report recommends further 

evaluation of plant-specific programs to manage these aging effects and 

mechanisms in inaccessible areas of these groups of structures if the 

environment is aggressive. In the GALL Report, it is noted that for inaccessible 

areas of plants with non-aggressive groundwater or soil (i.e., pH greater than 5.5, 

chlorides less than 500 parts per million, or sulfates less than 1,500 parts per 

million), the applicant should consider examinations of the exposed portions of 

the below-grade concrete, when excavated for any reason as well as periodic 

monitoring of below-grade water chemistry, including consideration of potential 

seasonal variations. 
Aging Management Review Results 

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 The staff found that the concrete structures were designed, constructed, and 

inspected following recommended ACI and ASTM standards and procedural 

controls to provide good quality concrete. The LRA states that the concrete 

structures are not subjected to groundwater for any sustained periods; however, 

the applicant does not quantify what it meant by sustained periods. The 

applicant also failed to demonstrate that the groundwater or soil adjacent to the 

inaccessible concrete structures is not aggressive, allows for opportunistic 

inspections of exposed portions of below-grade concrete, or provides for periodic 

monitoring of below-grade water chemistry, including seasonal variations. By 

letter dated February 19, 2010, the staff issued RAI 3.5.2.2.2-1 to address this 

issue. 

 By letter dated March 24, 2010, the applicant responded and explained that 

plant-operating experience, including opportunistic inspections of buried 

structures, has not identified any degradation due to aggressive groundwater or 

soil. The applicant further explained that the groundwater below the site is a 

perched aquifer that resulted from irrigation before plant construction. Since 

cessation of irrigation, the water level has dropped. It is currently 20 feet below 

the lowest structure and continues to drop. The applicant also stated that an 

engineering study in 2007 concluded that it is unlikely that the groundwater levels 

will rise in the future. Furthermore, the applicant stated that the Structures 

Monitoring Program includes provisions for inspections of inaccessible areas 

whenever they are made available, as well as actively uncovering below-grade 

concrete if conditions in adjoining or similar areas indicate that it is necessary. 

 The staff reviewed the response and found it acceptable because the applicant 

explained that the below-grade concrete is not exposed to groundwater, and the 

Structures Monitoring Program examines below-grade concrete when excavated 

for any reason. In addition, the applicant has not seen any indication of concrete 

degradation related to aggressive groundwater. The staff’s concern in 

RAI 3.5.2.2.2-1 is resolved. 

 On the basis of its review, the staff finds that the increase in porosity and 

permeability, cracking, loss of material (spalling, scaling) due to aggressive 

chemical attack and the cracking, loss of bond, and loss of material (spalling, 

scaling) due to corrosion of embedded steel in below-grade inaccessible 

concrete areas of Groups 1–3, 5 and 7–9 structures require no further evaluation 

because the concrete is not exposed to aggressive groundwater. In addition, the 

Structures Monitoring Program will inspect below-grade concrete when exposed 

for any reason. 

– Increase in porosity and permeability, and loss of strength due to leaching of 

calcium hydroxide, could occur in below-grade inaccessible concrete areas of 

Groups 1–3, 5, and 7–9 structures. 

 LRA Section 3.5.2.2.2.2.5 states that reinforced concrete structures were 

designed, constructed, and inspected in accordance with ACI and ASTM 

standards and procedural controls were utilized throughout the batching, mixing, 

and placement processes to provide for a good quality, dense, well-cured, and 

low-permeability concrete. The LRA also states that concrete mixes were 

designed in accordance with ACI 211.1-74. In addition, concrete structures are 

not subjected to flowing water for any sustained periods, and an engineering 

study confirms that groundwater elevations are below the lowest structures. The 

applicant stated that further evaluation of this AERM is not required. 
Aging Management Review Results 

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 The staff reviewed LRA Section 3.5.2.2.2.2.5 against the criteria in SRP-LR 

Section 3.5.2.2.2.2.5, which states that the GALL Report recommends further 

evaluation of this aging effect for inaccessible areas of Groups 1–3, 5 and 7–9 

structures if concrete was not constructed in accordance with the 

recommendations in ACI 201.2R-77. 

 In their review, the staff noted that the concrete structures were designed, 

constructed, and inspected in accordance with ACI and ASTM standards and 

procedural controls were utilized throughout the batching, mixing, and placement 

processes to provide for a good quality, dense, well-cured, and low permeability 

concrete. In its review, the staff noted that the applicant did not define what was 

meant by “not subjected to flowing water for any sustained periods” and did not 

note that the concrete was constructed in accordance with the recommendations 

in ACI 201.2R. By letter dated February 19, 2010, the staff issued 

RAI 3.5.2.2.1-1 to address the compliance of PVNGS concrete to 

recommendations provided in ACI 201.2R. 

 By letter dated March 24, 2010, the applicant responded and explained that the 

in-scope concrete was designed and constructed in accordance with 

ACI 211.1-74, which provides procedures for designing concrete mixes that take 

into consideration ACI 201 recommendations for concrete placeability, 

consistency, strength, and durability. The applicant further explained the two 

critical environmental conditions to consider when designing durable concrete 

are groundwater and exposure to freeze-thaw cycles. The applicant stated that 

an engineering study, conducted in 2007, concluded there was little likelihood of 

local raising groundwater levels beneath the units in the future. Therefore, site 

structures are not exposed to groundwater from the perched aquifer. In addition, 

the weathering index for PVNGS is negligible according to ASTM C33, Figure 1; 

therefore, the freeze-thaw cycles are not a concern. 

 The staff reviewed the applicant’s response and found it acceptable because it 

explains that the recommendations of ACI 201 are incorporated into the guidance 

of ACI 211.1-74. SER Section 3.5.2.2.1(4) supplies a more detailed discussion 

of the staff’s review. The staff’s concern in RAI 3.5.2.2.1-1 is resolved. Since the 

concrete was constructed in accordance with the guidance in ACI 201.2R, the 

staff finds that the criteria of SRP-LR Section 3.5.2.2.2.2.5 have been met, and 

no further evaluation is required. 

Based on the programs and analyses discussed above, the staff concludes that the applicant 

has met the criteria of SRP-LR Section 3.5.2.2.2.2. For those items that apply to LRA 

Section 3.5.2.2.2.2, the staff determines that the LRA is consistent with the GALL Report and 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended functions will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

 Reduction of Strength and Modulus of Concrete Structures Due to Elevated 

Temperature for Groups 1–5 Structures). LRA Section 3.5.2.2.2.3 addresses reduction 

of concrete strength and modulus due to elevated temperatures that may occur in PWR 

and BWR Groups 1–5 concrete structures. The applicant stated that the reactor cavity 

cooling subsystem operates in conjunction with the containment normal cooling units 

and provides continuous cooling of the primary shield and reactor cavity to limit the 

concrete temperature to less than the specified limit of 150 degrees F (65 degrees C). 

The reactor cavity is monitored with four high temperature alarm channels that are 

annunciated in the control room. Plant TS require that the containment average air 

temperature not exceed 117 degrees F (47 degrees C). High-temperature piping 
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penetrations have been designed to limit the local concrete temperature to 

200 degrees F (93 degrees C). In the case of piping carrying hot fluid, the pipe is 

insulated to prevent excessive concrete temperatures. 

 The staff reviewed LRA Section 3.5.2.2.2.3 against the criteria in SRP-LR 

Section 3.5.2.2.2.3, which states that reduction of strength and modulus of concrete, due 

to elevated temperatures, may occur in PWR and BWR Groups 1–5 concrete structures. 

ACI 349-85 specifies the concrete temperature limits for normal operation or any other 

long-term period and states that general area temperatures shall not exceed 

150 degrees F (65 degrees C) except for local areas that are permitted to have 

temperatures not to exceed 200 degrees F (93 degrees C). The GALL Report 

recommends further evaluation of a plant-specific program if any portion of the 

safety-related and other concrete structures exceeds these limits. 

 The staff reviewed program basis documents and noted that Group 1–5 concrete 

elements do not exceed temperature limits associated with aging degradation due to 

elevated temperature. On the basis of its review, the staff finds that reduction in strength 

and modulus of elasticity due to elevated temperatures in concrete areas of Groups 1–5 

structures is not a plausible AERM because concrete temperatures are maintained 

below limits specified in ACI 349-85. Therefore, the staff finds that this is not an AERM 

for these components because design and preventive measures preclude occurrence of 

the elevated temperature condition. 

 Aging Management of Inaccessible Areas for Group 6 Structures (Below Grade 

Inaccessible Concrete Areas). The staff reviewed LRA Section 3.5.2.2.2.4 against the 

following criteria in SRP-LR Section 3.5.2.2.2.4: 

– Increase in porosity and permeability, cracking, loss of material (spalling, scaling) 

due aggressive chemical attack and cracking, loss of bond, and loss of material 

(spalling, scaling) due to corrosion of embedded steel could occur in below-grade 

inaccessible concrete areas of Group 6 structures. 

 LRA Section 3.5.2.2.2.4.1 states that reinforced concrete structures were 

designed, constructed, and inspected in accordance with ACI and ASTM 

standards. In addition, it used procedural controls throughout the batching, 

mixing, and placement processes to provide for a good quality, dense, 

well-cured, and low-permeability concrete. The LRA further states that proper 

sizing, spacing, and distribution of reinforcing steel complied with ACI 318-71 

requirements. Concrete structures were noted to not be subjected to 

groundwater for any sustained periods, and an engineering study was performed 

to confirm that the groundwater elevations are below the lowest structures. 

 The staff reviewed LRA Section 3.5.2.2.2.4.1 against the criteria in SRP-LR 

Section 3.5.2.2.2.4.1, which states that the GALL Report recommends further 

evaluation of plant-specific programs to manage these aging effects in 

inaccessible areas of these groups of structures if the environment is aggressive. 

In the GALL Report, it is noted that for inaccessible areas of plants with 

non-aggressive groundwater and soil (i.e., pH greater than 5.5, chlorides less 

than 500 parts per million, or sulfates less than 1,500 parts per million) the 

applicant should consider examinations of the exposed portions of the 

below-grade concrete, when excavated for any reason and periodic monitoring of 

below-grade water chemistry, including consideration of potential seasonal 

variations. 

 The staff noted that inspections of Group 6 structures are performed under the 

Structures Monitoring Program, which is consistent with and incorporates the 
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elements of RG 1.127, ”Inspection of Water-Control Structures Associated with 

Nuclear Power Plants Program.” The staff found that the concrete structures 

were designed, constructed, and inspected following the recommended ACI and 

ASTM standards and procedural controls to provide good quality concrete. SER 

Section 3.0.3.2.20 documents the staff’s review of the Structures Monitoring 

Program. The staff confirmed that Group 6 structures subject to this AMR are inscope of the Structures Monitoring Program. It was further noted that the 

concrete structures are not subjected to groundwater for any sustained periods of 

time; however, the applicant did not quantify what it meant by sustained periods 

of time. The applicant also failed to demonstrate that the groundwater or soil 

adjacent to the inaccessible concrete structures is not aggressive, allow for 

opportunistic inspections of exposed portions of below-grade concrete, or provide 

for periodic monitoring of below-grade water chemistry, including seasonal 

variations. By letter dated February 19, 2010, the staff issued RAI 3.5.2.2.2-1 to 

address these issues. 

 By letter dated March 24, 2010, the applicant responded and explained that plant 

operating experience, including opportunistic inspections of buried structures, 

has not identified any degradation due to aggressive groundwater or soil. The 

applicant further explained that the groundwater below the site is a perched 

aquifer that resulted from irrigation before plant construction. Since cessation of 

irrigation, the water level has dropped. It is currently 20 feet below the lowest 

structure and continues to drop. The applicant also stated that an engineering 

study, done in 2007, concluded that there is little likelihood the groundwater 

levels will rise in the future. Furthermore, the applicant stated that the Structures 

Monitoring Program includes provisions for inspections of inaccessible areas 

whenever they are made available, as well as actively uncovering below-grade 

concrete if conditions in adjoining or similar areas indicate that it is necessary. 

 The staff reviewed the response and found it acceptable because the applicant 

explained that the below-grade concrete is not exposed to groundwater, and the 

Structures Monitoring Program examines below-grade concrete when excavated 

for any reason. In addition, the applicant has not seen any indication of concrete 

degradation related to aggressive groundwater. The staff’s concern in RAI 

3.5.2.2.2-1 is resolved. 

 On the basis of its review, the staff finds that the increase in porosity and 

permeability, cracking, loss of material (spalling, scaling) due to aggressive 

chemical attack and cracking, loss of bond, and loss of material (spalling, 

scaling) due to corrosion of embedded steel in below-grade inaccessible 

concrete areas of Group 6 structures requires no further evaluation because the 

concrete is not exposed to aggressive groundwater, and the Structures 

Monitoring Program will inspect below-grade concrete when exposed for any 

reason. 

– Loss of material (spalling, scaling) and cracking due to freeze-thaw could occur 

in below-grade inaccessible concrete areas of Group 6 structures. 

 LRA Section 3.5.2.2.2.4.2 states that PVNGS is located in a weathering region 

classified as negligible according to Figure 1 of ASTM C33-03. Therefore, the 

applicant states that this AERM is not applicable. 

 The staff reviewed LRA Section 3.5.2.2.2.4.2 against the criteria in SRP-LR 

Section 3.5.2.2.2.4.2, which recommends further evaluation of loss of material 

due to freeze-thaw for plants with concrete containments located in moderate to 
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severe weathering conditions. The staff finds acceptable the applicant’s 

evaluation that this aging effect is not applicable because the Group 6 structures 

concrete is located in a weathering region classified as negligible. 

– Cracking due to expansion and reaction with aggregates and increase in porosity 

and permeability, and loss of strength due to leaching of calcium hydroxide could 

occur in below-grade inaccessible reinforced concrete areas of Group 6 

structures. 

 LRA Section 3.5.2.2.2.4.3 states that concrete in inaccessible areas is evaluated 

for expansion and cracking due to reaction with aggregate. In LRA Section 

3.5.2.2.1.10, the applicant stated that acceptance of aggregate materials was 

based, in part, on petrographic examination in accordance with ASTM C295. 

Aggregate reactivity was evaluated in accordance with ASTM C289 and C227, 

and the reinforced concrete structures were designed, constructed and inspected 

in accordance with ACI and ASTM standards to provide good quality, dense, 

well-cured, and low-permeability concrete. The applicant further stated that 

concrete mixes were designed in compliance with ACI 211.1-74 and that 

procedural controls were imposed on the concrete throughout the batching, 

mixing, and placing processes. The applicant also noted that the concrete 

structures are not subjected to flowing water for sustained periods, and an 

engineering study shows that the groundwater elevations are below the lowest 

structures. The applicant stated that further evaluation for the effects of reaction 

with aggregates and leaching of calcium hydroxide are not required. 

 The staff reviewed LRA Section 3.5.2.2.2.4.3 against the criteria in SRP-LR 

Section 3.5.2.2.2.4.3, which states that the GALL Report recommends further 

evaluation of inaccessible areas if concrete was not constructed in accordance 

with the recommendations in ACI 201.2R-77. 

 SER Section 3.5.2.2.2(2)(b) documents the staff’s review for cracking due to 

expansion and reaction with aggregates for inaccessible concrete elements of 

Groups 1–5 and 7–9 structures. The staff noted that inspections of Group 6 

structures are performed under the Structures Monitoring Program, which is 

consistent with and integrates the elements of RG 1.127, “Inspection of 

Water-Control Structures Associated with Nuclear Power Plants Program.” SER 

Section 3.0.3.2.20 documents the staff’s review of the Structures Monitoring 

Program. The staff confirmed that accessible portions of Group 6 structures 

subject to this AMR are in-scope of the Structures Monitoring Program. 

 SER Section 3.5.2.2.2(2)(e) documents the staff’s review for increase in porosity 

and permeability, and loss of strength due to leaching of calcium hydroxide for 

inaccessible concrete elements of Groups 1–3, 5, and 7–9 structures. The staff 

noted that the applicant conducts inspections of Group 6 structures under the 

Structures Monitoring Program, which is consistent with and integrates the 

elements of RG 1.127, “Inspection of Water-Control Structures Associated with 

Nuclear Power Plants Program.” SER Section 3.0.3.2.20 documents the staff’s 

review of the Structures Monitoring Program. The staff confirmed that accessible 

portions of Group 6 structures subject to this AMR are in-scope of the Structures 

Monitoring Program. 

 On the basis of its review, the staff finds that cracking due to expansion and 

reaction with aggregates and increase in porosity and permeability and loss of 

strength due to leaching of calcium hydroxide in below-grade inaccessible 
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concrete areas of Group 6 structures requires no further evaluation because the 

concrete was constructed in accordance with the guidance in ACI 201.2R. 

Based on the programs identified above, the staff concludes that the applicant has met the 

criteria of SRP-LR Section 3.5.2.2.2.4. For those items that apply to LRA Section 3.5.2.2.2.4, 

the staff determines that the LRA is consistent with the GALL Report. The applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3). 

 Cracking due to Stress Corrosion Cracking and Loss of Material due to Pitting and 

Crevice Corrosion for Group 7 and 8 (Stainless Steel Tank Liners). LRA 

Section 3.5.2.2.2.5 states that the applicant evaluated in-scope tank liners in the CVCS 

and condensate systems and assigned them to GALL Report Chapters VII and VIII. 

Therefore, the applicant stated that further evaluation for the effects of cracking due to 

SCC and loss of material due to pitting and crevice corrosion is not required. 

 The staff reviewed LRA Section 3.5.2.2.2.5 against the criteria in SRP-LR 

Section 3.5.2.2.2.5, which states that cracking due to SCC and loss of material due to 

pitting and crevice corrosion could occur for Group 7 and 8 stainless steel tank liners 

exposed to standing water. The GALL Report recommends further evaluation of 

plant-specific programs to manage these aging effects. 

 The staff reviewed the Gall Report, Chapters VII and VIII relative to the CVCS and 

condensate systems, respectively. In Chapter VII Section E1, which addresses the 

CVCS, and Chapter VIII Section E, which addresses the condensate system, the staff 

noted that for stainless steel tanks in a treated borated water environment (temperature 

greater than 60 degrees C), the GALL Report recommends the Water Chemistry 

Program as the AMP for cracking due to SCC and loss of material due to pitting and 

crevice corrosion. The staff confirmed that the applicant evaluated in-scope tank liners 

in the condensate and CVCS systems and had been assigned to the Gall Report 

Chapters VII and VIII. 

 Aging of Supports Not Covered by Structures Monitoring Program. LRA 

Section 3.5.2.2.2.6 states that further evaluation of the following components is not 

required because they will be inspected per the Structures Monitoring Program: building 

concrete around support anchors, HVAC duct supports, instrument supports, non-ASME 

mechanical equipment supports, non-ASME supports, and electrical panels and 

enclosures. The LRA states, in Table 3.5.1, that PVNGS has no in-scope vibration 

isolation elements. 

 The staff reviewed LRA Section 3.5.2.2.2.6 against the criteria in SRP-LR 

Section 3.5.2.2.2.6, which states that further evaluation of certain component support 

and aging effect combinations is recommended if not covered by the Structures 

Monitoring Program. This includes the loss of material due to general and pitting 

corrosion, for Group B2–B5 supports, the reduction in concrete anchor capacity due to 

degradation of the surrounding concrete, for Group B1–B5 supports, and the reduction 

or loss of isolation function due to degradation of vibration isolation elements, for Group 

B4 supports. Further evaluation is necessary only for structure and aging effect 

combinations not covered by the Structures Monitoring Program. 

– Loss of Material Due to General and Pitting Corrosion, for Group B2–B5 

Supports. The LRA states, in Table 3.5.1, that loss of material due to general 

and pitting corrosion for Group B2–B5 supports is an aging effect that does not 

require further evaluation because the components are inspected under the 

Structures Monitoring Program. Supports identified include the HVAC duct 
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supports, instrument supports, non-ASME mechanical equipment supports, 

non-ASME supports, and electrical panels and enclosures. 

 The staff reviewed LRA Section 3.5.2.2.2.6 against the criteria in SRP-LR 

Section 3.5.2.2.2.6, which states that further evaluation is necessary only for 

structure and aging effect combinations not covered by the Structures Monitoring 

Program. 

 The staff confirmed that the Structures Monitoring Program manages the 

component support and aging effect combination of loss of material due to 

general and pitting corrosion for Group B2–B5. SER Section 3.0.3.2.20 

documents the staff’s review of the PVNGS Structures Monitoring Program. 

Since the applicant has committed to an appropriate AMP for the period of 

extended operation, the staff finds these AMR results to be acceptable. 

– Reduction in Concrete Anchor Capacity Due to Degradation of the Surrounding 

Concrete, for Group B1–B5 Supports. The LRA states, in Table 3.5.1, that the 

Structures Monitoring Program manages the reduction in concrete anchor 

capacity due to degradation of the surrounding concrete. 

 The staff reviewed LRA Section 3.5.2.2.2.6 against the criteria in SRP-LR 

Section 3.5.2.2.2.6, which states that further evaluation is necessary only for 

structure and aging effect combinations not covered by the Structures Monitoring 

Program. The staff confirmed that the Structures Monitoring Program manages 

the component support and aging effect combination of reduction in concrete 

anchor capacity due to degradation of the surrounding concrete for Group B2–B5 

supports. SER Section 3.0.3.2.20 documents the staff’s review of the PVNGS 

Structures Monitoring Program. Since the applicant has committed to an 

appropriate AMP for the period of extended operation, the staff finds these AMR 

results to be acceptable. 

– Reduction or Loss of Isolation Function Due to Degradation of Vibration Isolation 

Elements, for Group B4 Supports. The LRA states, in Table 3.5.1, that PVNGS 

has no in-scope vibration isolation elements. SER Section 3.5.2.1.1 documents 

the staff’s evaluation. 

Based on the programs and analysis identified above, the staff concludes that the applicant has 

met the criteria of SRP-LR Section 3.5.2.2.2.6. For those items that apply to LRA 

Section 3.5.2.2.2.6, the staff determines that the LRA is consistent with the GALL Report and 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended functions will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

 Cumulative Fatigue Damage due to Cyclic Loading. LRA Section 3.5.2.2.2.7 states that 

the applicant’s review identified no TLAAs supporting the design of these components. 

SER Section 4.3, “Metal Fatigue Analysis” documents the staff’s evaluation of the 

Class 1 component supports metal fatigue TLAA. 

3.5.2.2.3 Quality Assurance for Aging Management of Nonsafety-Related Components 

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA program. 

3.5.2.3 Aging Management Review Results Not Consistent with or Not Addressed in 

the Generic Aging Lessons Learned Report 

In LRA Tables 3.5.2-1 through 3.5.2-14, the staff reviewed additional details of the AMR results 

for material, environment, AERM, and AMP combinations not consistent with, or not addressed 

in, the GALL Report. 
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In LRA Tables 3.5.2-1 through 3.5.2-14, the applicant indicated, via notes F–J that the 

combination of component type, material, environment, and AERM does not correspond to an 

item in the GALL Report. The applicant provided further information about how it will manage 

the aging effects. Specifically, Note F indicates that the material for the AMR item component is 

not evaluated in the GALL Report. Note G indicates that the environment for the AMR item 

component and material is not evaluated in the GALL Report. Note H indicates that the aging 

effect for the AMR item component, material, and environment combination is not evaluated in 

the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the 

item component, material, and environment combination is not applicable. Note J indicates that 

neither the component nor the material and environment combination for the item is evaluated in 

the GALL Report. 

For component type, material, and environment combinations not evaluated in the GALL 

Report, the staff reviewed the applicant’s evaluation to determine if the applicant has 

demonstrated that it will adequately manage the effects of aging so that the intended function(s) 

will be maintained consistent with the CLB for the period of extended operation. The following 

sections document the staff’s evaluation. 

3.5.2.3.1 Containments, Structures, and Component Supports—Summary of Aging 

Management Evaluation—Containment Building 

In LRA Tables 3.5.2-1, 3.5.2-2, and 3.5.2-5, the applicant stated that the Fire Protection 

Program manages cementitious fire barrier coatings and wraps exposed to air-indoor 

uncontrolled (external) for loss of material and cracking. The AMR items cite generic Note J, 

indicating that neither the component nor the material and environment combination is 

evaluated in the GALL Report. The staff reviewed all AMR result lines in the GALL Report 

where the component and material is cementitious coating fire barriers or wraps and confirmed 

that there are no entries for this component or material where the aging effect is loss of material 

due to cracking. 

The staff reviewed the applicant’s Fire Protection Program, and SER Section 3.0.3.2.7 

documents its evaluation. The staff noted that the applicant’s Fire Protection Program conducts 

visual inspections of fire barriers once every 18 months for detection of cracking and loss of 

material. The staff also noted that the Fire Protection Program is used for other fire barriers 

including concrete walls, floors, and ceilings, and that cementitious fire barrier coatings have 

similar aging effects to concrete. The staff finds the applicant’s proposal to manage aging using 

the Fire Protection Program acceptable because the program performs visual inspections of fire 

barriers that are capable of detecting loss of material for cementitious fire barrier coatings and 

wraps. 

In LRA Tables 3.5.2-1, 3.5.2-2, and 3.5.2-7 the applicant stated that ceramic fiber and 

thermo-lag fire barrier seals exposed to air-indoor uncontrolled (external) are being managed for 

loss of material and cracking by the Fire Protection Program. The AMR items cite generic 

Note J, indicating that neither the component nor the material and environment combination is 

evaluated in the GALL Report. The staff reviewed all AMR result lines in the GALL Report 

where the component and material is ceramic fiber or thermo-lag fire barriers or seals and 

confirmed that there are no entries for this component and material where the aging effect is 

loss of material and cracking. 

The staff reviewed the applicant’s Fire Protection Program, and SER Section 3.0.3.2.7 

documents its evaluation. The staff noted that the applicant’s Fire Protection Program conducts 

visual inspections of fire barriers once every 18 months for detection of cracking and loss of 

material. The staff also noted that thermo-lag and ceramic fibers are used to provide fire 

barriers for cable trays and conduits. The staff finds the applicant’s proposal to manage aging 

using the Fire Protection Program acceptable because the program performs visual inspections 
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of fire barriers that are capable of detecting loss of material and cracking for ceramic and 

thermo-lag fire barriers and seals. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that their intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.5.2.3.2 Containments, Structures, and Component Supports—Summary of Aging 

Management Evaluation—Control Building 

SER Section 3.5.2.3.1 documents the staff’s evaluation for cementitious coating fire barrier 

coatings and wraps exposed to air-indoor uncontrolled (external), with aging effects of loss of 

material and cracking managed by the Fire Protection Program, with generic Note J. 

SER Section 3.5.2.3.1 documents the staff’s evaluation for ceramic fiber and thermo-lag fire 

barrier seals exposed to air-indoor uncontrolled (external), with aging effects of loss of material 

and cracking managed by the Fire Protection Program, with generic Note J. 

In LRA Tables 3.5.2-2, 3.5.2-5, and 3.5.2-13, the applicant stated that gypsum and plaster fire 

barriers exposed to air-indoor uncontrolled (external) are managed for cracking by the Fire 

Protection Program. The AMR items cite generic Note J, indicating that the GALL Report does 

not evaluate either the component or the material and environment combination. The staff 

reviewed all AMR result lines in the GALL Report where the component and material is gypsum 

or plaster fire barriers, and it confirmed that there are no entries for this component and material 

where the aging effect is cracking. 

The staff reviewed the applicant’s Fire Protection Program, and SER Section 3.0.3.2.7 

documents its evaluation. The staff noted that the applicant’s Fire Protection Program conducts 

visual inspections of fire barriers once every 18 months for detection of cracking and loss of 

material. The staff also noted that gypsum and plaster materials are commonly used to form 

walls when a fire barrier is required and that the GALL Report recommends the Fire Protection 

Program to manage aging for fire barrier walls constructed of other materials, such as concrete. 

The staff finds the applicant’s proposal to manage aging using the Fire Protection Program 

acceptable because the program performs visual inspections of fire barriers that are capable of 

detecting loss of material and cracking for ceramic and thermo-lag fire barriers and seals. 

The staff finds that the applicant has demonstrated that it will adequately manage the effects of 

aging for these components so that their intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.5.2.3.3 Diesel Generator Building—Summary of Aging Management Review—License 

Renewal Application Table 3.5.2-3 

The staff reviewed LRA Table 3.5.2-3, which summarizes the results of AMR evaluations for the 

diesel generator building component groups. The staff’s review did not identify any items with 

notes F–J, indicating that the combinations of component type, material, environment, and 

AERM for this system are consistent with the GALL Report. 

SER Section 3.0.2.2 documents the staff’s evaluation of the items with Notes A–E. 
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3.5.2.3.4 Turbine Building—Summary of Aging Management—License Renewal Application 

Table 3.5.2-4 

SER Section 3.5.2.3.1 documents the staff’s evaluation for cementitious coating fire barrier 

coatings and wraps exposed to air-indoor uncontrolled (external) with aging effects of loss of 

material and cracking managed by the Fire Protection Program, with generic Note J. 

3.5.2.3.5 Auxiliary Building—Summary of Aging Management Review—License Renewal 

Application Table 3.5.2-5 

SER Section 3.5.2.3.1 documents the staff’s evaluation for cementitious coating fire barrier 

coatings and wraps exposed to air-indoor uncontrolled (external) with aging effects of loss of 

material and cracking managed by the Fire Protection Program, with generic note J. 

SER Section 3.5.2.3.2 documents the staff’s evaluation for gypsum and plaster fire barrier 

exposed to air-indoor uncontrolled (external) having an aging effect of cracking managed by the 

Fire Protection Program, with generic note J. 

3.5.2.3.6 Radwaste Building—Summary of Aging Management Review—License Renewal 

Application Table 3.5.2-6 

The staff reviewed LRA Table 3.5.2-6, which summarizes the results of AMR evaluations for the 

radwaste building component groups. The staff’s review did not identify any items with notes F 

through J, indicating that the combinations of component type, material, environment, and 

AERM for this system are consistent with the GALL Report. 

SER Section 3.0.2.2 documents the staff’s evaluation of the items with Notes A–E. 

3.5.2.3.7 Main Steam Support Structure—Summary of Aging Management Review—License 

Renewal Application Table 3.5.2-7 

In LRA Table 3.5.2-7, the applicant stated that the Fire Protection Program manages the 

thermo-lag fire barrier seals externally exposed to plant indoor air for loss of material and 

cracking. SER Section 3.0.3.2.7 documents the staff’s evaluation. 

3.5.2.3.8 Station Blackout Generator Building—Summary of Aging Management Review—

License Renewal Application Table 3.5.2-8 

The staff reviewed LRA Table 3.5.2-8, which summarizes the results of AMR evaluations for the 

SBO generator building component groups. The staff’s review did not identify any items with 

notes F–J, indicating that the combinations of component type, material, environment, and 

AERM for this system are consistent with the GALL Report. 

SER Section 3.0.2.2 documents the staff’s evaluation of the items with Notes A–E. 

3.5.2.3.9 Fuel Building—Summary of Aging Management Review—License Renewal 

Application Table 3.5.2-9 

In LRA Table 3.5.2-9, for one component type—structural steel—the applicant proposed to 

assign the component to the Structures Monitoring Program to manage the aging effect of loss 

of material on carbon steel in a buried environment. This item references Note J, stating the 

GALL Report does not evaluate either the component or the material and environment 

combination. The intended function of this component is to provide for thermal expansion or 

seismic separation. 

The applicant stated that the Structures Monitoring Program provides inspection guidelines and 

walkdown checklists for concrete elements, structural steel, masonry walls, structural features, 

structural supports, and miscellaneous components such as doors. The applicant notes that the 

structural component is in a buried environment; however, it is not clear how this component will 

be inspected under the Structures Monitoring Program to demonstrate that this AERM is being 
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effectively managed since the Structures Monitoring Program, in large measure, is visual. 

Therefore, by letter dated February 19, 2010, the staff issued RAI 3.5.2.3-1 asking the applicant 

to explain how it will use the Structures Monitoring Program to manage this AERM. 

By letter dated March 24, 2010, the applicant explained that the portion of the component that is 

in a buried environment is normally inaccessible. The Structures Monitoring Program will 

inspect this portion of the component when it is accessible for any reason, or if conditions in 

adjoining areas indicate it is necessary to uncover the buried portion for inspection. 

The staff reviewed the applicant’s response and found it acceptable because it is the Structures 

Monitoring Program, which is the appropriate AMP for carbon steel in an outdoor environment, 

per GALL Report Table 5, item 25. In addition, the applicant’s Structures Monitoring Program 

has incorporated GALL Report recommended opportunistic inspections of inaccessible areas. 

SER Section 3.5.2.2.2, “Aging Management of Inaccessible Areas,” provides a more detailed 

discussion of the staff’s review of aging management of inaccessible areas. 

3.5.2.3.10 Spray Pond and Associated Water Control Structures—Summary of Aging 

Management Review—License Renewal Application Table 3.5.2-10 

In LRA Table 3.5.2-10, for one component type—screen—the applicant proposed to assign 

copper alloy to the Structures Monitoring Program to monitor for loss of material in a raw water 

environment. This item references Note J, “Neither the component nor the material and 

environment combination is evaluated in NUREG-1801,” and plant-specific note 2, which states 

that the GALL Report does not provide a line in which copper alloy screens are inspected per 

the Structures Monitoring Program. 

The applicant stated that the Structures Monitoring Program provides inspection guidelines and 

walkdown checklists for concrete elements, structural steel, masonry walls, structural features, 

structural supports, and miscellaneous components such as doors. The applicant notes that the 

structural component is used as a filter and will be monitored for loss of material; however, since 

this material is in a raw water environment and potentially has limited accessibility, it is not clear 

to the staff how the Structures Monitoring Program will inspect this component to demonstrate 

that this AERM is being effectively managed. Therefore, by letter dated February 19, 2010, the 

staff issued RAI 3.5.2.3-2 asking the applicant to explain how it will use the Structures 

Monitoring Program to manage this AERM. 

By letter dated March 24, 2009, the applicant explained that the screens in question are the 

ESP screens, which are accessible through the exterior deck of the spray pond pump house. 

The applicant raises the screens above the water level for visual inspection for loss of material. 

The staff reviewed the applicant’s response and found it acceptable because it explains how the 

Structures Monitoring Program will be able to complete visual inspections on the component for 

loss of material. The staff’s concern in RAI 3.5.2.3-2 is resolved. 

The staff noted that this material, aging effect, and environment combination is very similar to 

GALL Report item III.A6-11, which credits XI.S7 with managing copper alloys in raw water for 

loss of material. Since the applicant’s Structures Monitoring Program incorporates the 

requirements of XI.S7 (i.e. visual inspections on a five-year frequency), the staff finds the 

applicant’s use of the Structures Monitoring Program acceptable for this AMR item. 

SER Section 3.3.2.3.7 documents the staff’s evaluation for stainless steel components exposed 

to atmosphere or weather conditions, where there are no AERM and no AMP, citing generic 

note G. 

Based on its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 
Aging Management Review Results 

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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). 

3.5.2.3.11 Tank Foundations and Shells—Summary of Aging Management Review—License 

Renewal Application Table 3.5.2-11 

The staff reviewed LRA Table 3.5.2-11, which summarizes the results of AMR evaluations for 

the tank foundations and shells component groups. 

3.5.2.3.12 Transformer Foundations and Electrical Structures—Summary of Aging 

Management Review—License Renewal Application Table 3.5.2-12 

The staff reviewed LRA Table 3.5.2-12, which summarizes the results of AMR evaluations for 

the transformer foundations and electrical structures component groups. The staff’s review did 

not identify any items with notes F–J, indicating that the combinations of component type, 

material, environment, and AERM for this system are consistent with the GALL Report. 

SER Section 3.0.2.2 documents the staff’s evaluation of the items with Notes A–E. 

3.5.2.3.13 Yard Structures (In-Scope)—Summary of Aging Management Review—License 

Renewal Application Table 3.5.2-13 

SER Section 3.5.2.3.2 documents the staff’s evaluation for gypsum and plaster fire barriers 

exposed to air-indoor uncontrolled (external) having an aging effect of cracking managed by the 

Fire Protection Program with generic Note J. 

3.5.2.3.14 Supports—Summary of Aging Management Review—License Renewal Application 

Table 3.5.2-14 

In LRA Table 3.5.2-14, for one component type—non-ASME support—the applicant proposed to 

assign carbon steel and stainless steel having a nonsafety-related structural support function to 

the Structures Monitoring Program to manage the aging effect of loss of material in a raw water 

environment. This item references Note G, “Environment not in NUREG-1801 for this 

component and material.” The applicant stated that the PVNGS Structures Monitoring Program 

provides inspection guidelines and walkdown checklists for concrete elements, structural steel, 

masonry walls, structural features, structural supports, and miscellaneous components such as 

doors. The applicant notes that the structural component is used as a nonsafety-related 

structural support function and that nonsafety-related supports meet the criterion under 

10 CFR 54.4(a)(2) when they prevent interaction between safety-related and nonsafety-related 

components. However, since this material is in a raw water environment and potentially has 

limited accessibility, it is not clear to the staff how the applicant will inspect this component 

under the Structures Monitoring Program to demonstrate that it effectively manages this AERM. 

Therefore, by letter dated February 19, 2010, the staff issued RAI 3.5.2.3-3 asking the applicant 

to explain how it will use the Structures Monitoring Program to manage this AERM. 

In its response, dated March 24, 2010, the applicant explained that the components were 

included to evaluate the non-code supports for drain pipes located inside the radioactive waste 

drain sumps. The applicant further explained that it included these supports within the scope of 

license renewal in error; therefore, the referenced non-code supports have been deleted from 

LRA Table 3.5.2-14. 

The staff verified that removal of the supports from the scope of license renewal was 

appropriate by comparing with the criteria of 10 CFR 54.4(a)(1), (2), or (3) for SSCs within the 

scope of license renewal. The staff reviewed the applicant’s response and found it acceptable 

because the supports do not meet the criteria of 10 CFR 54.4(a)(1), (2), or (3). 

In LRA Table 3.5.2-14, for component type—Supports ASME 2 and 3—the applicant proposed 

to credit the IWF Program to manage the aging effect of loss of material for carbon and 
Aging Management Review Results 

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stainless steel in a raw water and a fuel oil environment. This item references Note G, 

“Environment not in NUREG-1801 for this component and material.” Since this material is in a 

raw water or fuel oil environment and potentially has limited accessibility, it is not clear how this 

component will be inspected under the IWF Program to demonstrate that this AERM is being 

effectively managed. Therefore, by letter dated April 28, 2010, the staff issued RAI 3.5.2.3-4 

asking the applicant to explain how the IWF Program would manage the effect of aging on 

carbon and stainless steel components in a raw water or fuel oil environment. 

By letter dated May 21, 2010, the applicant explained that the supports in a raw water 

environment are ASME Class 3 stainless steel supports located in the ESPs. There are no 

carbon steel supports in the raw water environment of the ESPs. The applicant revised the LRA 

accordingly. The applicant further explained that it examined the ASME Class 3 supports, 

according to IWF requirements, using remote cameras. The applicant also explained that the 

supports in a fuel oil environment are ASME Class 3 carbon steel supports located in the diesel 

fuel oil storage tank. There are no stainless steel supports in a diesel fuel oil environment. The 

applicant revised the LRA accordingly. The applicant further explained that these supports are 

within the scope of the AMSE Section XI, Subsection IWF Program, but are exempt from 

examination. 

The staff reviewed the applicant’s response and found the applicant’s explanation acceptable 

regarding the inspection of stainless steel supports in a raw water environment since they are 

being inspected remotely, according to the IWF requirements. However, the staff needed 

additional information about the inspection requirements for carbon steel supports. Therefore, 

the staff requested the basis for which the fuel oil transfer pump supports are exempt from IWF 

examination requirements. 

In a letter dated June 21, 2010, the applicant supplemented its response to RAI 3.5.2.3-4. The 

applicant stated that a carbon steel Class 3 support assembly, which also supports the diesel 

fuel oil transfer pump, restrains the three-quarter-inch diameter diesel fuel discharge line in the 

diesel fuel oil tank. The applicant further stated that diesel fuel oil pump support is exempt from 

IWF examination based on the size of the pipe. 

The staff reviewed the applicant’s supplemental information and found it acceptable because 

the diesel fuel oil tank support also supports the three-quarter-inch diameter diesel fuel 

discharge line. IWF-1230 exempts supports from examination requirements that are connected 

to piping that is exempt from volumetric, surface, and VT-1 or VT-3 visual examination in 

accordance with IWD-1220. According to IWD-1220, Class 3 components and piping 

segments, 4-inch diameter and smaller, are exempt from VT-1 visual examination. 

Based on its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.5.3 Conclusion 

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the structures and component supports 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). 
Aging Management Review Results 

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3.6 Aging Management of Electrical and Instrumentation and Controls

The following information documents the staff’s review of the applicant’s AMR results for the 

electrical and instrumentation and control (I&C) components and component groups of the 

following parts: 

 connections (metallic parts) 

 connectors 

 high-voltage insulators 

 insulated cables and connections 

 metal enclosed bus 

 penetrations electrical 

 switchyard bus and connections 

 terminal block 

 transmission conductors and connections 

3.6.1 Summary of Technical Information in the Application 

LRA Section 3.6 provides AMR results for the electrical and I&C components and component 

groups. LRA Table 3.6.1, “Summary of Aging Management Evaluations in Chapter VI of 

NUREG-1801 [the GALL Report] for Electrical Components,” is a summary comparison of the 

applicant’s AMRs with those evaluated in the GALL Report for the electrical and I&C 

components and component groups. 

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industryoperating experience in the determination of AERMs. The plant-specific evaluation included 

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 provided sufficient information 

to demonstrate that it would adequately manage the effects of aging for the electrical and I&C 

components 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 reviewed AMRs to ensure the applicant’s claim that certain 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 has identified the appropriate GALL Report AMRs. SER Section 3.0.3 

documents the staff’s evaluations of the AMPs, and SER Section 3.6.2.1 gives details of the 

staff’s evaluation for AMRs that are consistent with the GALL Report. 

The staff also reviewed AMRs 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 SRP-LR Section 3.6.2.2 acceptance criteria. SER Section 3.6.2.2 documents the 

staff’s evaluations. 

The staff also conducted a technical review of the remaining AMRs not consistent with or not 

addressed in the GALL Report. The technical review evaluated if all plausible aging effects 

have been identified and if the aging effects listed were appropriate for the material-environment 

combinations specified. SER Section 3.6.2.3 documents the staff’s evaluations. 
Aging Management Review Results 

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For SSCs that the applicant claimed were not applicable or required no aging management, the 

staff reviewed the AMR items and the plant’s operating experience to verify the applicant’s 

claims. 

Table 3.6-1 summarizes the staff’s evaluation of components, aging effects or mechanisms, and 

AMPs listed in LRA Section 3.6 and addressed in the GALL Report. 

Table 3.6-1. Staff Evaluation for Electrical and Instrumentation and Controls 

in the GALL Report 

Component Group 

(GALL Report 

Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or Amendments 

Staff 

Evaluation 

Electrical equipment 

subject to 

10 CFR 50.49 EQ 

requirements 

(3.6.1-1) 

Degradation due to 

various aging 

mechanisms 

EQ of Electric 

Components 

Yes TLAA Consistent 

with GALL 

Report. See 

Section 

3.6.2.2.1. 

Electrical cables, 

connections and fuse 

holders (insulation) 

not subject to 

10 CFR 50.49 

EQ requirements 

(3.6.1-2) 

Reduced insulation 

resistance and electrical 

failure due to various 

physical, thermal, 

radiolytic, photolytic, 

and chemical 

mechanisms 

Electrical Cables 

and Connections 

Not Subject to 

10 CFR 50.49 

EQ Requirements

No Electrical Cables 

and Collections 

not Subject to 

10 CFR 50.49 

EQ 

Requirements 

Consistent 

with GALL 

Report. 

Conductor insulation 

for electrical cables 

and connections used 

in instrumentation 

circuits not subject to 

10 CFR 50.49 

EQ requirements that 

are sensitive to 

reduction in conductor 

insulation resistance 

(3.6.1-3) 

Reduced insulation 

resistance and electrical 

failure due to various 

physical, thermal, 

radiolytic, photolytic, 

and chemical 

mechanisms 

Electrical Cables 

And Connections 

Used In 

Instrumentation 

Circuits Not 

Subject to 

10 CFR 50.49 

EQ Requirements

No Electrical Cables 

and Connections 

Not Subject to 

10 CFR 50.49 

EQ Used in 

Instrumentation 

Circuits 

Consistent 

with GALL 

Report. 

Conductor insulation 

for inaccessible 

medium voltage (2 kV 

to 35 kV) cables 

(e.g., installed in 

conduit or direct 

buried) not subject to 

10 CFR 50.49 

EQ requirements 

(3.6.1-4) 

Localized damage and 

breakdown of insulation 

leading to electrical 

failure due to moisture 

intrusion, water trees 

Inaccessible 

Medium Voltage 

Cables Not 

Subject to 

10 CFR 50.49 

EQ Requirements

No Inaccessible 

Medium-Voltage 

Cables Not 

Subject to 

10 CFR 50.49 

EQ Program 

Consistent 

with GALL 

Report. 

Connector contacts 

for electrical 

connectors exposed 

to borated water 

leakage 

(3.6.1-5) 

Corrosion of connector 

contact surface due to 

intrusion of borated 

water 

Boric Acid 

Corrosion 

No Boric Acid 

Corrosion 

Consistent 

with GALL 

Report. 
Aging Management Review Results 

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Component Group 

(GALL Report 

Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or Amendments 

Staff 

Evaluation 

Fuse Holders (Not 

Part of a Larger 

Assembly): Fuse 

holders - metallic 

clamp 

(3.6.1-6) 

Fatigue due to ohmic 

heating, thermal cycling, 

electrical transients, 

frequent manipulation, 

vibration, chemical 

contamination, 

corrosion, and oxidation 

Fuse Holders No Fuse Holder Consistent 

with GALL 

Report. 

MEB –

bus/connections 

(3.6.1-7) 

Loosening of bolted 

connections due to 

thermal cycling and 

ohmic heating 

MEB No MEB Program Consistent 

with GALL 

Report. 

MEB –

insulation/insulators 

(3.6.1-8) 

Reduced insulation 

resistance and electrical 

failure due to various 

physical, thermal, 

radiolytic, photolytic, 

and chemical 

mechanisms 

MEB No MEB Program Consistent 

with GALL 

Report. 

MEB – enclosure 

assemblies 

(3.6.1-9) 

Loss of material due to 

general corrosion 

Structures 

Monitoring 

Program 

No MEB Program Consistent 

with GALL 

Report. See 

Section 

3.6.2.1.1 

MEB – enclosure 

assemblies 

(3.6.1-10) 

Hardening and loss of 

strength due to 

elastomers degradation 

Structures 

Monitoring 

Program 

No MEB Program 

(B2.1.36) 

Consistent 

with GALL for 

material, 

environment, 

aging effect, 

but a different 

AMP is 

credited (See 

Section 

3.6.2.1.2) 

High-voltage 

insulators 

(3.6.1-11) 

Degradation of 

insulation quality due to 

presence of any salt 

deposits and surface 

contamination; loss of 

material caused by 

mechanical wear due to 

wind blowing on 

transmission conductors

A plant-specific 

AMP is to be 

evaluated 

Yes None Further 

evaluation 

(See SER 

Section 

3.6.2.2.2) 

Transmission 

conductors and 

connections; 

switchyard bus and 

connections 

(3.6.1-12) 

Loss of material due to 

wind induced abrasion 

and fatigue; loss of 

conductor strength due 

to corrosion; increased 

resistance of connection 

due to oxidation or loss 

of preload 

A plant-specific 

AMP is to be 

evaluated 

Yes None Further 

evaluation 

(See SER 

Section 

3.6.2.2.3) 
Aging Management Review Results 

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Component Group 

(GALL Report 

Item No.) 

Aging Effect/ 

Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, 

or Amendments 

Staff 

Evaluation 

Cable Connections - 

metallic parts 

(3.6.1-13) 

Loosening of bolted 

connections due to 

thermal cycling, ohmic 

heating, electrical 

transients, vibration, 

chemical contamination, 

corrosion, and oxidation 

Electrical Cable 

Connections Not 

Subject to 

10 CFR 50.49 EQ 

Requirements 

No Electrical Cable 

Connections Not 

Subject to 

10 CFR 50.49 

EQ 

Requirements 

Program 

(B2.1.35) 

Consistent 

with GALL 

(See Section 

3.6.2.1) 

Fuse Holders (Not 

Part of a Larger 

Assembly) - insulation 

material 

(3.6.1-14) 

None None No Not applicable Consistent 

with GALL. 

(See Section 

3.6.2.1) 

 

The staff’s review of the electrical and I&C component groups fell into one of three categories. 

One category, documented in SER Section 3.6.2.1, reviewed AMR results for components that 

the applicant indicated are consistent with the GALL Report and require no further evaluation. 

Another category, documented in SER Section 3.6.2.2, reviewed AMR results for components 

that the applicant indicated are consistent with the GALL Report and for which further evaluation 

is recommended. A third category, documented in SER Section 3.6.2.3, reviewed AMR results 

for components that the applicant indicated are not consistent with or not addressed in the 

GALL Report. SER Section 3.0.3 documents the staff’s review of AMPs credited to manage or 

monitor aging effects of the electrical and I&C components. 

3.6.2.1 Aging Management Review Results Consistent with the Generic Aging Lessons 

Learned Report 

LRA Section 3.6.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the electrical and I&C components: 

 Electrical Cable Connections Not Subject to 10 CFR 50.49 EQ Requirements 

 Boric Acid Corrosion 

 Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements 

 Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Used 

in Instrumentation Circuits 

 Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 EQ Requirements 

 Metal Enclosed Bus 

 Fuse Holders 

In LRA Table 3.6.2-1, the applicant summarized AMRs for the electrical and I&C components 

and claimed that these AMRs are consistent with the GALL Report. 

The staff audited and reviewed the information in the LRA. The staff did not repeat its review of 

the matters described in the GALL Report; however, the staff did verify that the material 

presented in the LRA was applicable and that the applicant identified the appropriate GALL 

Report AMRs. 
Aging Management Review Results 

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The staff reviewed the LRA to confirm that the applicant provided a brief description of the 

system, components, materials, and environments; stated that the applicable aging effects were 

reviewed and evaluated in the GALL Report; and identified those aging effects for the electrical 

and I&C components that are subject to an AMR. On the basis of its review, the staff 

determines that, for AMRs not requiring further evaluation, as identified in LRA Table 3.6.1, the 

applicant’s references to the GALL Report are acceptable and no further staff review is required. 

3.6.2.1.1 Loss of Material Due to General Corrosion 

LRA Table 3.6.1, item 3.6.1.9 addresses the loss of material due to general corrosion of MEB 

enclosure assemblies. The LRA credits the MEB Program. The GALL Report recommends 

AMP XI.S6, “Structures Monitoring Program,” to manage the aging effects for these 

components. The associated AMR item cites generic Note E, indicating that the LRA AMR is 

consistent with the GALL Report item for material, environment and aging effect, but credits a 

different AMP. 

For those items with generic Note E, the GALL Report recommends the Structures Monitoring 

Program, which recommends the use of visual inspections. In its review of components 

associated with item 3.6.1.9, for which the applicant cited generic Note E, the staff noted that 

the MEB Program proposes to manage the aging of the MEB enclosure assemblies using visual 

inspection of these components for evidence of degradation. SER Section 3.0.3.1.14 

documents the staff’s evaluation of the MEB AMP. The staff finds that using visual inspection 

as described in the Metal-Enclosed Bus Inspection Program is acceptable to inspect the outside 

of metal enclosed bus enclosure assemblies for loss of material due to general corrosion. 

The staff concludes that the applicant has demonstrated that it will adequately manage the 

effects of aging of these components so that their intended functions will remain consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.6.2.1.2 Hardening and Loss of Strength Due to Elastomer Degradation 

LRA Table 3.6.1, item 3.6.1.10 addresses the effects of hardening and loss of strength of 

elastomers. The LRA credits the MEB Program. The GALL Report recommends XI.S6, 

“Structures Monitoring Program,” to manage the aging effects for these components. The 

associated AMR item cites generic Note E, indicating that the LRA AMR is consistent with the 

GALL Report item for material, environment and aging effect, but credits a different AMP. 

For those items with generic Note E, the GALL report recommends the Structures Monitoring 

Program, which recommends the use of visual inspections. In its review of components 

associated with item 3.6.1.10, for which the applicant cited generic Note E, the staff noted that 

the MEB Program proposes to manage the aging of the MEB enclosure assemblies using visual 

inspection and flexing of the elastomer, as described in MEB Program. SER Section 3.0.3.1.14 

documents the staff’s evaluation of this AMP. The staff finds that using visual inspection and 

flexing, as described in the MEB Inspection Program, is acceptable to inspect the MEB 

elastomer for degradation. 

The staff concludes that the applicant has demonstrated that it will adequately manage the 

effects of aging of these components so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3). 

3.6.2.2 Aging Management Review Results Consistent with the Generic Aging Lessons 

Learned Report for Which Further Evaluation Is Recommended 

In LRA Section 3.6.2.2, the applicant further evaluates aging management, as recommended by 

the GALL Report, for the electrical and I&C components and provides information concerning 

how it will manage the following aging effects: 
Aging Management Review Results 

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 electrical equipment subject to EQ 

 degradation of insulation quality due to salt deposits or surface contamination and loss 

of material due to mechanical wear 

 loss of material due to wind-induced abrasion and fatigue, loss of conductor strength due 

to corrosion, and increased resistance of connection due to oxidation or loss of pre-load 

 QA for aging management of nonsafety-related components 

For component groups evaluated in the GALL Report, for which the applicant claimed 

consistency with the report and for which the GALL Report recommends further evaluation, the 

staff reviewed the corresponding AMRs identified in LRA Table 3.6.1 as items 3.6.1.11 

and 3.6.1.12. The staff also reviewed the applicant’s evaluation to determine if it adequately 

addressed the issues. In addition, the staff reviewed the applicant’s further evaluations against 

the criteria contained in SRP-LR Section 3.6.2.2. The staff’s review of the applicant’s further 

evaluations follows. 

3.6.2.2.1 Electrical Equipment Subject to Environmental Qualification 

In LRA Section 3.6.2.3, “Environmental Qualification of Electrical and Instrumentation and 

Control Equipment,” the applicant states EQ is a TLAA, as defined by 10 CFR 54.3. TLAAs are 

required to be evaluated in accordance with 10 CFR 54.21. SER Section 4.4, “10 CFR 50.49 

Thermal, Radiation, and Cyclical Aging Analyses” documents the staff’s review of the 

applicant’s evaluation of this TLAA. 

3.6.2.2.2 Degradation of Insulator Quality Due to Salt Deposits or Surface Contamination and 

Loss of Material Due to Mechanical Wear 

LRA Section 3.6.2.2.2 addresses degradation of insulator quality due to salt deposits or surface 

contamination and loss of material due to mechanical wear. The applicant states that PVNGS is 

located in an area where the outdoor environment is not subject to industry air pollution or salt 

spray. Contamination build-up on the high-voltage insulators is not a problem due to sufficient 

rainfall in the spring and summer washing the insulators. Additionally, there is no salt spray at 

the plant since the plant is not located near the ocean. The degradation of insulator quality in 

the absence of salt deposits and surface contamination is not an AERM at PVNGS. The 

applicant further stated that the transmission conductors are designed and installed so that they 

do not swing significantly and cause wear due to wind-induced abrasion and fatigue. The 

applicant concluded that loss of material due to wind-induced abrasion and fatigue is not an 

applicable AERM. 

The staff reviewed LRA Section 3.6.2.2.2 against SRP-LR Section 3.6.2.2.2, which states that 

degradation of insulator quality due to salt deposits or surface contamination may occur in 

high-voltage insulators. The GALL Report recommends further evaluation of plant-specific 

AMPs for plants at locations of potential salt deposits or surface contamination (e.g., near salt 

water bodies or industrial pollution). Loss of material due to mechanical wear caused by wind 

on transmission conductors may occur in high-voltage insulators. The GALL Report 

recommends further evaluation of a plant-specific AMP to ensure that these aging effects are 

adequately managed. 

The staff noted various airborne materials such as dust, salt, and industrial effluents can 

contaminate insulator surfaces. However, the buildup of surface contamination is gradual and, 

in most areas, rain washes away such contamination; the glazed insulator surface aids this 

contamination removal. Surface contamination can be a problem in areas where the greatest 

concentration of airborne particles is prevalent, such as near facilities that discharge soot or 

near the seashore where there is salt spray. Since PVNGS is not located near facilities that 

discharge soot or near the seashore, the rate of contamination buildup on the insulators is not 
Aging Management Review Results 

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significant. However, the applicant did not address plant-specific operating experience with 

high-voltage insulator failures relating to surface contamination. 

In a letter dated February 19, 2010, the staff issued RAI 3.6.2.2.2-1 asking the applicant to 

review plant-specific operating experience to confirm that there have been no failures of 

high-voltage insulators due to surface contamination. In response to the staff’s request, in a 

letter dated March 24, 2010, the applicant stated that the transmission system owner, Salt River 

Project, had not identified any documented operating experience failures of high-voltage 

insulators within the scope of license renewal due to surface contamination. A search of 

documented operating experience identified the following three high-voltage bushing flashovers 

that resulted in unit trips: 

(1) July 31, 1988—B Phase, Unit 3 

(2) November 14, 1991—A Phase, Unit 3 

(3) March 1, 1996—C Phase, Unit 1 

The applicant also stated that during the initial evaluation of the flashovers, contamination levels 

were reviewed and found to be minimal such that there was little risk of contamination-induced 

flashover. The applicant further stated that subsequent additional evaluation of the flashovers 

concluded that the flashovers were due to the tilt angle of the bushings. Booster sheds were 

added to channel water away from the bushings during heavy rain; there have not been repeat 

flashovers. 

The staff finds the applicant’s response acceptable because the applicant reviewed its 

plant-specific operating experience and confirmed that there have been no failures of 

high-voltage insulators due to surface contamination. The staff accepts the applicant’s 

conclusion that the flashover events were not caused by insulator contamination, but due to 

high conductivity water that channeled between the bushings in heavy rain due to the tilt angle 

of the bushing. The applicant added booster sheds to channel water away from the surface of 

the bushings; this design change prevents a water path to the insulators. Based on its review, 

the staff determined that surface contamination is not a significant AERM for the high-voltage 

insulators. 

The staff noted that mechanical wear is an aging effect for strain and suspension insulators as 

they are subject to movement. Movement of the insulators can be caused by wind blowing the 

supported transmission conductor, causing it to swing from side to side. If this swinging is 

frequent enough, it can cause wear in the metal contact point of the insulator string and 

between an insulator and supporting hardware. Although this wear is possible, industrial 

experience has shown that the transmission conductors do not normally swing and that when 

they do, in a substantial wind, they do not continue to swing for very long once the wind has 

subsided. 

Transmission conductors at PVNGS are designed and installed not to swing significantly and 

not to wear due to wind-induced abrasion and fatigue. However, the applicant did not address 

plant-specific operating experience with high-voltage insulator loss of material due to wear. In a 

letter dated February 19, 2010, the staff issued RAI 3.6.2.2.2-2 asking the applicant to review its 

operating experience to identify if wear has occurred in high-voltage insulators and transmission 

conductors. In response to the staff’s request, in a letter dated March 24, 2010, the applicant 

stated that it and the Salt River Project have not identified any documented operating 

experience of high-voltage insulators and transmission conductors within the scope of license 

renewal associated with loss of material due to wear that has resulted in a loss of intended 

function. The staff finds the applicant response acceptable because the applicant has reviewed 

its documented plant-specific operating experience and confirmed that there has been no failure 

of high-voltage insulators and transmission conductor due to loss of material due to wear. 
Aging Management Review Results 

 3-335 

Based on its review, the staff determined that loss of material due to wear is not a significant 

AERM. 

Based on the discussed above, the staff concludes that the applicant has met the SRP-LR 

Section 3.6.2.2.2 criteria. The staff determines that that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended functions will be maintained consistent with the CLB during the 

period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.6.2.2.3 Loss of Material Due to Wind-Induced Abrasion and Fatigue, Loss of Conductor 

Strength Due to Corrosion, and Increased Resistance of Connection Due to 

Oxidation or Loss of Pre-Load 

LRA Section 3.6.2.2.3 addresses loss of material due to wind-induced abrasion and fatigue, loss 

of conductor strength due to corrosion, and increased resistance of connection due to oxidation 

or loss of pre-load. 

In LRA Section 3.6.2.2.3, the applicant stated that industry experience has shown that 

transmission conductors are designed and installed not to swing significantly and cause wear 

due to wind-induced abrasion and fatigue. Therefore, the applicant concluded that loss of 

material due to wind-induced abrasion and fatigue is not an applicable AERM for the period of 

extended operation. 

The applicant stated that the most prevalent mechanism contributing to loss of conductor 

strength of an aluminum conductor steel reinforced (ACSR) transmission conductor is corrosion, 

which includes corrosion of the steel core and aluminum strand pitting. The applicant further 

stated the following: 

ACSR conductor degradation begins as a loss of zinc from the galvanized steel 

core wires. Corrosion rates depend largely on air quality, which involves 

suspended particles in the air, sulfur dioxide concentration, rain, fog chemistry, 

and other weather conditions. The PVNGS outdoor environment is not subject to 

industry air pollution or saline environment that would cause significant corrosion 

of the transmission conductors. 

The National Electrical Safety Code (NESC) requires that tension on installed 

conductors be a maximum of 60 percent of the ultimate conductor strength. The 

NESC also sets the maximum tension a conductor must be designed to 

withstand heavy load requirements, which includes consideration of ice, wind, 

and temperature. 

At PVNGS, the ACSR transmission conductors are 2-2156 KCMIL per phase 

with a core of 19 steel strands having ultimate conductor strength of 60,300 

pounds-force. The PVNGS ACSR transmission conductors within the scope of 

license renewal are installed so that conductor tension does not exceed 18,000 

pounds-force at the NESC heavy loading condition (30 percent of the ultimate 

conductor strength). 

The applicant also stated that tests performed by Ontario Hydroelectric on ACSR transmission 

conductors with a core of 7 steel strands averaging 70–80 years old, showed a 30-percent loss 

of ultimate conductor strength due to corrosion. Assuming a 30-percent loss of ultimate 

conductor strength (18,090 pounds-force) due to corrosion over 60 years, the PVNGS ACSR 

transmission conductors have adequate design margin to offset the loss of strength due to 

corrosion and still meet the NESC requirement of not exceeding 60 percent of the ultimate 

conductor strength [(60,300-18,090)x60%=25,326]. The applicant concluded that corrosion is 

not a credible aging effect that requires management for the period of extended operation. 
Aging Management Review Results 

 3-336 

The applicant stated that, at the time of installation, it treated transmission conductor and 

switchyard bus connections with corrosion inhibitors to avoid connection oxidation and torqued 

to avoid loss of pre-load. Further, the applicant stated the following: 

Based on temperature data in the UFSAR Chapter 2.3, the transmission 

connections and switchyard bus does not experience thermal cycling. The 

transmission connections and switchyard bus are subject to average monthly 

temperatures ranging from 105 oF in July and August to 38 oF in January with 

minimal ohmic heating. Therefore, increased resistance of connections due to 

oxidation or loss of pre-load is not an aging effect requiring management for the 

period of extended operation. These connections are periodically evaluated via 

thermography as part of the preventive maintenance activities. The periodic 

thermography will continue into the period of extended operation. 

The staff reviewed LRA Section 3.6.2.2.3 against the criteria in SRP-LR Section 3.6.2.2.3, which 

states that loss of material due to wind-induced abrasion and fatigue, loss of conductor strength 

due to corrosion, and increased resistance of connection due to oxidation or loss of pre-load 

could occur in transmission conductors and connections and in switchyard bus and connections. 

The GALL Report recommends further evaluation of a plant-specific AMP to ensure that this 

aging effect is adequately managed. 

The staff noted that transmission conductors do not normally swing and that when they do, due 

to a substantial wind, they do not continue to swing for very long once the wind has subsided. 

Wind loading that can cause a transmission line to vibrate is considered in the design and 

installation. In addition, the sections of transmission conductors in the scope of license renewal 

are short spans connecting the switchyard to the startup transformers, and the surface areas 

exposed to wind loads are not significant. Furthermore, the applicant indicated that it has 

reviewed the plant-specific operating experience and did not identify issue of loss of material 

due to wear for transmission conductors. Based on its review, the staff determined that loss of 

material of transmission conductors due to vibration is not an AERM. 

The staff reviewed the testing program performed by Ontario Hydroelectric to determine 

whether PVNGS transmission conductors have adequate design margin to perform their 

intended function during the extended period of operation. The study showed about 30-percent 

loss of conductor strength of an 80-year-old ACSR conductor due to corrosion. The NESC 

requires that tension on installed conductors be a maximum of 60 percent of the ultimate 

conductor strength. The NESC also sets the maximum tension; a conductor must be designed 

to withstand under heavy load requirements, which include consideration of one-half inch of 

radial ice and 4 pounds per square feet wind. 

The staff reviewed the requirements concerning the specific conductors included in the AMR. 

At PVNGS, the ACSR transmission conductors are 2,156 thousand circular mils. These 

transmission conductors have a core of 19 steel strands with conductor strength of 60,300 

pounds-force. These transmission conductors have 18,000 pounds-force of NESC heavy 

loading. With the loss of 30 percent conductor strength due to corrosion, the conductor strength 

would be 42,210 pounds force (60,300x0.7). 

The ratio between the heavy loading and the ultimate conductor strength, after losing 30 percent 

of conductor strength, would be approximately 43 percent. The ratio of heavy loading and the 

ultimate conductor strength is below the maximum 60 percent NESC requirement. Furthermore, 

the staff noted that the length of transmission conductors within the scope of license renewal is 

generally a short span. These transmission conductors connect the switchyard to the startup 

transformers, providing restoration of offsite power after an SBO event. The loading of these 

transmission conductors is much less than the calculated heavy loading of a long span 

transmission line. 
Aging Management Review Results 

 3-337 

The staff determined that with a 30 percent loss of conductor strength, there is still ample 

margin between the NESC requirements and the actual conductor strength. Based on this 

information, the staff determined that loss of conductor strength due to corrosion of transmission 

conductor is not a significant AERM for the period of extended operation. 

SRP-LR Section 3.6.2.2.3 states that loss of pre-load could occur in transmission and 

switchyard bus connections. EPRI TR 104213 states that an electrical connection must be 

designed to remain tight and maintain good conductivity through a large temperature range. 

Meeting this design requirement is difficult if the materials specified for the bolt and the 

conductor are different and have different rates of thermal expansion. For example, copper and 

aluminum bus materials expand faster than most bolting materials. If thermal stress is added to 

stresses inherent at assembly, the joint members or fasteners can yield. If deformation occurs 

during thermal loading (i.e., heatup), then when the connection cools, the joint will loosen. 

Increased temperature difference in electrical bolted joints is due to 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, then loose and 

failure prone joints will result. 

The applicant stated that the transmission connections and switchyard bus does not experience 

thermal cycling. The applicant also stated that the transmission connections and switchyard 

bus are subject to average monthly temperatures ranging from 38–105 degrees F with minimal 

ohmic heating. The applicant concluded that loss of pre-load is not an AERM for the period of 

extended operation. The thermal expansion, due to ohmic heating and thermal cycling, 

depends heavily on the load and not the average monthly temperature. 

In a letter dated February 19, 2010, the staff issued RAI 3.6.2.2.3-1 asking the applicant to 

justify why loss of pre-load is not an applicable AERM. In response to the staff’s request, in a 

letter dated March 24, 2010, the applicant stated that loss of pre-load of switchyard bus and 

connections is not applicable because procedures require that switchyard connections be 

assembled using a corrosion inhibitor, and connections are also torqued to avoid loss of 

pre-load. Additionally, switchyard conductor and bus connections are assembled with stainless 

steel Belleville washers to prevent loss of preload. The applicant further stated that the 

transmission system owner, Salt River Project, periodically performs infrared scans of 

switchyard equipment and connections, including before and after scans, to verify connector 

integrity for equipment undergoing maintenance. The applicant also stated that a search of 

operating experience identified no evidence of switchyard bus connection or transmission 

conductor connection loss of pre-load. 

The staff finds the applicant response acceptable because the use of Belleville washers on 

bolted electrical connections of dissimilar metals compensates for temperature changes, 

maintains the proper torque, and prevents loosening. This method of assembly is consistent 

with the good bolting practices recommended by industry guidelines (EPRI TR-104213, “Bolted 

Joint Maintenance & Application Guide”). Furthermore, the applicant reviewed its plant-specific 

operating experience and did not find any evidence of switchyard bus and transmission 

conductor connection failures due to loss of pre-load. Based on its review, the staff finds that 

loss of pre-load of switchyard bus and transmission conductor connections is not an applicable 

AERM. 

Based on the programs identified above, the staff concludes that the applicant has met the 

SRP-LR Section 3.6.2.2.3 criteria. For those line items that apply to LRA Section 3.6.2.2.3, the 

staff determines that that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3). 
Aging Management Review Results 

 3-338 

3.6.2.2.4 Quality Assurance for Aging Management of Nonsafety-Related Components 

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA program. 

3.6.2.3 Aging Management Review Results Not Consistent with or Not Addressed in 

the Generic Aging Lessons Learned Report 

In LRA Table 3.6.2-1, the staff reviewed additional details of the AMR results for material, 

environment, AERM, and AMP combinations not consistent with, or not addressed in, the GALL 

Report. The applicant indicated, via Notes F–J that the combination of component type, 

material, environment, and AERM does not correspond to a line item in the GALL Report. The 

applicant provided further information about how it will manage the aging effects. 

For component type, material, and environment combinations not evaluated in the GALL 

Report, the staff reviewed the applicant’s evaluation to determine if 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. The 

following section documents the staff’s evaluation. 

Metal Enclosed Bus (Enclosure)—Summary of Aging Management Review—License Renewal 

Application Table 3.6.2-1. In LRA, Table 3.6.2-1 under MEB (Enclosure), the applicant 

indicated that it will use the MEB Program to manage the loss of material for aluminum bus 

enclosures. The applicant included Note J, which states that neither the component nor the 

material and environment combination is available in the GALL Report. The staff noted that the 

MEB Program proposes to manage the aging of the MEB enclosure assemblies through visual 

inspections of these components for evidence of loss of material. SER Section 3.0.3.1.14 

documents the staff’s evaluation of the MEB AMP. The staff finds that using visual inspections, 

as described in the MEB Program, is acceptable for inspecting the outside of aluminum bus 

enclosure assemblies for loss of material due to general corrosion. 

3.6.3 Conclusion 

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the electrical and I&C components 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). 

3.7 Conclusion for Aging Management Review Results

The staff reviewed the information in LRA Section 3, “Aging Management Review Results,” and 

LRA Appendix B, “Aging Management Programs.” On the basis of its review of the AMR results 

and AMPs, the staff concludes that the applicant has demonstrated that the aging effects will be 

adequately managed so that the intended functions will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the applicable UFSAR supplement program summaries and concludes that the 

supplement adequately describes the AMPs credited for managing aging, as required by 10 

CFR 54.21(d). 

With regard to these matters, the staff concludes that there is reasonable assurance that the 

applicant will continue to conduct the activities authorized by the renewed licenses in 

accordance with the CLB, and any changes made to the CLB, in order to comply with 10 CFR 

54.21(a)(3), are in accordance with the Atomic Energy Act of 1954, as amended, and NRC 

regulations. 
 

 4-1 

4.0 TIME-LIMITED AGING ANALYSES 

4.1 Time-Limited Aging Analyses

4.1.1 Identification of Time-Limited Aging Analyses 

This section of the safety evaluation report (SER) addresses the identification of time-limited 

aging analyses (TLAAs). In license renewal application (LRA) Sections 4.2–4.8, Arizona Public 

Service Company (APS) (the applicant) addressed the TLAAs for Palo Verde Nuclear 

Generating Station, Units 1, 2, and 3 (PVNGS). SER Sections 4.2–4.9 document the review of 

the TLAAs conducted by the U.S. Nuclear Regulatory Commission (NRC) staff (the staff). 

TLAAs are certain plant-specific safety analyses that involve time-limited assumptions defined 

by the current operating term. Pursuant to Title 10 of the Code of Federal Regulations

(10 CFR), Section 54.21(c)(1), applicants must list TLAAs. The definition of a TLAA is found in 

10 CFR Part 54.3, “Definitions.” 

In addition, pursuant to 10 CFR 54.21(c)(2), applicants must list existing plant-specific 

exemptions granted in accordance with 10 CFR 50.12, “Specific Exemptions,” based on TLAAs. 

For any such exemptions, the applicant must evaluate and justify the continuation of the 

exemptions for the period of extended operation. 

4.1.2 Summary of Technical Information in the Application 

To identify TLAAs, the applicant evaluated calculations against the six criteria specified in 

10 CFR 54.3. The applicant said that it 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. In LRA Table 4.1-1, “List of 

TLAAs” the applicant listed the following applicable TLAAs: 

 Reactor vessel neutron embrittlement analysis 

 Metal fatigue analysis 

 Environmental qualification (EQ) of electrical equipment 

 Concrete containment tendon prestress 

 Concrete liner plate, equipment hatch and personnel airlocks, penetrations, and polar 

crane brackets 

 Plant-specific TLAA 

As required by 10 CFR 54.21(c)(2), the applicant must list all exemptions granted in accordance 

with 10 CFR 50.12 that are based on TLAAs and evaluated and justified for continuation 

through the period of extended operation. The LRA states that the applicant reviewed each 

active exemption to determine whether it was based on a TLAA. The applicant stated that it had 

no TLAA-based exemptions. 

4.1.3 Staff Evaluation 

LRA Table 4.1-1 lists the TLAAs the applicant identified as being applicable to PVNGS. The 

staff reviewed the information to determine whether the applicant had provided sufficient 

information as required by 10 CFR 54.21(c)(1) and 10 CFR 54.21(c)(2). As defined in 

10 CFR 54.3, TLAAs meet the following six criteria: 
Time-Limited Aging Analyses 

 4-2 

(1) Involve systems, structures, and components within the scope of license renewal, under 

10 CFR 54.4(a) 

(2) Consider the effects of aging 

(3) Involve time-limited assumptions defined by the current operating term (for example, 

40 years) 

(4) 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 

systems, structures, and components to perform its intended functions, pursuant to 

10 CFR 54.4(b) 

(6) Are contained or incorporated by reference in the CLB 

The staff noted that the applicant assembled the list of potential TLAAs using the following 

regulatory and industry documents: 

 The NUREG-1800, “Standard Review Plan for Review of License Renewal Applications 

for Nuclear Power Plants,” Chapter 4 

 Nuclear Energy Institute 95-10, “Industry Guideline for Implementing the Requirements 

of 10 CFR 54, the License Renewal Rule” 

 The 10 CFR Part 54 Final Rule “Statement of Considerations” 

 Prior LRAs 

 Plant-specific document reviews and interviews with plant personnel 

The staff finds the applicant’s use of these documents to compile a list of potential TLAAs 

reasonable since the applicant used all available resources from the staff, Nuclear Energy 

Institute, past LRAs, and its own plant-specific review. 

Using the documents listed above, the applicant reviewed its CLB documents to determine if the 

design or analysis feature of each potential TLAA, in fact, exists in the licensing basis for the 

site. The applicant also determined if additional unit-specific TLAAs exists. The applicant 

reviewed the following documents to formulate the list of potential unit-specific TLAAs: 

 UFSAR 

 Technical Specifications (TS) 

 The SERs for the original operating licenses 

 Subsequent Safety Evaluations (SEs) 

 APS and NRC docketed licensing correspondence 

In accordance with 10 CFR 54.21(c), those potential TLAAs that meet all six criteria defined in 

10 CFR 54.3(a) are actual TLAAs and require a disposition. The applicant reviewed the 

six criteria based on information in the CLB source documents (as listed above), and from other 

source documents for the potential TLAAs to include the following: 

 The Standard Safety Analysis Report for CE System 80 

 Vendor, NRC-sponsored, and licensee topical reports 

 Design calculations 

 Code stress reports or code design reports 

 Drawings 

 Specifications 
Time-Limited Aging Analyses 

 4-3 

The staff finds the applicant’s approach in determining TLAA reasonable because the applicant 

has performed a comprehensive search through its CLB, based on available staff and industry 

guidance and experience, and has reviewed these potential TLAAs against the six criteria of a 

TLAA as defined in 10 CFR 54.3(a). 

The applicant provided a list of potential TLAAs from NUREG-1800, “Standard Review Plan for 

Review of License Renewal Applications for Nuclear Power Plants,” (SRP-LR) dated 

September 2005. The applicant listed those potential TLAAs in LRA Table 4.1-2, “Review of 

Analyses Listed in NUREG-1800, Table 4.1-2.” The applicant further provided a list of its 

plant-specific TLAAs in LRA Table 4.1-1. 

The staff performed an independent search of exemptions in effect during the staff’s review of 

the LRA by reviewing the operating license and conducting a search of the NRC’s Agencywide 

Documents Access and Management System. The staff found five exemptions in effect, with 

one scheduled to be issued by the staff on July 31, 2010. Three of these exemptions have 

been granted since submittal of the LRA. The staff confirmed that none of these exemptions 

are based on a TLAA. 

Based on the information provided by the applicant regarding the results of the applicant’s 

search of the CLB to identify these exemptions, and the staff’s independent search, the staff has 

determined, in accordance with 10 CFR 54.21(c)(2), that there are no TLAA-based exemptions 

which have been justified for continuation through the period of extended operation. 

4.1.3.1 Evaluation of the Applicant’s Identification of Time-Limited Aging Analyses 

4.1.3.1.1 Absence of Time-Limited Aging Analyses for Metal Corrosion Allowances and 

Corrosion Effects 

Summary of Technical Information in the Application. SRP-LR Table 4.1-3 lists examples of 

potential plant-specific TLAAs. This table includes “metal corrosion allowance” as a possible 

TLAA. In response to this table entry, the applicant provided LRA paragraph 4.7.2, “Absence of 

TLAAs for Metal Corrosion Allowances and Corrosion Effects.” In this paragraph, the applicant 

states that, other than the issues described in LRA paragraphs 4.7.4 and 4.7.5, which are 

addressed in SER Sections 4.7.4 and 4.7.5, it “found no description of time-dependant corrosion 

allowances, rates, or corrosion-dependent design lives of pressure vessels, system 

components, piping, or metal containment components” in its review of the CLB. Based on this 

statement, the applicant implies that TLAAs are not required. 

Staff Evaluation and Conclusion. In its review of LRA paragraph 4.7.2, the staff concluded that 

the applicant intended to state that TLAAs for metal corrosion allowances were not required by 

10 CFR 54.3(a)(6), which states that they are not contained or incorporated by reference in the 

CLB. In evaluating the applicant’s assertion, the staff conducted a search of the applicant’s 

UFSAR and TS. The staff also considered additional documents such as NRC general 

communications and American Society of Mechanical Engineers (ASME) Code requirements, 

which could incorporate a requirement in the CLB for a corrosion allowance TLAA. Following 

this review, the staff finds no reason to disagree with the applicant’s assertion that calculations 

related to corrosion allowances, other than those described in paragraphs 4.7.4 and 4.7.5, are 

not included in the applicant’s CLB. The staff concludes that the absence of a TLAA, pursuant 

to 10 CFR 54.21, for metal corrosion allowances and corrosion effects is acceptable because 

the requirement of 10 CFR 54.3(a)(6) is not met. 

4.1.3.1.2 Absence of a Time-Limited Aging Analysis for Reactor Vessel Underclad Cracking 

Analyses 

Summary of Technical Information in the Application. In LRA Section 4.7.6, the applicant stated 

that the reactor pressure vessel (RPV) underclad cracking has been addressed by the choice of 

material and weld cladding processes that are designed to avoid these defects, consistent with 
Time-Limited Aging Analyses 

 4-4 

regulatory guide (RG) 1.43, “Control of Stainless Steel Weld Cladding of Low-Alloy Steel 

Components.” The applicant stated further that they have not discovered any cracks. 

The vessel shell and head plates are constructed of SA-533, Grade B, Class 1 Steel, which is 

immune to underclad cracking. The RPV nozzles and flange are constructed of susceptible 

material SA-508, but these components were clad with low-heat-input processes, which are not 

known to cause underclad cracking. The determination that the RPV material is not susceptible 

to underclad cracking is not based on time-dependent analyses and, therefore, the applicant 

states underclad cracking is not a TLAA. 

Staff Evaluation and Conclusion. The staff noted that underclad cracks have been reported to 

exist only in SA-508, Class 2, RPV forgings manufactured with a coarse grain microstructure 

and clad by high heat input, submerged arc welding processes. Since high heat input, 

submerged arc welding processes were not used for the fabrication of the cladding over their 

RPV nozzles and flange, the staff agrees with the applicant that RPV underclad cracking is not 

an issue and is not a TLAA because the requirement of 10 CFR 54.3(a)(4) is not met. 

4.1.3.1.3 Absence of a Time-Limited Aging Analysis for a Reactor Coolant Pump Flywheel 

Fatigue Crack Growth Analysis 

Summary of Technical Information in the Application. In LRA Section 4.7.7, the applicant stated 

that the reactor coolant pump (RCP) flywheel burst is the subject of RG 1.14, “Reactor Coolant 

Pump Flywheel Integrity” and its predecessor, Safety Guide 14. The CLB commits to 10-year 

interval inspections in accordance with Safety Guide 14, Revision 0, Position c.4.b. 

PVNGS relies on flywheel design, material, fabrication, and the periodic inspections in 

accordance with Safety Guide 14, Position c.4.b. No crack growth analysis or time-dependent 

probabilistic failure assessment has been performed for the flywheels, either to extend the 

inspection interval for less than the design life or to support a safety determination for the design 

life. Therefore, no TLAA exists. 

Staff Evaluation and Conclusion. The applicant stated that “[t]he current PVNGS licensing basis 

commits to the 10-year-interval inspections of Safety Guide 14 (Rev. 0) Position c.4.b.” 

It further stated that no crack growth analysis has been performed for the flywheels; therefore, 

no TLAA exists. For the period of extended operation, RG 1.14, Rev. 1 should be used and 

referenced unless the RCP inspection in the CLB is independent of the underlying stress and 

fracture mechanics analyses of the flywheels, which may contain a time-limited analysis such as 

a fatigue analysis or a fatigue crack growth analysis. Hence, the staff issued RAI 4.7.7-1 for 

clarification. 

The applicant’s response to RAI 4.7.7-1 confirmed that, “[t]he stress and fracture mechanics 

analysis in the RCP flywheel design report does not contain any fatigue or time-dependent 

fatigue crack evaluations. The design report includes an evaluation of cracks that will permit 

either a ductile or brittle burst at overspeed.” This statement clarified that the applicant’s RCP 

flywheel evaluation in the CLB is not a TLAA. However, if indications from the past RCP 

flywheel inspections were detected and evaluated for continued operation for a limited time, 

these flaw evaluations are very likely to be TLAAs. Hence, the staff issued RAI 4.7.7-2. 

The applicant’s response to RAI 4.7.7-2 confirmed that, “APS has performed ultrasonic test 

examinations approximately every three years and eddy current test examinations every 

10 years in accordance with the Inservice Inspection (ISI) Program on the flywheel of each of 

the RCPs. No indications of degradation have been found in any of the RCP flywheels, and, 

therefore, no flaw evaluations have been performed.” Hence, the staff concludes that the 

applicant’s RCP flywheel evaluation is not a TLAA because the requirement of 

10 CFR 54.3(a)(6) is not met. Also, there is no TLAA on flaw evaluations for detected flaws in 

the RCP flywheels because no indications of degradation have been found in them. 
Time-Limited Aging Analyses 

 4-5 

4.1.3.1.4 Absence of Time-Limited Aging Analyses in Fatigue Crack Growth Assessments 

and Fracture Mechanics Stability Analyses for the Leak-Before-Break Elimination of 

Dynamic Effects of Primary Loop Piping Failures 

Summary of Technical Information in the Application. The staff has approved the 

Leak-Before-Break (LBB) application for the primary coolant loop piping in the three PVNGS 

units. The approved LBB application permits elimination of the postulated large breaks in the 

main reactor coolant loops and their jet and pipe whip effects and the removal of jet barriers and 

whip restraints. The containment pressurization and equipment qualification analyses retain the 

large-break assumptions. NUREG-0857, “Safety Evaluation Report Related to the Operation of 

PVNGS Units 1, 2, and 3,” November 1981, with Supplements 1–12, documents NRC’s 

approval of the LBB application. The applicant claims that the fatigue crack growth analysis and 

the fracture mechanics stability analyses are not TLAAs. 

Staff Evaluation. The staff reviewed LRA Section 4.3.2.15 to verify, pursuant to 10 CFR 54.3(a), 

that the fatigue crack growth assessments and fracture mechanics stability analyses for the LBB 

elimination of dynamic effects of primary piping failures are not TLAAs. 

By letter dated October 11, 1984, the staff approved the LBB analysis for the main reactor 

coolant loops, including the hot, cold, and crossover legs in each of the PVNGS units. 

In general, the two TLAA issues regarding LBB evaluations are the fatigue crack growth 

analysis and the flaw evaluation of the cast austenitic stainless steel (CASS). The fatigue crack 

growth analysis postulates several representative flaws in high stress locations and calculates 

their final crack size using transient cycles to determine their acceptability at the end of the 

licensed life. The transient cycles are time-dependent; therefore, the fatigue crack growth 

analysis is usually considered a TLAA. CASS experiences thermal aging embrittlement as it 

ages, which reduces its fracture toughness. Fracture toughness is a material property that 

resists crack initiation and propagation; therefore, the use of CASS material usually involves 

a TLAA. 

The applicant stated that the primary coolant loop piping does not contain CASS. Therefore, 

thermal aging embrittlement of CASS is not a TLAA issue. The staff verified that there is no 

CASS in the primary coolant loop piping and, therefore, finds this acceptable. The following 

evaluation provides the staff’s determination of the fatigue crack growth analysis. 

Fatigue Crack Growth. Section 3.6.3 of the SRP-LR, paragraph III.10 states that, “[t]he reviewer 

should determine that the candidate piping does not have a history of fatigue cracking or failure. 

An evaluation to ensure that the potential for pipe rupture due to thermal and mechanical 

induced fatigue is unlikely should be performed.” 

In a letter dated January 14, 2010, the staff issued RAI 4.3.2.15-1 asking the applicant to 

demonstrate that fatigue is not an active degradation mechanism during the period of extended 

operation and that the original LBB evaluation is valid for the extended period of operation. By 

letters dated March 1 and May 21, 2010, the applicant responded that within the context of 

SRP-LR Section 3.6.3, fatigue is not an active degradation mechanism for the following 

reasons: 

 Fatigue crack growth analyses for the proposed licensed operating period are 

acceptable (in this case, including the period of extended operation). The acceptability 

of the LBB fatigue crack growth analyses for the licensed operating period including the 

period of extended operation is addressed below. 

 Crack stability analyses are acceptable and, if time-dependent, are acceptable for the 

proposed licensed operating period (in this case, including the period of extended 

operation). The LBB crack stability analyses are not time-dependent and are discussed 

below. 
Time-Limited Aging Analyses 

 4-6 

 Material fracture toughness parameters, including effects of long-term thermal aging are 

acceptable. The LBB crack stability analyses include appropriate material toughness 

parameters, which are not time-dependent and are discussed below. 

 There are no indications of pressurized water stress corrosion cracking, erosion, 

erosion-corrosion, water hammer, creep, other cracking, leakage, or other evidence of 

actual or incipient fatigue or failures that would indicate that the LBB analysis is invalid 

within the scope of the piping exempted from crack postulation by the LBB analysis of 

NRC Mechanical Engineering, Branch Technical Position MEB-3.1, Postulated Rupture 

Locations for Fluid System Piping Inside and Outside of Containment, as part of 

Standard Review Plan Section 3.6.2 (Note: MEB-3.1 has been renamed Branch 

Technical Position BTP 3-4, Revision 2 and is a stand-alone document in Chapter 3 of 

the Standard Review Plan). No such indications or failures have been observed in the 

scope of PVNGS LBB piping. 

The technical basis for the LBB evaluation is provided in the CE topical report entitled “Leak 

Before Break Evaluation of the Main Coolant Loop Piping of a CE Reactor Coolant System.” 

This report was provided as an attachment to a letter dated June 14, 1983 (also, Revision 1 of 

the CE topical report was submitted to the staff as an attachment to a letter dated 

December 23, 1983). Section 3 of the topical report describes fatigue calculations to 

demonstrate the acceptability of fatigue crack growth for various postulated flaws, which 

demonstrates that fatigue is not an active degradation mechanism of concern. One of these 

calculations, for a relatively small flaw of 1 inch in depth and 8 inches in length, demonstrates 

that the crack will not penetrate through wall for a very large number of cycles, principally 

heatup and cooldown cycles. 

The technical basis report for approval of LBB incorporates fatigue crack growth calculations 

that have a time basis (40 years) or consider numbers of cycles in the calculations. However, 

LRA Section 4.3.2.15 states that the LBB fatigue crack analyses are not TLAAs because the 

postulated fatigue cracks grow slowly and the fatigue evaluation does not depend on the design 

life. In RAI 4.3.2.15-1, the staff asked the applicant to provide technical basis to support the 

notion that the LBB evaluation is not a TLAA. 

By letter dated March 1, 2010, in response to RAI 4.3.2.15-1, the applicant stated that the 

acceptability of the LBB evaluation depends on a fracture mechanics crack stability analysis and 

a fatigue crack growth analysis. By letter dated May 21, 2010, the applicant provided additional 

clarification to its response to RAI 4.3.2.15-1, as described below. 

Crack Stability Analysis - The applicant postulated three semi-elliptical cracks (0.5 x 39 inches, 

1.0 x 34 inches, and 0.35 x 45.5 inches) for the crack stability analysis. For the large crack 

sizes postulated, the applicant calculated that through-wall leaks would occur at 21, 4, and 38 

years, respectively; determined that preferential growth would be in the radial direction, and 

determined that the rate of growth between a through-wall detectable leak and a critical crack 

size would be acceptable for defects much larger than any anticipated actual initial defect. The 

staff noted that the LBB analysis is based on existence of a leaking flaw in the pipe and the pipe 

is allowed to leak. The above crack stability analysis shows when a leak will occur based on 

postulated flaws as part of the applicant’s sensitivity study for the LBB evaluation. 

The applicant stated that two crack stability criteria have been used to assess the likelihood that 

a crack with opening stress intensity K, or a J-integral at the tip would remain stable. The 

applicant contended that both methods are independent of time. The first involves the use of 

linear-elastic fracture mechanics fracture toughness KIc which is a measure of the material’s 

resistance to fracture. A KI value below which there is no crack extension is Kc. As a practical 

consideration, KIc is a measure of the stress intensity at which fracture takes place. Its value 

has been empirically correlated to the material’s Charpy V-Notch test value using the 
Time-Limited Aging Analyses 

 4-7 

Rolfe-Novak-Barsom correlation that is independent of time. The second method involves the 

elastic-plastic crack instability theory using the J-integral crack tip parameter T, the tearing 

modulus, when the volume of plastically deformed material is appreciable. A TApplied value below 

which there is no crack extension is TMaterial. TMaterial is only a function of the J-integral, modulus 

of elasticity, E, and the material’s yield stress, Sy, and not time. The applicant concluded that all 

of these flaws will be acceptable at the end of 60 years. 

The applicant concluded that the fracture mechanics crack stability analysis is not 

time-dependent and, therefore, remains applicable for the period of extended operation. 

The staff agrees that the crack stability analysis is not a TLAA because the requirement of 

10 CFR 54.3(a)(3) is not met. 

Fatigue Crack Growth Analysis - The applicant postulated two cracks (8 x 18 inches and 

1 x 8 inches) for the fatigue crack growth calculations. The existing fatigue crack growth 

evaluation demonstrates that initially postulated cracks larger than those required by the LBB 

rule will remain within allowable sizes for an order of magnitude longer than the 40-year current 

licensed operating period. Since the safety determination supported by this evaluation does not 

depend on the design life, and, therefore, does not meet Criteria 3 and 5 of the 10 CFR 54.3(a) 

TLAA definition, the applicant did not classify this fatigue crack growth evaluation as a TLAA. 

The applicant stated further that since the safety determination supported by the existing fatigue 

crack growth evaluation is valid for several times the 60-year design life, it is valid for at least 

the period of extended operation. 

In Enclosure 2 of the May 21, 2010 letter, the applicant clarified the fatigue crack growth 

calculations. The applicant stated that a linear elastic fracture mechanics analysis was 

performed to determine the crack growth of the various postulated semi-elliptical shaped inner 

surface cracks in the reactor coolant system (RCS) main loop piping. The method of analysis is 

based on the ASME, Section Xl, Appendix A, subsurface flaw evaluation procedure, where the 

fatigue crack growth rate, da/dN, of the material is characterized in terms of the range of applied 

stress intensity factor, ΔK. 

This characterization is generally of the form, da/dN = C0 (ΔKI)

n

, which has been determined 

experimentally. The material constants for carbon steel fatigue crack growth in a water 

environment used by CE in their evaluation are as follows: 

n = 3.726 

C0 = 3.795 x 10-10

The applicant stated that the fatigue crack growth curve used in the evaluation also included 

upper-bound data to envelope the ASME Code Section Xl curve. From this method of stress 

intensity factor determination, the ΔKI level is calculated based on the crack size and loading 

conditions. Using a stepping procedure for the number of cycles of loading in a given time 

period, depth and length crack growth rates are calculated, and the corresponding change in 

crack size is determined as well as the time required to penetrate the entire pipe wall and 

produce a leak. The start-up and shutdown transient was found to be the greatest contributor to 

the usage factor for the main loop piping. A cyclic stress of 18 ksi, conservatively enveloping 

the start-up and shut down stress, was applied to the hypothetical flaws (1 x 8 inch and 

8 x 18 inches) in the circumferential direction in both the 42-inch diameter hot leg and 30-inch 

diameter cold leg piping. The applicant stated that the number of start-up and shutdown cycles 

necessary to cause a 1-inch deep crack from 8 to 18 inches long to grow through the pipe wall 

and leak is at least 3,000 to 8,000 cycles which is significantly greater than the 40 year design 

value of 500 cycles and the projected value of 213 actual cycles in 60 years. Thus the applicant 

stated that the partial through-wall cracks will not propagate through the entire pipe wall for 

more than 400 years. 
Time-Limited Aging Analyses 

 4-8 

The basis for the safety determination is, therefore, not that the crack will remain within an 

acceptable size within a 40-year design lifetime but, (1) that the rate of growth for any 

anticipated crack size is acceptable, even following wall penetration and detectable leakage, 

and (2) that initial defects larger than the ASME Code Section III initial inspection criteria will not 

grow through the pipe wall in several 40-year design lifetimes. 

The applicant determined the frequency of load application by assuming a uniform distribution of 

a typical 40-year set of CE design basis loading events over a 40-year life. LRA Table 4.3-3 

demonstrates that the rates of accumulation of transient cycles have remained less than those 

assumed as the basis for the LBB evaluation, with a few exceptions that have no significant 

effect on the bases for the LBB fatigue crack growth evaluation. Therefore, the basis of the 

fatigue crack growth analysis, the basis for the safety determination, and the conclusion of the 

safety determination will not change with an increase in the licensed operating period. The 

applicant concluded that the fatigue crack growth analyses, therefore, do not “...involve 

time-limited assumptions defined by the current operating term, for example, 40 years.” They 

are time-dependent, but for an indefinite period, and are, therefore, not time-limited. 

In a letter dated March 1, 2010, in response to RAI 4.3.2.15-1, the applicant stated that “...the 

Metal Fatigue aging management program is not implemented to monitor the transient cycles to 

confirm that the transient cycles used in the fatigue crack growth analyses for the LBB piping 

exceed the actual transient cycles because the existing LBB fatigue crack growth evaluation is 

valid for the period of extended operation...” The staff needed further clarification of the 

applicant’s determination that the transient cycles used in the fatigue crack growth analyses for 

the LBB piping do not need to be tracked by the applicant's enhanced metal fatigue AMP. In a 

May 19, 2010, conference call, the staff requested the applicant to verify and confirm that the 

transient cycles used in the fatigue crack growth calculation exceed and bound the actual 

operating transient cycles. 

In a letter dated May 21, 2010, the applicant submitted a follow-up response stating that the 

LBB analysis for the RCS main loop piping consisted of two bounding evaluations that remove 

the time dependency from the projected crack growth evaluation. In the fatigue crack growth 

evaluation, cracks larger than allowed by the ASME Code Section III initial inspection 

acceptance criteria would take 3,000 to 8,000 cycles of the most significant contributor to fatigue 

usage factor (start-up and shutdown) to propagate through the entire pipe wall. The 40-year 

design value for this transient is 500 cycles and the projected value for 60 years is 213 cycles. 

In the crack stability evaluation, cracks significantly larger than the ASME allowable were 

demonstrated to remain stable after leaking under the most severe loading, which is the safe 

shutdown earthquake. Therefore, given the results of the above sensitivity evaluations, the staff 

confirmed that the number of transient cycles accumulated over a 60-year period will not affect 

the results of the LBB evaluations and finds it acceptable that the metal fatigue program is not 

implemented to monitor the fatigue crack growth analyses for the LBB piping. 

The staff finds the applicant’s clarification acceptable because the analysis does not meet 

10 CFR 54.3(a)(3). The staff noted the analysis showed that the postulated flaws are 

acceptable for 8,000 transient cycles while the transient cycles expected through the period of 

extended operation is 213 cycles. The analysis does not meet 10 CFR 54.3(a)(3) criteria where 

the time-limited assumptions are defined by the current operating term, for example, 40 years. 

The staff’s concern in RAI 4.3.2.15-1 is resolved. 

Alloy 82/182 Dissimilar Metal Welds. Nickel-based Alloy 600/82/182 material in the pressurized 

water reactor (PWR) environment has been shown to be susceptible to primary water stress 

corrosion cracking (PWSCC). In RAI 4.3.2.15-3, the staff asked the applicant to identify any 

Alloy 82/182 weld metal and Alloy 600 components used in the LBB approved piping for both 

units. The staff also asked the applicant to discuss any measures (such as weld overlays or 

mechanical stress improvement) that have been or will be implemented to reduce the 
Time-Limited Aging Analyses 

 4-9 

susceptibility of PWSCC in the LBB piping components if it contains alloy 600/82/182 material. 

The staff also asked the applicant to discuss the inspection history and future inspection 

frequency of the Alloy 82/182 dissimilar metal butt welds. By letter dated March 1, 2010, in 

response to RAI 4.3.2.15-3, the applicant stated that no Alloy 82/182 weld metal or Alloy 600 

components remain in the main reactor coolant loops within the scope of the LBB analysis, 

except the branch, instrument, and resistance temperature detector (RTD) nozzle connections 

shown in Table 4.1-1 below. The applicant noted that none of the components in the table 

below have shown any degradation. 

Table 4.1-1. Alloy 82/182 Dissimilar Metal Welds Mitigation 

RC Loop Nozzle to: Welds Inspection Methods Mitigation Strategy 

Shutdown cooling 

line 1 & 2 

Alloy 82/182 100% Volumetric once in the next 5 years, if no 

additional indications/growth, continue with the 

existing Code examination program for unflawed 

condition or approved alternative 

Bare metal visual examination once every 3 refuel 

outages (RFOs) when volumetric exams are not 

performed 

Full Structural 

Overlay: 

Unit 1 fall 2008 

Unit 2 spring 2008 

Unit 3 spring 2009 

Pressurizer surge line Alloy 82/182 100% Volumetric once in the next 5 years, if no 

additional indications/growth, continue with the 

existing Code examination program for unflawed 

condition or approved alternative 

Bare metal visual examination once every 3 RFO 

when volumetric exams are not performed 

Full Structural 

Overlay: 

Unit 1 spring 2007 

Unit 2 spring 2008 

Unit 3 fall 2007 

Pressurizer Spray line 

1A & 1B 

Alloy 82/182 Bare metal visual examination once every 3 RFO Potential for future

structural weld overlay 

or mechanical stress 

improvement 

Safety injection line Alloy 82/182 100% Volumetric every 6 yrs & bare visual 

examination once every 3 RFO when volumetric 

exams are not performed 

None 

Drain line 1A, 1B, & 

2A 

Alloy 82/182 Bare metal visual examination once every 3 RFO None 

Letdown line 2B Alloy 82/182 Bare metal visual examination once every 3 RFO None 

Charging line 2A Alloy 82/182 Bare metal visual examination once every 3 RFO None 

Cold leg RTD Nozzles Alloy 600 Bare metal visuals None 

RCP Instrument Taps Alloy 600 Bare metal visuals None 

 

The staff finds that the applicant has clarified that no Alloy 82/182 weld metal or Alloy 600 

components remain in the main reactor coolant loops within the scope of the LBB analysis 

except those shown in the table. The staff reviewed the table to evaluate if the applicant is 

using appropriate inspection methods to manage the branch, instrument, and RTD nozzle 

connections adequately. The staff finds that the applicant will manage the Alloy 82/182 and 

Alloy 600 components in the LBB-approved RCS piping adequately and in accordance with 

ASME Code requirements as discussed below. The staff’s concern in RAI 4.3.2.15-3 is 

resolved. 

In RAI 4.3.2.15-4, the staff asked the applicant to discuss the inspection history and results of 

the LBB-approved piping. If indications or flaws remain in inservice LBB piping, the staff asked 

the applicant to discuss monitoring of indications and flaws to the end of the period of extended 
Time-Limited Aging Analyses 

 4-10 

operation and inspection schedules for each of the LBB pipes (other than existing indications 

and flaws). 

By letter dated March 1, 2010, in response to RAI 4.3.2.15-4, the applicant stated that welds 

and piping that are part of the LBB piping have been examined under the ASME Code 

Section XI ISI starting in the first interval and will be examined under the rules of the ASME 

Code Section XI ISI in future intervals. The piping in question is part of the overall population of 

welds subject to examination. The applicant has found no rejectable indications, and it will 

continue to examine piping in accordance with the ASME Code Section XI ISI. The applicant 

performs surface and volumetric exams on 25 percent of the welds spread out over each 

10-year interval and a visual exam every outage. 

The staff finds that the applicant will follow the ASME Code Section XI ISI to inspect the 

LBB-approved primary coolant piping during the period of extended operation. Therefore, the 

structural integrity of the reactor coolant loop piping will be maintained to the end of 60 years. 

The staff’s concern in RAI 4.3.2.15-4 is resolved. 

Effects of Power Uprate and Steam Generator Replacement on the LBB Analysis. The 

applicant has evaluated the effect of power uprate and SG replacement on the LBB-approved 

primary coolant piping and found no change to the conclusion of the LBB analysis. In 

RAI 4.3.2.15-5, the staff asked the applicant to clarify whether the LBB analyses have been 

reanalyzed to determine the effect of operating conditions due to system modifications such as 

power uprates or SG modifications on the LBB analyses for the period of extended operation. 

By letter dated March 1, 2010, in response to RAI 4.3.2.15-5, the applicant stated it evaluated 

the effects of power uprate and SG replacement, and the evaluation resulted in no change to 

the conclusion of the LBB analysis (Supplement 11 to NUREG-0857, “Safety Evaluation Report 

Related to the Operation of PVNGS, Units 1, 2, and 3”). Since the applicant reviewed the LBB 

analyses for effects of power uprate and SG replacement with no effect on the conclusion and, 

since they are not TLAAs, the increase in operating life for the period of extended operation 

does not affect them. The staff’s concern in RAI 4.3.2.15-5 is resolved. 

The staff finds that the power uprate and SG replacement will not affect the LBB evaluation 

during the period of extended operation. 

Conclusion. Based on its review, the staff concludes that the applicant has demonstrated that 

the LBB analysis is not a TLAA because the analysis does not meet 10 CFR 54.3(a)(3) criteria. 

4.1.3.1.5 Absence of Supplemental Fatigue Analysis Time-Limited Aging Analyses in 

Response to Bulletin 88-08 for Intermittent Thermal Cycles due to 

Thermal-Cycle-Driven Interface Valve Leaks and Similar Cyclic Phenomena 

Summary of Technical Information in the Application. In amended LRA Section 4.3.2.8 

(dated May 27, 2010), the applicant references Bulletin 88-08, “Thermal Stresses in Piping 

Connected to Reactor Cooling Systems,” which recommends that a high-cycle fatigue analysis 

be performed for the auxiliary pressurizer spray systems. This section states that a 

“supplemental bounding thermal gradient stress analysis to determine the effect of low cycle 

fatigue,” was performed and that the analysis did not evaluate the effects of high-cycle fatigue 

on these lines, as recommended in Bulletin 88-08. 

Staff Evaluation. The staff confirmed that the applicant’s response to Bulletin 88-08, dated 

October 3, 1988, did not commit to the performance of a high-cycle fatigue analysis. 

LRA Section 4.3.2.7, subsection “Flow Stratification Thermal Gradient in the Auxiliary Spray 

Line and Tee” states that, “[t]he analysis of the thermal gradient demonstrated that the 

cumulative fatigue usage factor, including the effects of this thermal gradient, meets ASME 

Code Section III Subsection NB-3600 for a 40-year plant life.” Based on this statement, it 
Time-Limited Aging Analyses 

 4-11 

appears that this analysis meets the definition of a TLAA in accordance with 10 CFR 54.3(a). 

By letter dated July 21, 2010, the staff issued RAI 4.3-15 asking that the applicant identify the 

low-cycle fatigue analysis that is being referred to in LRA Sections 4.3.2.7 and 4.3.2.8 and 

clarify whether the low-cycle fatigue analysis on the auxiliary pressurizer spray systems 

included an applicable, implicit fatigue analysis, cycle-based fatigue flaw growth, or cycle-based 

fracture mechanics analysis. The staff also asked the applicant justify why the low-cycle fatigue 

analysis would not need to be identified as a TLAA if it is determined that the analysis does 

include a cycle-dependent analysis. This was previously identified as part of Open Item 4.3-1. 

The applicant's response dated August 12, 2010, stated that the low-cycle fatigue analysis 

referred to in LRA Section 4.3.2.7 and 4.3.2.8 is an analysis that considered deadweight, 

thermal (including stratification), seismic and LOCA load case to determine the effects on the 

existing fatigue cycle stress range. The applicant further stated that the calculation did not 

contain an implicit fatigue analysis, cycle-based fatigue flaw growth or a cycle-based fracture 

mechanics analysis. The applicant stated that the analysis concluded that the effect of thermal 

stratification does not negatively impact the auxiliary pressurizer spray systems or the stress 

ranges of the fatigue analysis. The applicant also stated that the low cycle fatigue referred to in 

LRA Sections 4.3.2.7 and 4.3.2.8 in response to NRC Bulletin 88-08 does not include 

cycle-based assumptions. 

Based on its review, the staff finds the applicant’s response to RAI 4.3-15 acceptable because 

the applicant clarified that the low cycle fatigue analysis referred to in LRA Sections 4.3.2.7 and 

4.3.2.8 is not a TLAA and does not contain an implicit fatigue analysis, cycle-based fatigue flaw 

growth, or a cycle-based fracture mechanics analysis. This part of Open Item 4.3-1 is closed. 

Conclusion. The staff concludes that the applicant has demonstrated that the applicant does 

not have a fatigue analysis TLAAs in response to Bulletin 88-08 for intermittent thermal cycles 

due to thermal-cycle-driven interface valve leaks and similar cyclic phenomena as part of its 

CLB, and therefore does not meet the definition of a TLAA, in accordance with 10 CFR 54.3. 

4.1.3.1.6 Absence of Time-Limited Aging Analyses in Evaluations of Effects of Vibration on 

the Unit 1, Train A Shutdown Cooling System Suction Line Fatigue Analysis and of 

Vibration Limits Established for its Isolation Valve Actuator 

Summary of Technical Information in the Application. LRA Section 4.3.2.13 summarizes the 

evaluation of the absence of a TLAA for the evaluations of effects of vibration on the Unit 1 

Train A shutdown cooling system (SCS) suction line fatigue analysis, and of vibration limits 

established for its isolation valve actuator. 

In March of 2006, the applicant conducted a test to diagnose the causes of high vibration in the 

Unit 1 Train A SCS suction line. The applicant stated that the correction included moving the 

Unit 1 UV651 valve inboard, to increase the acoustic response above the line and valve 

resonance. Unit 1 has since operated at 100 percent power with acceptable vibration levels. 

The evaluation of the UV651 valve actuator determined that maintaining vibration below the 

administrative limit would maintain accelerations below the revised vibration limits established 

for indefinite, continuous operation. These evaluations are, therefore, not time-limited and are 

therefore not TLAAs. 

Staff Evaluation. The staff reviewed LRA Section 4.3.2.13 to evaluate the absence of a TLAA in 

evaluations of effects of vibration on the Unit 1 Train A SCS suction line fatigue analysis, and of 

vibration limits established for its isolation valve actuator. The applicant stated that in 2006, a 

test to diagnose causes of high vibration in the Unit 1 Train A SCS suction line was conducted. 

The Train A SCS suction line is connected to the Loop 1 hot leg. This test operated both Loop 1 

reactor coolant pumps but only one Loop 2 pump. This condition produced high Loop 1 flow, 

which caused brief excursions of an SCS Train A vibration monitor beyond both the 

administrative and analytical limits. The applicant stated that at these vibration levels, the time 
Time-Limited Aging Analyses 

 4-12 

required for operator action to shut down the unit might result in unacceptable fatigue usage and 

eventual failure of the piping or isolation valve motor operator. The applicant stated that the 

correction included moving the Unit 1 UV651 valve inboard, to increase the acoustic response 

above the line and valve resonance. Unit 1 has since operated at 100 percent power with 

acceptable vibration levels. The applicant has also moved the corresponding valves in Units 2 

and 3 to prevent similar problems. The staff noted the applicant's conclusion that maintaining 

vibration below the administrative limit would maintain alternating stresses below the endurance 

limit at the most limiting location. The staff also noted that the applicant demonstrated that 

vibration levels remaining below the administrative limit would maintain accelerations below the 

revised vibration limits established for the UV651 valve actuator for an indefinite period. The 

staff finds it reasonable that if the vibrations are maintained below the endurance limit, then the 

fatigue life can be considered infinite. This is reasonable because the alternating stress is less 

than the stress that would result in fatigue failure and because the material can endure an 

extremely large number of cycles (107

 cycles) without failing. The staff noted that the 

applicant’s evaluation did not qualify the piping or valve for any similar excursions during the 

remaining life of the plant, and therefore does not meet the definition of a TLAA in accordance 

with 10 CFR 54.3(a)(3). 

Based on its review, the staff finds the applicant’s evaluation of high vibration of the Unit 1 

Train A SCS suction line and of the actuator of its UV651 motor-operated isolation valve is not a 

TLAA because the applicant demonstrated that maintaining vibration below the administrative 

limit would maintain alternating stresses below the endurance limit for the UV651 valve actuator 

for an indefinite period. Further, it is acceptable because the applicant’s evaluation did not 

qualify the piping or valve for any similar excursions during the remaining life of the plant, and, 

therefore, it does not meet the definition of a TLAA in accordance with 10 CFR 54.3(a)(3). 

Conclusion. Based on its review, the staff concludes that the applicant has demonstrated that 

the evaluations of the effects of vibration on the Unit 1 Train A SCS suction line fatigue analysis 

and of vibration limits established for its isolation valve actuator, are not TLAAs because they do 

not meet 10 CFR 54.3(a)(3) criteria. 

4.1.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable list 

of TLAAs, as required by 10 CFR 54.21(c)(1), and that no exemption has been granted on the 

basis of a TLAA for which continuation has been justified during the period of extended 

operation. 

4.2 Reactor Vessel Neutron Embrittlement

“Neutron embrittlement” is the term for changes in mechanical properties of RPV materials 

caused by exposure to a fast neutron flux, energy (E) values greater than 1 mega electron-volt 

(MeV) (E > 1 MeV), within the vicinity of the reactor core, called the “beltline region.” The most 

pronounced material change is a reduction in fracture toughness. As fracture toughness 

decreases with cumulative fast neutron exposure, the material’s resistance to cleavage and 

ductile fracture decreases. Fracture toughness also depends on temperature. The reference 

temperature (RTNDT), above which the material behaves in a ductile manner and below which 

the material behaves in a brittle manner, increases as the fluence increases and requires higher 

temperatures for continued ductility. All light-water reactors are required by 10 CFR 50.60 to 

meet the fracture toughness, pressure-temperature (P-T) limits, and material surveillance 

program requirements for the reactor coolant pressure boundary in Appendices G and H of 

10 CFR Part 50. The RTNDT value, which is evaluated at one-quarter or three-quarters of the 

RPV wall thickness (1⁄4T or 3⁄4T) for a specified effective full power years (EFPYs), is usually 

referred to as the “adjusted reference temperature” (ART) in the P-T limit applications. In 
Time-Limited Aging Analyses 

 4-13 

10 CFR Part 50.61, fracture toughness requirements are supplied for protecting the RPV of a 

PWR against the consequences due to a pressurized thermal shock (PTS) event—a severe 

overcooling event concurrent with or followed by significant pressure in the RPV. Neutron 

fluence, upper shelf energy (USE), PTS, and P-T limits are time-dependent items that must be 

investigated to evaluate RPV embrittlement or reduction of fracture toughness. The CLB 

analyses evaluating reduction of fracture toughness of the RPV for 40 years are TLAAs. The 

following sections address neutron fluence, USE, PTS, and P-T limits for RPV beltline materials 

for the period of extended operation. 

4.2.1 Neutron Fluence, Upper Shelf Energy and Adjusted Reference Temperature 

4.2.1.1 Summary of Technical Information in the Application 

LRA Section 4.2.1 summarizes the evaluation of neutron fluence, USE, and ART for the period 

of extended operation. 

The applicant analyzed the most-recently-examined 230-degrees, Capsule 5 dosimeters from 

each of the three Units (reports were submitted to the staff in letters dated April 5, 2005; 

April 4, 2006; and September 26, 2005) to project the neutron fluence at 54 EFPYs, including 

effects of the power uprate. The applicant's revised fluence values were determined with 

transport calculations using the Discrete Ordinates Radiation Transport Code and the Bugle-96 

cross-section library, which is derived from the Evaluated Nuclear Data Files, version B-VI. The 

applicant stated that the neutron transport and dosimetry evaluation methodologies follow the 

guidance and meet the requirements of RG 1.190, “Calculational and Dosimetry Methods for 

Determining Pressure Vessel Neutron Fluence,” and are consistent with Westinghouse 

Commercial Atomic Power (WCAP) Report WCAP-14040-NP-A, “Methodology Used to Develop 

Cold Overpressure Mitigating System Setpoints and RCS Heatup and Cooldown Limit Curves.” 

The LRA states that the clad-base metal interface fluences at 54 EFPY, projected from 

measured exposures and lead factors of Capsule 5, are 2.51E+19, 2.83E+19, and 

2.93E+19 neutrons per centimeter squared (n/cm2

) for E > 1 MeV for Units 1, 2, and 3, 

respectively. The applicant states that these values are less than the original 32 EFPY 

projection of 3.15E+19 n/cm2

 (E > 1 MeV) used in the PTS evaluation dated January 17, 1986, 

or the 3.29E+19 n/cm2

 (E > 1 MeV) used to determine the end-of-license (EOL) ART and USE 

in the NRC’s Reactor Vessel Integrity Database (RVID). 

The CLB predictions of USE and ART in PVNGS vessel materials at 32 EFPYs indicated that 

Unit 1 plate materials will be most limiting for both USE and ART. The recently-measured 

ΔRTNDT values in LRA Table 4.2-2 confirm that the limiting Unit 1 plate material will remain 

limiting for ART in the period of extended operation. 

For the USE evaluation, the applicant reproduced from the RVID, the copper content, initial 

USE, and neutron fluence values for RPV beltline materials in LRA Tables 4.2-3 to 4.2-5. The 

estimated 54 EFPY USE values in these tables are obtained using Position 1.2 of RG 1.99, 

“Radiation Embrittlement to Reactor Pressure Vessel Materials,” Revision 2. They are greater 

than 50 ft-lbs. The applicant stated that the most recent measured USEs show that the decline 

in USEs is less than originally predicted by RG 1.99, Revision 2. Hence, the applicant 

concludes that the USE of the limiting material will remain adequate for the period of extended 

operation. 

In summary, the applicant asserts that the evaluation of the acceptability of neutron fluence, 

USE, and ART remains valid for the period of extended operation, in accordance with 

10 CFR 54.21(c)(1)(i). In addition, neutron fluence, USE, and ART will be managed for the 

period of extended operation by continuing the Reactor Vessel Surveillance Program in 

accordance with 10 CFR 54.21(c)(1)(iii). See SER Section 3.0.3.2.10 for the staff’s evaluation 

of the Reactor Vessel Surveillance Program. 
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4.2.1.2 Staff Evaluation 

The staff reviewed LRA Section 4.2.1 to verify, pursuant to 10 CFR 54.21(c)(1)(i), that the 

neutron fluence, USE, and ART analyses remain valid for the period of extended operation or, 

pursuant to 10 CFR 54.21(c)(1)(iii), that the validity of these parameters and their associated 

analyses will be adequately managed for the period of extended operation using the Reactor 

Vessel Surveillance Program. 

Neutron fluence is an input for determining the USE and ART. The staff reviewed the 

referenced surveillance capsule dosimetry reports to determine that anisotropic scattering in the 

fluence analyses was treated with a P5 Legendre expansion, and that angular discretization was 

modeled with an S16 order of angular quadrature. Based on the review, the staff concluded that 

the applicant performed fluence calculations in accordance with RG 1.190 and the results are, 

therefore, acceptable. This is because the Bugle-96 cross section library is derived from 

Evaluated Nuclear Data Files, version B-VI-based nuclear data and because the scattering 

approximations and angular quadrature exceed the minimum values specified in RG 1.190. 

The uncertainty specified by the applicant of 13 percent, is within the 20-percent tolerance 

specified in RG 1.190 for calculational uncertainty, which is acceptable to the staff. The staff 

also considered the acceptability of fluence projections to the end of the period of extended 

operation based on 54 EFPYs of exposure. The applicant increased its assumed capacity 

factors from 80 to 90 percent. The staff finds that the assumption of a 90-percent capacity 

factor is acceptable because capacity factors in the past five years have averaged less than 

90 percent as documented in NUREG-1350, “2009-2010 Information Digest,” Volume 21, 

August 2009. 

Based on the above evaluation, the staff finds that the applicant’s fluence calculations are 

acceptable to support the period of extended operation. 

For USEs, 10 CFR 50, Appendix G contains screening criteria that establish limits on how far 

the USE values for a RPV material may be allowed to decrease due to neutron irradiation 

exposure. The regulation requires the initial USE value be greater than 75 ft-lbs in the 

unirradiated condition and that the value must be greater than 50 ft-lbs in the fully irradiated 

condition throughout the licensed life of the plant. USE values of less than 50 ft-lbs may be 

acceptable to the staff if it can be demonstrated that these lower values will provide margins of 

safety against brittle fracture equivalent to those required by ASME Code Section XI, 

Appendix G. 

As discussed earlier, the staff accepts the 54 EFPY fluence values used by the applicant. 

These 54 EFPY fluence values are bounded by the fluence value in the CLB for 32 EFPYs. 

LRA Tables 4.2-3 to 4.2-5 summarize the 54 EFPY USE. Upon review, the staff found apparent 

discrepancies in these tables. Hence, the staff issued RAI 4.2.1-1 on November 3, 2009. This 

RAI also included a finding in LRA Table 4.2-6 for Unit 1, 54 EFPY reference temperature for 

pressurized thermal shock (RTPTS). 

The applicant responded in a letter, dated December 18, 2009, which appropriately corrected 

LRA Tables 4.2-3 to 4.2-8, including additional corrections to errors not identified by the staff. 

As a result, the staff was able to verify consistency of RPV material information between LRA 

Section 4.2 and the staff’s RVID. The applicant obtained the 54 EFPY USE values in LRA 

Tables 4.2-3 to 4.2-5 using Position 1.2 of RG 1.99 (without using surveillance data). All USE 

values exceed 50 ft-lbs. Surveillance data from three withdrawn capsules were not used 

because of the applicant’s conclusion: “[t]he most recent coupon examination results also show 

that the decline in USE and increase in RTNDT in plate and weld materials are less than originally 

predicted by Regulatory Guide 1.99, Revision 2....” This justification of not using the 

surveillance data is not in accordance with RG 1.99, Revision 2. Hence, the staff issued 

RAI 4.2.1-2 to determine the applicant’s basis for not considering all surveillance data. 
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The applicant responded in a letter, dated December 18, 2009, but did not provide adequate 

justification for not using surveillance data in predicting 54 EFPY USE drops for RPV materials. 

However, this information is available in the additional references listed below: 

 WCAP-16374-NP, “Analysis of Capsule 230° from Arizona Public Service Company Palo 

Verde Unit 1 Reactor Vessel Radiation Surveillance Program,” February 2005 

 WCAP-16524-NP, “Analysis of Capsule 230° from Arizona Public Service Company Palo 

Verde Unit 2 Reactor Vessel Radiation Surveillance Program,” February 2006 

 WCAP-16449-NP, “Analysis of Capsule 230° from Arizona Public Service Company Palo 

Verde Unit 3 Reactor Vessel Radiation Surveillance Program,” August 2005. 

Acceptance of the applicant’s approach depends on the examination of the measured USE 

drops for all RPV materials having at least two surveillance data. 

The staff reviewed the measured USE drops for all RPV surveillance materials having at least 

two surveillance data in these surveillance reports. The staff found that the measured USE 

drops are less than the predicted values using Position 1.2 of RG 1.99, Revision 2, except for 

one Unit 2 surveillance data where the measured USE drop is more than the predicted value by 

1 percent. The staff determined that the applicant’s 54 EFPY USE values, based on 

Position 1.2, are adequate because the 1-percent difference in the USE value for the 

surveillance data is within test and curve fitting uncertainty. Hence, RAI 4.2.1-2 is resolved, and 

the applicant’s USE analysis, with its results summarized in LRA Tables 4.2-3 to 4.2-5, is in 

accordance with RG 1.99, Revision 2 and remains valid for the period of extended operation. 

LRA Section 4.2.1 also discussed the applicant’s evaluation of ART values for RPV materials. 

For RPV materials having specimens in surveillance capsules, RG 1.99, Revision 2 requires 

that all surveillance data in the surveillance capsule reports be considered in determining their 

chemistry factors. The staff discovered inconsistent information in the surveillance capsule 

reports. Hence, the staff issued RAI 4.2.1-3 on November 3, 2009, to confirm that the applicant 

misidentified surveillance specimens for Unit 1 in the WCAP-15589 report and confirm that 

Units 2 and 3 did not experience similar misidentifications. 

In a letter dated December 18, 2009, the applicant confirmed the misidentification of specimens 

in Capsule 38-degrees, for Unit 1 in the WCAP-15589 report and stated that WCAP-15589, 

Revision 1 report corrected this problem. The applicant submitted the WCAP-15589, Revision 1 

report on November 13, 2009. Hence, the WCAP-16374 report for Capsule 230-degrees and 

the USE and ART evaluations in the LRA reflect correct information on the use of surveillance 

data. To rule out misidentification of surveillance specimens for Units 2 and 3, the applicant 

stated that unlike Unit 1, which has three capsules containing M-4311-1 base metal material 

and three containing M-6701-2 base metal material, Units 2 and 3 have only one type of base 

metal material in their surveillance capsules. Hence, the staff concludes that the 

misidentification of surveillance specimens that happened to Unit 1 is unlikely to happen to 

Units 2 and 3, and the staff considers RAI 4.2.1-3 resolved. 

No criterion for ARTs is given in 10 CFR 50. However, as the most important parameter for 

determining the fracture toughness of the RPV material, it affects the P-T limits directly. The 

staff found that the chemistry factor for the limiting Unit 1 plate material in the CLB is greater 

than that based on surveillance data, and determined that the applicant can continue to use it to 

calculate the ART for the limiting material. The use of ART in the P-T limits for the period of 

extended operation is discussed in Section 4.2.3 of this SER. 

4.2.1.3 Updated Final Safety Analysis Report Supplement 

The applicant provided an UFSAR supplement summary description of its TLAA evaluation of 

the neutron fluence, USE, and ART values for RPV materials in LRA Section A3.1.1. The staff 
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reviewed LRA Section A3.1.1 against the acceptance criteria in SRP-LR Section 4.2.2.2. Based 

on its review of the UFSAR supplement, the staff concludes that the summary description of the 

applicant’s actions to address the neutron fluence, USE, and ART is adequate per 

10 CFR 54.21(d). 

4.2.1.4 Conclusion 

On the basis of its review, as discussed above, the staff concludes that the applicant has 

demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that for neutron fluence, USE, and ART, the 

analyses remain valid for the period of extended operation. The staff also finds it acceptable 

that the plant’s Reactor Vessel Surveillance Program will provide information for further 

validating or modifying its projected neutron fluence, ART, and USE values during the period of 

extended operation, pursuant to 10 CFR 54.21(c)(1)(iii). Finally, the staff finds that the UFSAR 

supplement contains an appropriate summary description of the TLAA evaluations, as required 

by 10 CFR 54.21(d). 

4.2.2 Pressurized Thermal Shock 

4.2.2.1 Summary of Technical Information in the Application 

LRA Section 4.2.2 summarizes the PTS evaluation of the beltline materials for the period of 

extended operation against the screening criteria established in accordance with 10 CFR 50.61, 

“Fracture Toughness Requirements for Protection Against Pressurized Thermal Shock Events.” 

The screening criteria are 270 degrees F for plates, forging, and axial weld materials and 

300 degrees F for circumferential weld materials. 

The applicant claims that since the 54 EFPY fluence is expected to remain within the values 

originally predicted for a 32 EFPY life, the 54 EFPY RTPTS is also expected to remain within the 

values originally predicted for a 32 EFPY life. Hence, the conclusions of the original evaluation 

are unaffected, and the original evaluation of the PTS screening parameter and the conclusion 

remains valid for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i). 

4.2.2.2 Staff Evaluation 

The staff reviewed LRA Section 4.2.2 to verify, pursuant to 10 CFR 54.21(c)(1)(i), that the 

analyses remain valid for the period of extended operation. 

The 10 CFR 50.61 provides the fracture toughness requirements protecting the RPVs of PWRs 

against the consequences of PTS. Applicants are required to perform an assessment of the 

RPV materials’ projected RTPTS values through the end of their operating license. The rule 

requires each applicant to calculate the EOL RTPTS value for each RPV beltline material. The 

RTPTS value for each beltline material is the sum of the unirradiated RTNDT, a shift in the RTNDT

value caused by neutron irradiation of the material (ΔRTNDT), and a margin value to account for 

uncertainties (M). 10 CFR 50.61 also provides screening criteria, against which the calculated 

values are to be evaluated. 

As stated in LRA Section 4.2.2.1, the screening criteria are 270 degrees F for plates, forging, 

and axial weld materials and 300 degrees F for circumferential weld materials. 10 CFR 50.61 

provides a discussion regarding the calculations of ΔRTNDT and the M value (defined in 

10 CFR 50.61(c)(1)(iii)). In 10 CFR 50.61, ΔRTNDT is the product of a chemistry factor and a 

fluence factor, where the fluence factor is dependent upon the neutron fluence at the 

clad-to-base metal interface and the chemistry factor is dependent upon information from either 

the surveillance material or from the tables in 10 CFR 50.61. If the RPV beltline material is not 

represented by surveillance material, its chemistry factor may be determined using the tables 

and the methodology documented in 10 CFR 50.61. The chemistry factor determined from the 

tables in 10 CFR 50.61 depends upon the amount of copper and nickel in the material. If the 

RPV beltline material is represented by surveillance material, its chemistry factor may be 
Time-Limited Aging Analyses 

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determined from the surveillance data using the methodology documented in 10 CFR 50.61. 

The methods of determining RTPTS values in 10 CFR 50.61 are equivalent to the methods of 

determining RTNDT values in RG 1.99, Revision 2. 

In LRA Tables 4.2-6 to 4.2-8, the applicant reproduced the information (RPV materials data, 

neutron fluence, and the projected RTPTS results) for PVNGS from the NRC’s RVID to 

demonstrate that the units comply with 10 CFR 50.61. Instead of using the RVID labeling, 

“EOL,” the applicant labeled the fluence-dependent parameters in these tables as “54 EFPY” to 

indicate that the PTS evaluation is valid for the period of extended operation. The tabulated 

54 EFPY RTPTS values are based on the neutron fluence value of 3.29E+19 n/cm2

 (E > 1 MeV), 

which bounds the 54 EFPY neutron fluence values of 2.51E+19 n/cm2

, 2.83E+19 n/cm2, and 

2.93E+19 n/cm2

 (E > 1 MeV) for the PVNGS units. The staff accepts these values (see 

Section 4.2.1.2 of this SER). LRA Tables 4.2-6 to 4.2-8 also show that the RTPTS for the limiting 

RPV beltline material (the intermediate shell plate M-6701-2 and M-6701-3) is 122.5 degrees F, 

meeting the PTS criteria. 

LRA Section 4.2.2 further states that the PVNGS 10 CFR 50.61 PTS submittal, dated 

January 17, 1986, projected an RTPTS of 132 degrees F for the limiting plate material at the 

3.15E+19 n/cm2

 (E > 1 MeV) clad-base metal interface fluence. Based on the copper and nickel 

values reported in the January 17, 1986, PTS evaluation, the staff believes that the applicant’s 

limiting material then was the Unit 1 intermediate shell plate M-6701-1, not the Unit 1 

intermediate shell plates M-6701-2 or M-6701-3 identified in the CLB (or RVID). This 

discrepancy is not important because the RVID shows that the difference in RTPTS caused by 

using the different limiting plates identified above is only 0.8 degree F. Considering this, the 

January 17, 1986, evaluation still bounds the applicant’s PTS evaluation at 54 EFPYs for the 

period of extended operation. 

Based on the above discussion, the staff concludes that RPV beltline materials satisfy the PTS 

requirements of 10 CFR 50.61 through the period of extended operation. The applicant’s TLAA 

for calculating the RTPTS values of the RPV beltline materials at the end of the period of 

extended operation is acceptable because the calculated values are bound by the existing 

analysis and meet the requirements of 10 CFR 54.21(c)(1)(i). This ensures that the RPV 

materials will have adequate RTPTS values and fracture toughness through the period of 

extended operation. 

4.2.2.3 Updated Final Safety Analysis Report Supplement 

The applicant provided an UFSAR supplement summary description of its TLAA evaluation of 

PTS in LRA Section A3.1.2. Based on its review of the UFSAR supplement, the staff concludes 

that the summary description of the applicant’s actions to address PTS is adequate. 

4.2.2.4 Conclusion 

On the basis of its review, as discussed above, the staff concludes that the applicant has 

demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that for PTS, the analyses remain valid for the 

period of extended operation. The staff also concludes that the UFSAR supplement contains an 

appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d). 

4.2.3 Pressure-Temperature Limits 

4.2.3.1 Summary of Technical Information in the Application 

LRA Section 4.2.3 summarizes the evaluation of P-T limits for the period of extended operation. 

The applicant states that the current license includes P-T limit curves calculated for 

embrittlement effects originally determined to be valid up to 32 EFPYs. However, they were 

based on projections of EOL ART that depended on an originally-estimated 32 EFPY beltline 

high-energy neutron fluence of 3.29E+19 n/cm2

 (E > 1 MeV), which exceeds the maximum 
Time-Limited Aging Analyses 

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fluence now expected at 54 EFPYs, 2.93E+19 n/cm2

 (E > 1 MeV). Hence, the present P-T limit 

curves for 32 EFPYs are still valid for the period of extended operation in accordance with 

10 CFR 54.21(c)(1)(i). APS will confirm their basis for 54 EFPYs prior to operation beyond 

32 EFPYs and will update documents in accordance with the provisions of 10 CFR 50.59. 

4.2.3.2 Staff Evaluation 

The staff reviewed LRA Section 4.2.3 to verify that, pursuant to 10 CFR 54.21(c)(1)(i), the P-T 

limit analyses remain valid for the period of extended operation. 

The staff approved the current P-T limits on February 25, 2010, through issuance of 

Amendment 178 which revised the TS to relocate the P-T limits and the low temperature 

overpressure protection (LTOP) system enable temperatures from the TS to a 

licensee-controlled document, the Pressure Temperature Limits Report. The associated 

request for exemption from 10 CFR 50, Appendix G on P-T limits calculation was approved on 

February 24, 2010. The current P-T limits are for 32 EFPYs with a neutron fluence of 

3.29E+19 n/cm2

 (E > 1 MeV) at the RPV clad-to-base metal interface (the RPV surface). 

The staff found that the limiting material for the P-T limits, which apply to all units, is the Unit 1 

intermediate shell plate M-6701-2 or M-6701-3. The copper and nickel contents, the initial 

RTNDT values, and the 32 EFPY neutron fluence at the RPV surface for the limiting material are 

identical to the information in the RVID. The applicant continued to use this material information 

in its P-T limit evaluation for the period of extended operation. 

As evaluated in Section 4.2.1.2 of this SER, the staff accepts the applicant’s 54 EFPY neutron 

fluence values of 2.51E+19 n/cm2

, 2.83E+19 n/cm2, and 2.93E+19 n/cm2 (E > 1 MeV). These 

fluence values are bounded by the 32 EFPY neutron fluence value of 3.29E+19 n/cm2

(E > 1 MeV) for the current P-T limits. Since the copper and nickel contents and the initial 

RTNDT values for the limiting material of the P-T limits remain unchanged during the period of 

extended operation, the fact that the neutron fluence for the current P-T limits bounds the 54 

EFPY neutron fluence shows that the current P-T limits bound the 54 EFPY P-T limits. 

Based on the above discussion, the staff determines that the applicant’s P-T limit evaluation of 

the RPV beltline materials during the period of extended operation is acceptable because the 

current P-T limits remain valid for the period of extended operation in accordance with 

10 CFR 54.21(c)(1)(i). This P-T limit evaluation will ensure that the RPV materials will have 

adequate fracture toughness and meet the requirements of 10 CFR 50.60 and 10 CFR 50, 

Appendix G during the period of extended operation. 

As mentioned, the applicant was approved on February 25, 2010, to relocate the P-T limits for 

PVNGS to a licensee-controlled Pressure Temperature Limits Report. As such, as long as the 

P-T limit methodology stays the same, future changes to the P-T limit curves will be processed 

through the provisions of 10 CFR 50.59 instead of the license amendment process, as stated by 

the applicant. 

4.2.3.3 Updated Final Safety Analysis Report Supplement 

The applicant provided an UFSAR supplement summary description of its TLAA evaluation of 

P-T limits in LRA Section A3.1.3. Based on its review of the UFSAR supplement, the staff 

concludes that the summary description of the applicant’s actions to address P-T limits is 

adequate. 

4.2.3.4 Conclusion 

On the basis of its review, as discussed above, the staff concludes that the applicant has 

demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that, for P-T limits, the analyses remain valid 

for the period of extended operation. The staff also concludes that the UFSAR supplement 
Time-Limited Aging Analyses 

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contains an appropriate summary description of the TLAA evaluation, as required by 

10 CFR 54.21(d). 

4.2.4 Low Temperature Overpressure Protection 

4.2.4.1 Summary of Technical Information in the Application 

LRA Section 4.2.4 summarizes the evaluation of LTOP for the period of extended operation. 

The applicant states that TS Limited Condition for Operation 3.4.13 requires LTOP, which is 

provided by relief valves in the two suction lines of the SCS or by operating with the RCS 

depressurized and with an open RCS vent of sufficient size to protect the SCS and RCS. The 

LTOP enable temperatures (the temperatures below which LTOP must be established), and 

those analyses that confirm the ability to protect the system’s pressure limits, depend on the P-T 

limit curves and the ART. The LTOP enable temperatures and the supporting design basis 

calculations are TLAAs. The mass and energy addition transient analyses in the LTOP 

licensing basis, however, are not time-dependent. The applicant uses the enable temperatures 

and P-T heatup and cooldown limits as input to determine maximum system temperature at the 

time of the event and the heatup and cooldown rates with the system aligned. 

The applicant states further that the only time-limited analyses upon which the LTOP setpoints 

are based are those for the P-T curves and ART. These will remain valid for the period of 

extended operation. Therefore the LTOP licensing and design basis analyses will remain valid 

for the period of extended operation, in accordance with 10 CFR 54.21 (c)(1)(i). 

4.2.4.2 Staff Evaluation 

The staff reviewed LRA Section 4.2.4 to verify, pursuant to 10 CFR 54.21(c)(1)(i), that LTOP 

remains valid for the period of extended operation. 

In Sections 4.2.1.2 and 4.2.3.2 of this SER, the staff concludes that the applicant’s ART and 

P-T limit evaluations of the RPV beltline materials during the period of extended operation are 

acceptable because the current P-T limits remain valid for the period of extended operation in 

accordance with 10 CFR 54.21(c)(1)(i). Since the ART and the P-T limits, which are the only 

time-dependent inputs to the LTOP evaluation, remain valid for the period of extended 

operation, the LTOP evaluation will also remain valid for the period of extended operation, in 

accordance with 10 CFR 54.21(c)(1)(i). 

4.2.4.3 Updated Final Safety Analysis Report Supplement 

The applicant provided an UFSAR supplement summary description of its TLAA evaluation of 

LTOP in LRA Section A3.1.4. Based on its review of the UFSAR supplement, the staff 

concludes that the summary description of the applicant’s actions to address LTOP is adequate. 

4.2.4.4 Conclusion 

On the basis of its review, as discussed above, the staff concludes that the applicant has 

demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that, for LTOP, the analyses remain valid for 

the period of extended operation. The staff also concludes that the UFSAR supplement 

contains an appropriate summary description of the TLAA evaluation, as required by 

10 CFR 54.21(d). 

4.3 Metal Fatigue Analysis

LRA Section 4.3 provides the assessment of metal fatigue analyses in the CLB, which the 

applicant determined to be TLAAs for license renewal. The applicant divides this section of the 

LRA into the following subsections: 

 LRA Section 4.3.1, “Fatigue Aging Management Program” and its subsections 
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 LRA Section 4.3.2, “ASME III Class 1 Fatigue Analysis of Vessels, Piping, and 

Components” and its subsections 

 LRA Section 4.3.3, “Fatigue and Cycle-Based TLAAs of ASME III Subsection NG 

Reactor Pressure Vessel Internals” 

 LRA Section 4.3.4, “Effects of the Reactor Coolant System Environment on Fatigue Life 

of Piping and Components [Generic Safety Issue (GSI) 190]” 

 LRA Section 4.3.5, “Assumed Thermal Cycle Count for Allowable Secondary Stress 

Range Reduction Factor in ANSI B31.1 and ASME III Class 2 and 3 Piping” 

The applicant identifies that the following metal fatigue analyses constitute TLAAs for the LRA: 

 “Reactor Pressure Vessel, Nozzles, Head and Studs” (LRA Section 4.3.2.1) 

 “Control Element Drive Mechanism (CEDM) Nozzle Pressure Housings” (LRA 

Section 4.3.2.2) 

 “Reactor Coolant Pump Pressure Boundary Components” (LRA Section 4.3.2.3) 

 “Pressurizer and Pressurizer Nozzles” (LRA Section 4.3.2.4) 

 “Steam Generator ASME III Class 1, Class 2 Secondary Side, and Feedwater Nozzle 

Fatigue Analyses” (LRA Section 4.3.2.5) 

 “ASME III Class 1 Valves” (LRA Section 4.3.2.6) 

 “ASME III Class 1 Piping and Piping Nozzles” (LRA Section 4.3.2.7) 

 “Bulletin 88-11 Revised Fatigue Analysis of the Pressurizer Surge Line for Thermal 

Cycling and Stratification” (LRA Section 4.3.2.9) 

 “Class 1 Fatigue Analyses of Class 2 Regenerative and Letdown Heat Exchangers” 

(LRA Section 4.3.2.10) 

 “Class 1 Fatigue Analyses of Class 2 HPSI and LPSI Safety Injection Safeguard Pumps 

for Design Thermal Cycles” (LRA Section 4.3.2.11) 

 “Class 1 Analysis of Class 2 Main Steam Safety Valves” (LRA Section 4.3.2.12) 

 “High Energy Line Break Postulation Based on Fatigue Cumulative Usage Factor” (LRA 

Section 4.3.2.14) 

The staff evaluated these TLAAs in the subsections that follow. The applicant also identified the 

following metal fatigue analyses in LRA Section 4.3.2 that do not comply with the definition of a 

TLAA, as defined in 10 CFR 54.3: 

 “Absence of Supplemental Fatigue Analysis TLAAs in Response to Bulletin 88-08 for 

Intermittent Thermal Cycles due to Thermal-Cycle-Driven Interface Valve Leaks and 

Similar Cyclic Phenomena” (LRA Section 4.3.2.8) 

 “Absence of TLAAs in Evaluations of Effects of Vibration on the Unit 1 Train A Shutdown 

Cooling System Suction Line Fatigue Analysis, and of Vibration Limits Established for its 

Isolation Valve Actuator” (LRA Section 4.3.2.13) 

 “Absence of TLAAs in Fatigue Crack Growth Assessments and Fracture Mechanics 

Stability Analyses for the Leak-Before-Break (LBB) Elimination of Dynamic Effects of 

Primary Loop Piping Failures” (LRA Section 4.3.2.15) 
Time-Limited Aging Analyses 

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The staff evaluated the applicant’s basis for claiming that these analyses are not TLAAs in SER 

Section 4.1.3.1. 

During the acceptance review of the LRA, the staff noted that Table 4.3-9, “Summary of PVNGS 

Class 1 Valve Fatigue Analyses,” did not give the information necessary for the staff’s review. 

The staff, therefore, ended the acceptance review of the application; issued a letter dated 

February 13, 2009, to the applicant describing the incomplete information; and asked the 

applicant to provide a plan for resolving the identified deficiency. The applicant provided its 

response by letter dated February 25, 2009, and stated that it would supplement the LRA before 

April 15, 2009. By letter dated April 14, 2009, the applicant submitted Supplement 1 to the LRA 

which provided the missing information. The staff then accepted the LRA (74 FR 22978) and 

began its review. 

The staff noted other discrepancies and inconsistencies during the review of LRA Section 4.3, 

“Metal Fatigue Analysis.” The staff held several conference calls with the applicant concerning 

metal fatigue analysis issues. The topics of these conference calls are captured in a summary 

document dated July 14, 2010. Additionally, the staff held a public meeting to discuss metal 

fatigue issues on May 6, 2010. The public meeting summary can be found in a document dated 

June 25, 2010. 

By letter dated April 28, 2010, the applicant submitted Amendment 14 to the LRA to clarify and 

correct LRA Section 4.3.1 as discussed with the staff. By letter dated May 27, 2010, the 

applicant submitted Amendment 16 to the LRA to provide conforming changes to the remaining 

Section 4.3 subsections and related sections (e.g., Appendix B, Section B3.1 “Metal Fatigue of 

Reactor Coolant Pressure Boundary”). By letter dated June 29, 2010, the applicant submitted 

Amendment 18 to the LRA, which further modified appropriate sections and provided responses 

to the staff’s RAIs issued on June 2, 2010 (these RAIs will be discussed later in this section). 

Additional metal fatigue amendments were provided by the applicant by letters dated 

July 7, 2010 (Amendment 19), August 12, 2010 (Amendment 22), October 13, 2010 

(Amendment 25) and December 3, 2010 (Amendment 28). These are discussed in Sections 4.3 

and 4.7. 

4.3.1 Enhanced Fatigue Aging Management Program 

In LRA Section 4.3.1, “Enhanced Fatigue Aging Management Program (B3.1),” the applicant 

provides a general discussion on its use of the Metal Fatigue of Reactor Coolant Pressure 

Boundary Program. This discussion includes how the applicant will use the program to track the 

number of occurrences for the plant’s design basis transients and their effects on the fatigue 

analysis for ASME Code Class components. 

The LRA describes the enhanced AMP in the following subsections: 

 LRA Section 4.3.1.1, “Licensing and Design Basis of the PVNGS Component Cyclic and 

Transient Limit Program” 

 LRA Section 4.3.1.2, “Enhanced PVNGS Fatigue Management Program (B3.1)” 

 LRA Section 4.3.1.3, “Seismic History” 

 LRA Section 4.3.1.4, “Present and Projected Status of Monitored Locations” 

 LRA Section 4.3.1.5, “Program Scope, Action Limits, and Corrective Actions” 

In LRA Section 4.3.1, the applicant identifies that the enhanced metal fatigue AMP will apply 

one of the following fatigue monitoring methodologies for ASME Code Class components: 

 Cycle counting (CC) 
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 Cycle-based fatigue per cycle (CBF-C) 

 Cycle-based fatigue with partial cycles (CBF-PC) 

 Event pairing cycle-based fatigue (CBF-EP) 

 Stress-based fatigue (SBF) 

In this section, the applicant clarifies when it is appropriate to use these monitoring methods as 

the basis for accepting the metal fatigue TLAAs in accordance with the TLAA acceptance 

requirement in 10 CFR 54.21(c)(1)(iii). 

The staff’s evaluation of LRA Section 4.3.1 and its subsections follows. 

4.3.1.1 Licensing and Design Basis of the Palo Verde Nuclear Generating Station 

Component Cyclic and Transient Limit Program 

4.3.1.1.1 Summary of Technical Information in the License Renewal Application 

The applicant provides a summary of the licensing and design information for the “Component 

Cyclic and Transient Limit Program” in LRA Section 4.3.1.1. TS 5.5.5 requires the applicant to 

include an administrative program that “provides controls to the UFSAR Section 3.9.1.1 cycle 

and transient occurrences to ensure that components are maintained within the design limits.” 

The applicant also states that UFSAR Section 3.9.1.1 includes, by reference, information and 

transient definitions from the following UFSAR sections and tables, listed in LRA Table 4.3-1: 

 UFSAR Section 3.7.3.2, “Operating Basis Earthquake (OBE) Cycles” 

 UFSAR Table 3.9.1-1, “ASME III Class 1 Components by the NSSS Vendor (CE)” 

 UFSAR Table 3.9-1, “ASME III Class 1 Piping Not By the NSSS Vendor (CE)” 

 UFSAR Section 3.9.3, “ASME III Class 2 and 3 Components” 

 UFSAR Section 5.4.1, “Reactor Coolant Pumps” 

 UFSAR Section 5.4.2, “Steam Generators” 

 UFSAR Section 5.4.3, “Reactor Coolant Piping” 

 UFSAR Section 5.4.10, “Pressurizer” 

4.3.1.1.2 Staff Evaluation 

The staff reviewed the TS and UFSAR to assess whether the sections referenced by the 

applicant in LRA Section 4.3.1.1 and in LRA Table 4.3-1 were the applicable CLB and current 

design basis documents. The staff confirmed that TS 5.5.5 gives the licensing requirements for 

tracking the occurrences of the design basis transients, and the TS references the transients 

listed and evaluated in UFSAR Section 3.9.1.1. The staff verified that UFSAR Section 3.9.1.1 

refers to those design basis transients that UFSAR Table 3.9.1-1 lists for ASME Code Class 1 

Nuclear Steam Supply System (reactor vessel) components, UFSAR Table 3.9-1 for ASME 

Code Class 1 Non-Nuclear Steam Supply System (NSSS), and the UFSAR sections referenced 

in the above bulleted list. Based on this verification, the staff determined that the applicant 

appropriately referenced the appropriate CLB and UFSAR sections for tracking the design basis 

transients that are applicable to the fatigue assessments. 

4.3.1.1.3 Conclusion 

Based on this review, the staff concludes that the applicant’s Component Cyclic and Transient 

Limit Program references the appropriate TS requirement and UFSAR sections and that LRA 

Section 4.3.1.1, as administratively amended in LRA Amendment 14, provides an accurate 

summary of the TS requirements and UFSAR sections that are applicable to this program. 
Time-Limited Aging Analyses 

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4.3.1.2 Enhanced Fatigue Aging Management Program 

4.3.1.2.1 Summary of Technical Information in the License Renewal Application 

In LRA Section 4.3.1.2, the applicant provides a brief description of the general basis for the 

enhanced metal fatigue AMP that will be implemented during the period of extended operation. 

LRA Section 4.3.1.2 includes LRA Table 4.3-2, “PVNGS Unit 1, 2, and 3 Licensing Basis 

Transients,” which provides a summary of the design basis transients that are applicable to this 

TLAA and the design basis limits for these transients. 

4.3.1.2.2 Staff Evaluation 

The staff reviewed the information in LRA Section 4.3.1 against the SRP-LR Section 4.3.2.1.1.3 

for ASME Code Section III, Code Class 1 components and SRP-LR Section 4.3.2.1.2.3 for 

ASME Code Section III, Code Class 2 and 3 components designed to ANSI B31.1 

requirements. Specifically, the staff reviewed the general scope, monitoring method basis, 

corrective actions, and analytical margin information in LRA Section 4.3.1 to evaluate whether 

the monitoring method bases were in conformance with those given in the enhanced metal 

fatigue AMP. The staff also evaluated whether the bases would be adequate for managing the 

metal fatigue in ASME Code Class components or in piping, piping components, or piping 

elements designed to American National Standards Institute (ANSI) B31.1 requirements in 

accordance with 10 CFR 54.21(c)(1)(iii). 

The applicant gives their basis for using CBF-C, CBF-PC, and CBF-EP monitoring methods in 

LRA Section 4.3.1. The staff noted that this is an acceptable basis for how they would apply 

these methods. The applicant clarified that it would count the number of cycles for transients 

used in the analysis for the locations monitored by these methods. The staff also noted that 

these methods would periodically update the cumulative usage factor (CUF) values based on 

actual cycle count data. The staff finds that this is consistent with the “detection of aging 

effects” program element recommendation in the Generic Aging Lessons Learned (GALL) 

Report AMP X.M1, “Metal Fatigue of Reactor Coolant Pressure Boundary.” The applicant also 

clarified the differences between the CBF-C, CBF-PC, and CBF-EP monitoring methods and 

explained how these methods meet ASME Code Section III requirements for CUF calculations. 

The staff finds the applicant’s basis for using CBF-C, CBF-PC, and CBF-EP methods, as 

amended, acceptable because the methods comply with ASME Code Section III requirements 

and are consistent with the recommendations of the GALL Report. 

The staff noted there was conflicting information between the scope of the information provided 

in the original LRA Section 4.3.1 and relevant information in other subsections of LRA 

Section 4.3 concerning the use of “Global” and SBF monitoring methods. 

The staff noted the original LRA Section 4.3.1 states that the “Global” monitoring method will be 

used to count and track transient event cycles affecting the location to ensure that the numbers 

of transient events assumed by the design basis calculations will not be exceeded. However, 

under this monitoring method, the fatigue AMP will not periodically calculate accumulated 

fatigue usage of the component location being monitored. The staff noted that, in contrast, the 

“detection of aging effects” program element in the GALL Report Metal Fatigue AMP 

recommends periodic updates of the CUF calculations. Thus, the staff determined that the 

basis for applying the “Global” monitoring method is not consistent with the recommendations of 

the GALL Report Metal Fatigue AMP. The staff also noted that LRA Section 4.3.1.5 states that 

the use of the “Global” monitoring method would only be applied to component locations with 

low calculated design basis CUF values. However, the staff noted that in the original LRA 

Table 4.3-4, the applicant applied the use of the “Global” monitoring method to both 

components with low and high calculated design basis CUF values. Thus, the staff noted that 

there was conflicting information in the TLAA on how the “Global” monitoring method would be 

applied and that the “Global” monitoring method was not consistent with the CUF update 
Time-Limited Aging Analyses 

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recommendation in the GALL Report Metal Fatigue AMP. A metal fatigue conference calls 

summary document, dated July 14, 2010, summarizes the staff’s discussion with the applicant 

concerning this issue. 

With respect to SBF monitoring methods, the staff noted that on page 4.3-3 of the original LRA 

Section 4.3.1, the applicant said that it intends to apply the SBF monitoring to those component 

locations with high CUF values for which a more refined approach is necessary to show 

long-term structural acceptability. The staff noted that the applicant clarified that SBF 

monitoring updates the CUF calculations for these components using “real time” temperature, 

pressure, and flow histories for the components. The applicant further stated that the 

monitoring method depends on “global-to-local” correlation or “transfer” functions, which 

calculate local transient pressures and temperatures from data collected by the limited number 

of plant instruments to determine local stresses and fatigue usage. The staff noted the original 

LRA Table 4.3-4 states that the SBF monitoring basis could be applied on a bounding basis, 

where the application of SBF monitoring for one component with high valued CUF values would 

also be used as a SBF monitoring basis for other components with high valued CUFs. The 

associated sections of the original LRA (Sections 4.3.1 and 4.3.1.5), however, do not provide 

sufficient justification that the SBF monitoring method could be applied on a bounding SBF 

monitoring basis. While the applicant did provide its action limits and correction actions for SBF 

monitoring in LRA Section 4.3.1.5, the applicant’s bases do not establish how it would apply 

corrective actions for the bounding SBF monitoring basis. Specifically, the staff noted that the 

applicant had not established or justified what type of corrective actions it would apply to 

unmonitored, highly-valued CUF component locations if a CUF action limit was reached for a 

monitored location. A metal fatigue conference calls summary document, dated July 14, 2010, 

summarizes the staff’s discussion with the applicant concerning this issue. 

The staff reviewed the information in TS 5.5.5 and in the original LRA Sections 4.3.1 and 4.3.1.2 

and LRA Table 4.3-2 against relevant design basis information in USAR Sections 3.9.1.1, 

3.7.3.2, 3.9.3, 5.4.1, 5.4.2, 5.4.3, and 5.4.10 and UFSAR Tables 3.9.1-1 and 3.9-1 for 

consistency. The staff also reviewed the information in the original LRA Section 4.3.1.2 and 

LRA Table 4.3-2 against relevant information in other subsections, including the original LRA 

Sections 4.3.2, 4.3.3, 4.3.4 and 4.3.5 and LRA Tables 4.3-3 through 4.3-8. 

TS 5.5.5, “Component Cyclic or Transient Limits,” provides controls to track UFSAR 

Section 3.9.1.1 cyclic and transient occurrences to ensure the applicant maintains components 

within the design limits. During its review, the staff noted there were many inconsistencies 

between the information in LRA Sections 4.3.1, 4.3.1.2, or Table 4.3-2 and design basis 

information in the UFSAR. The staff also noted inconsistencies between subsections and 

between subsections and tables contained in LRA Section 4.3. The following items provide 

examples of the inconsistencies that the staff noted in the original LRA: 

 A given transient is listed in LRA Table 4.3-2 (and and in LRA Table 4.3-3) as a normal 

operating condition, upset condition, or test condition transient but is listed under a 

different transient category in either UFSAR Table 3.9.1-1 or 3.9-1. 

 Normal operating condition, upset condition, or test condition transients that are listed in 

either UFSAR Table 3.9.1-1 or 3.9-1 are not accounted for in LRA Tables 4.3-2 

and 4.3-3. 

 Design basis limit information for a given transient in LRA Table 4.3-2 fails to reflect all 

design basis information or is different from that listed for the corresponding transient in 

either UFSAR Table 3.9.1-1 or 3.9-1. 
Time-Limited Aging Analyses 

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 LRA Table 4.3-2 states that a given transient in LRA 4.3-2 will be counted under the 

program’s tracking activities, but LRA Table 4.3-3 contradicts this by indicating that the 

transient will not be counted under the program’s monitoring activities. 

 Omission of emergency or faulted events in LRA Tables 4.3-2 and 4.3-3 that are within 

the scope of emergency or faulted design basis transients in UFSAR Table 3.9.1-1 

or 3.9-1. 

A metal fatigue conference calls summary document, dated July 14, 2010, describes the staff’s 

discussions with the applicant concerning these and other issues. 

By letter dated April 28, 2010, the applicant submitted Amendment 14 to the LRA to address 

several of these issues. In this letter, the applicant provided updated information concerning the 

enhanced metal fatigue AMP monitoring bases for this TLAA. Specifically, the staff noted that 

the applicant amended the LRA to make the following changes and clarifications: 

 LRA Section 4.3 was amended to use the terminology “cycle counting” monitoring to 

replace the term “Global” monitoring. The staff finds this change to be acceptable 

because the change is administrative and does not affect the staff’s basis for accepting 

the monitoring bases for the enhance fatigue AMP. 

 LRA Section 4.3.1 was changed to clarify that the scope of the enhanced metal fatigue 

AMP will include all ASME Code Section III Class 1 components and Class 2 portions of 

the SGs that have been analyzed to ASME Code requirements for Class 1 components. 

 The enhanced metal fatigue AMP was clarified such that it will continue to monitor for 

plant transients required by TS 5.5.5. In addition, CUFs will be calculated for a subset of 

ASME Code Class 1 reactor coolant pressure boundary vessel and piping components 

and ASME Code Class 2 SG locations that were conservatively analyzed using ASME 

Code Class 1 CUF analysis bases. 

 LRA Sections 4.3.1 and 4.3.1.2 were changed to clarify that the enhanced program 

continues to count transient cycles and will monitor the CUF values for bounding 

locations, as given in amended LRA Table 4.3-4 of Amendment 14. 

 The LRA was amended to clarify the enhanced metal fatigue AMP action limits on 

tracked cycles and CUF values and establish appropriate corrective actions to be taken 

before the licensing basis limits on fatigue effects, at any location, are exceeded. 

The staff evaluated the monitoring bases for the enhanced metal fatigue AMP, as amended and 

verified that the applicant is crediting the enhanced metal fatigue AMP to disposition the TLAAs 

for ASME Code Class 1 components that were designed to ASME Code Section III or for ASME 

Code Class 2 SG components that were analyzed in accordance with ASME Code Section III 

CUF design calculations. The staff verified that the applicant has dispositioned its implicit 

fatigue analyses for safety Class 1 piping designed to ANSI B31.1 requirements or ASME Code 

Class 2 or 3 components designed to ASME Code Section III requirements in accordance with 

10 CFR 54.21(c)(1)(i) or 10 CFR 54.21(c)(1)(ii). Based on this review and verification, the staff 

finds that the applicant’s scope of the enhanced metal fatigue AMP acceptable because it is 

appropriately being used for those ASME Code Class 1 and 2 components that were analyzed 

to ASME Code Section III CUF analysis criteria. 

The applicant amended LRA Sections 4.3.1 and 4.3.1.2 to clarify the differences between the 

current fatigue AMP and the enhanced version of the program that it will carry out during the 

period of extended operation. The applicant clarified that the enhanced metal fatigue AMP will 

use CC, CBF-C, CBF-PC, CBF-EP, and SBF monitoring bases. The staff verified that the 

applicant appropriately revised and updated the contents of LRA Table 4.3-4. 
Time-Limited Aging Analyses 

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In amended LRA Table 4.3-4, the applicant credits the following enhanced metal fatigue AMP 

monitoring bases for ASME Code Class 1 components: 

 SBF monitoring as the 10 CFR 54.21(c)(1)(iii) aging management monitoring basis for 

the pressurizer surge line elbow, which is the limiting environmentally-assisted fatigue 

(EAF) location (i.e., limiting NUREG/CR-6260 location) 

 CBF-PC monitoring as the 10 CFR 54.21(c)(1)(iii) aging management monitoring basis 

for the pressurizer spray nozzles, which are the limiting non-environmental CUF 

components for the current fatigue AMP (limiting design basis CUF value of 0.9923) 

The staff noted that under the amended basis in LRA Table 4.3-4, as given in Amendment 14, 

the applicant currently credits SBF monitoring only for 10 CFR 54.21(c)(1)(iii) management of 

the pressurizer surge line elbow, which according to the LRA is the limiting ASME Code Class 1 

location for EAF. For the current fatigue AMP, the pressurizer spray nozzles are the limiting 

ASME Code Class 1 component (limiting design basis CUF of 0.9923). The updated table does 

not credit SBF for this limiting component. By letter dated July 21, 2010, the staff issued 

RAI 4.3-7 asking the applicant to justify its basis for not evaluating the pressurizer spray nozzles 

for EAF, considering that the pressurizer spray nozzles have a limiting design basis CUF of 

0.9923. This issue was previously identified as part of Open Item 4.3-1. 

In its response dated August 12, 2010, the applicant stated that the surge line elbow location is 

an adequate sentinel location for monitoring because the EAF usage factor is a product of the 

environmental factor (Fen) and design basis CUF. Transients with large, sudden temperature 

shocks that give rise to a high effective strain rate and a lower Fen dominate the pressurizer 

spray nozzle fatigue analysis. By contrast, the applicant stated that the surge line elbow 

experiences a mix of rapid (e.g., insurge, outsurge) and slow (e.g. heatup or cooldown 

stratification) transients, thus, it experiences a higher Fen compared to the pressurizer spray 

nozzle. The staff noted that this is reasonable based on the type of transients experienced by 

each component because components that experience transients with a lower strain rate will 

have a larger Fen value. Furthermore, the applicant also conservatively stated that the surge 

line elbow analysis includes effects from stratification mechanisms while it is known that the 

pressurizer spray nozzle does not experience stratification effects. 

Based on its review, the staff finds the applicant’s response to RAI 4.3-7 acceptable because 

the applicant clarified that the higher Fen value for the surge line elbow will result in a higher EAF 

usage factor compared to the pressurizer spray nozzle. Further, since the stratification effect of 

the surge line and the fatigue analysis are only associated with the surge line elbow, this results 

in the surge line elbow as the bounding component compared to the pressurizer spray nozzle. 

The staff’s concern described in RAI 4.3-7 is resolved and this part of Open Item 4.3-1 is closed. 

In Amendment 14, the applicant modified LRA Sections 4.3.1 and 4.3.1.2 to clarify that it will 

enhance the current fatigue AMP to include additional location-specific CUF calculations and an 

automated and computerized management software program for CC and CBF monitoring within 

two years of entering the period of extended operation. The applicant amended the LRA to 

clarify that the CC monitoring method will track and count transient event cycles to ensure that it 

will not exceed the number of transient events assumed by the design basis calculations, but 

this monitoring method will not perform periodic updates of the CUF calculations. The applicant 

clarified that the automated and computerized software program will automatically track and 

count the design basis transients for the applicant’s facility and that this will supplement the 

applicant’s manual counting of design basis transient occurrences. 

The applicant amended the LRA to clarify the differences between the CBF-C, CBF-PC, and 

CBF-EP monitoring methods and to clarify that the monitoring methods will use both CC and 

CUF monitoring by periodically updating the CUFs for the appropriate components. The 
Time-Limited Aging Analyses 

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applicant also amended the LRA to clarify that FatiguePro® will be used as the enhanced 

program’s software basis for implementing the CC and CBF monitoring methods. 

The staff reviewed the amended CC monitoring basis against SRP-LR Section 4.3.2.1.1.3 and 

to the “parameters monitored or detected,” and “detection of aging effects” program elements in 

the GALL Report Metal Fatigue AMP. The staff noted that for the amended basis for CC 

monitoring, the applicant clarified that the monitoring method will only track and count cycles for 

the design basis transients that are applicable to this TLAA. The staff also noted that, in 

Amendment 14, the applicant clarified that the CC monitoring methodology will apply corrective 

actions if an action limit is reached. The staff noted that in LRA Section 4.3.1.5, the applicant 

states that these corrective actions will include an assessment of the need to perform an 

updated CUF calculation for a component if an action limit is reached. 

Based on this review, the staff finds the applicant’s CC monitoring basis to be acceptable 

because: (1) the amended basis conforms to the staff’s recommendation in the “parameters 

monitored or inspected” program element in the GALL Report Metal Fatigue AMP for cycle 

tracking; (2) the amended basis will conform to the staff recommendation in the “detection of 

aging effects” program element in the GALL Report Metal Fatigue AMP for performing periodic 

CUF updates when a CC action limit is reached and an update of the CUF calculation is 

determined to be the appropriate corrective action for the applicable component; and (3) this is 

consistent with the recommendations in SRP-LR Section 4.3.2.1.1.3. 

The staff reviewed the amended CBF-C, CBF-PC, and CBF-EP monitoring bases against 

SRP-LR Section 4.3.2.1.1.3 and the “parameters monitored or detected,” and “detection of 

aging effects” program element recommendations in the GALL Report Metal Fatigue AMP. The 

staff noted that the FatiguePro® software basis for implementing the CBF-C, CBF-PC and 

CBF-EP methodologies include both CC applications and periodic CUF update bases. The staff 

determined that the CBF-C, CBF-PC, and CBF-EP monitoring methodologies are all acceptable 

ways of performing periodic CUF calculations because they involve an acceptable ASME Code 

Section III stress calculation methodology. 

Based on this review, the staff finds the applicant’s basis for applying CBF-C, CBF-PC, and 

CBF-EP monitoring methods to be acceptable for three reasons: (1) the amended basis 

conforms to the staff’s recommendation in the “parameters monitored or inspected” program 

element in the GALL Report Metal Fatigue AMP for cycle tracking; (2) the amended basis 

conforms to the staff’s recommendation in the “detection of aging effects” program element in 

the GALL Report Metal Fatigue AMP for periodic CUF updates; and (3) this conforms to the 

recommendations in SRP-LR Section 4.3.2.1.1.3 to accept TLAAs on metal fatigue and manage 

metal fatigue in accordance with 10 CFR 54.21(c)(1)(iii). 

In Regulatory Information Summary (RIS) 2008-30, the staff raised technical concerns related to 

the conservatism of using one-dimensional stress models for the evaluation of EAF in limiting 

locations. For these locations, the staff recommended that the applicant use three-dimensional 

stress models conforming to ASME Code Section III requirements to confirm that 

one-dimensional stress models are conservative. 

In Amendment 14, the applicant committed to the use of a software program for SBF monitoring 

of the pressurizer surge line (hot leg) elbow that incorporates a three-dimensional, six-element 

stress tensor method to meet the ASME Code Section III NB-3200 requirements. The applicant 

also committed to the implementation of this software at least two years before entering the 

period of extended operation. The applicant amended the “Methods” statement in LRA 

Section 4.3.1 to clarify how it would use SBF monitoring methods relative to ASME Code 

Section III requirements, based on the results of real stress histories for the components 

evaluated. 
Time-Limited Aging Analyses 

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The staff reviewed the amended SBF monitoring basis against SRP-LR Section 4.3.2.1.1.3 and 

the “detection of aging effects” and “monitoring and trending” program elements in the GALL 

Report Metal Fatigue AMP. The staff also reviewed the amended basis against the staff’s 

requirements for performing stress analyses and CUF calculations in the ASME Code 

Section III, as invoked by reference in 10 CFR 50.55a, “Codes and Standards,” and the staff’s 

recommendations for performing these type of analyses in RIS 2008–30. 

In Amendment 14, the applicant modified Commitment No. 39. LRA Sections A2.1, A3.2, and 

B3.1 noted this change to reflect the use of a fatigue monitoring software program and methods 

for SBF monitoring that will carry out a three-dimensional, six-element tensor stress analysis 

method and conform to the requirements of ASME Code Section III Article NB-3200. Thus, the 

staff noted that this commitment has been placed on both the UFSAR supplement for this TLAA 

and the UFSAR supplement for the applicant’s enhanced metal fatigue AMP for purposes of 

addressing the technical issues raised and discussed in RIS 2008–30. 

The staff also noted that, in Amendment 14, the applicant no longer credits its SBF monitoring 

on a bounding basis. The staff finds that this change resolves the staff’s concern discussed 

earlier in this section. 

Based on this review, the staff finds the applicant’s amended basis for using SBF monitoring to 

be acceptable based on the following criteria and conclusions: 

 The applicant no longer credits SBF monitoring on a bounding basis and will apply SBF 

monitoring methods to each applicable component. 

 The amended basis does not credit a version of FatiguePro® which uses a 

one-dimensional stress-intensity term in lieu of a six-element stress tensor as the 

software basis for SBF monitoring. Instead, it addresses the need to implement a SBF 

monitoring software program and methodology that comply with the requirements in the 

ASME Code Section III and that conform to the technical recommendations in 

RIS 2008–30. 

 The staff has verified that Commitment No. 39 reflects this basis, as updated in LRA 

Amendment 14, and that the commitment is in the UFSAR supplements for both this 

TLAA and the enhanced metal fatigue AMP. 

 When the enhanced program is implemented for SBF monitoring during the period of 

extended operation, the software program and methodology will be in compliance with 

the stress analysis criteria in the ASME Code Section III, Article NB-3200, the 

requirements in 10 CFR 50.55a, “Codes and Standards,” and in conformance with the 

technical analysis recommendations in NRC RIS 2008–30. 

 The amended basis conforms to the recommendations in SRP-LR for using SBF 

monitoring as a basis for accepting TLAAs in accordance with 10 CFR 54.21(c)(1)(iii) 

and with the recommendations in the GALL Report Metal Fatigue AMP for performing 

periodic updates of CUF calculations. 

Based on its review, the staff finds the applicant has demonstrated that the enhanced Metal 

Fatigue Program is acceptable because the applicant has described how it will implement the 

monitoring methods (CC, CBF-C, CBF-PC, CBF-EP, and SBF) consistent with the 

recommendations of the GALL Report AMP for those components that require aging 

management for cumulative fatigue damage. 

4.3.1.2.3 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii) that the effects of aging due to fatigue on the 
Time-Limited Aging Analyses 

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intended functions of the components within the scope of the enhanced Metal Fatigue Program 

will be adequately managed for the period of extended operation. 

4.3.1.3 Seismic History 

4.3.1.3.1 Summary of Technical Information in the License Renewal Application 

In LRA Section 4.3.1.3, the applicant gives a brief description of seismic design basis 

requirements and seismic transient history. The applicant clarifies that those design analyses 

that compared seismic loads to allowable component or structure stress allowable loads are not 

TLAAs. The applicant states, however, that the design of systems, structures, and components 

may include seismic loads in the fatigue analyses or may assume a stated number of seismic 

load cycles for the purpose of establishing an allowable stress or stress range (e.g., as would be 

used in implicit fatigue analyses of ANSI B31.1 components or Code Class 2 or 3 components 

designed to ASME Code Section III). 

The applicant states that for design purposes, the safe-shutdown earthquake (SSE) is based on 

a 0.20 gravity ground-motion stress, and the OBE is based on a 0.10 gravity ground-motion 

stress. The applicant states that for the purposes of evaluating actual earthquake events, an 

SSE is defined as an earthquake that results in a categorization of eight on a Mercalli intensity 

scale seven (i.e., results in ground-motion ranging stresses ranging from 0.15 gravity to 

0.33 gravity). An OBE is defined as an earthquake that results in a categorization of seven on a 

Mercalli intensity scale (i.e., results in ground-motion stresses ranging from 0.072 gravity to 

0.15 gravity). The applicant summarizes that, as of 2008, only seven minor earthquakes have 

occurred and that the strongest of these earthquakes resulted in ground-motion stresses of only 

approximately 0.015 gravity. The applicant states that there have not been any recorded SSE 

or OBE events to date. 

4.3.1.3.2 Staff Evaluation 

The staff reviewed the SSE and OBE information in LRA Section 4.3.1.3 against the applicant’s 

transient categories for these events in LRA Tables 4.3-2 and 4.3-3. The staff noted that in the 

original LRA, Tables 4.3-2 and 4.3-3 included two earthquake transient categories: 

(1) Transient 27, “Operating Basis Earthquake,” which represents that transient category for 

OBE events, and (2) Transient 39, “Seismic Event Up To and Including One-half of the 

Safe-shutdown Earthquake, at 100% Power,” which represents the transient category for 

non-SSE and non-OBE seismic events. 

The staff noted that UFSAR Table 3.9.1-1 lists Transient 27, “Operating Basis Earthquake,” as 

one of the upset condition transients that is applicable to the ASME Code Class 1 NSSS 

components (the reactor vessel components), and the design basis sets a limit of 

200 occurrences for this transient. The staff also noted that UFSAR Table 3.9-1, item I.F.2.a 

lists Transient 39, “Seismic Event Up To and Including One-half of the Safe-shutdown 

Earthquake, at 100% Power,” as an upset condition transient that is applicable to the Class 1 

RCS piping components. The staff verified that LRA Tables 4.3-2 and 4.3-3 appropriately 

reflected the cycle occurrence design limit of 200 for Transient 27 and the cycle occurrence 

design limit of 2 for Transient 39. Thus, the staff finds that LRA Tables 4.3-2 and 4.3-3 reflected 

the appropriate design basis cycle occurrence limit information for Transients 27 and 39. The 

staff noted that in Amendment 14, the applicant administratively changed the transient number 

for the “Operating Basis Earthquake” transient from Transient 27 to Transient 32, and the 

“Seismic Event Up To and Including One-half of the Safe-shutdown Earthquake, at 

100% Power,” transient from Transient 39 to Transient 44. SER Section 4.3.1.4 supplies the 

staff’s evaluation on the applicant’s basis for projecting the number of cycles that will occur for 

these transients through the expiration of the period of extended operation (60-year cycle 

projections for these transients). 
Time-Limited Aging Analyses 

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The staff also noted that the design basis in UFSAR Section 3.9.1.1 includes the faulted 

condition transient “Seismic Event Up To and Including One-half of the Safe-shutdown 

Earthquake, at 100% Power,” which is listed as an UFSAR Table 3.9-1 faulted condition 

transient I.F.4.a for Class 1 RCS piping components and faulted condition transient II.E4.a for 

Class 1 portions of the chemical and volume control system. The staff determined that the 

applicant appropriately accounted for this transient in the amended LRA Tables 4.3-2 and 4.3-3. 

SER Section 4.3.1.4.2 provides the staff’s evaluation as to whether the applicant should track 

and count this transient under the enhanced metal fatigue AMP. 

4.3.1.3.3 Conclusion 

Based on its review, the staff concludes that LRA Tables 4.3-2 and 4.3-3 reflect the appropriate 

design basis limit values for Transient 27, “Operating Basis Earthquake,” and Transient 39, 

“Seismic Event Up To and Including One-half of the Safe-shutdown Earthquake, at 

100% Power.” SER Section 4.3.1.4 gives the staff’s evaluation of the applicant’s 60-year cycle 

projections for Transients 27 and 39 and basis for omitting the “Seismic Event Up To and 

Including One-half of the Safe-Shutdown Earthquake, at 100% Power,” transient from the scope 

of LRA Tables 4.3-2 and 4.3-3. 

4.3.1.4 Present and Projected Status of Monitored Locations 

4.3.1.4.1 Summary of Technical Information in the License Renewal Application 

The applicant provides its basis for establishing the current transient occurrence values (cycle 

values) and the transient values that are projected for the period of extended operation (60-year 

cycle values) in LRA Section 4.3.1.4. In this section, the applicant includes a summary of the 

methodology used to project the cycle occurrence values for the design basis transients to the 

expiration of the period of extended operation (i.e., 60-year cycle projection methods). The 

section also includes LRA Table 4.3-3, which gives the applicant’s current cycle and 60-year 

cycle data based on the applicant’s implementation of its 60-year cycle projection methods. 

LRA Table 4.3-2 summarizes the design basis limit criteria for the design basis transients that 

are involved with this TLAA derived from transient information in UFSAR Tables 3.9.1-1 

or 3.9-1. 

In LRA Amendment 14, the applicant revised its basis methodology for projecting the cycle 

occurrence values for the design basis transients to the expiration of the period of extended 

operation (i.e., 60-year cycle projection methodology for the design basis transients). 

4.3.1.4.2 Staff Evaluation 

The staff reviewed the 60-year cycle projection methodology in LRA Section 4.3.1.4 and the 

60-year cycle projection data in LRA Table 4.3-3 against SRP-LR Section 4.3.2.1.1.1 to 

determine whether sufficient information has been provided to demonstrate that “the number of 

assumed transients would not be exceeded during the period of extended operation” and to 

ensure that existing CUF or implicit fatigue calculations remain valid for the period of extended 

operation in accordance with 10 CFR 54.21(c)(1)(i). The staff also reviewed the 60-year 

projection methodology, the 60-year projection basis, and data in LRA Table 4.3-3 against 

applicable requirements for design basis transient cycle tracking in TS 5.5.5 and applicable 

design basis transient information in UFSAR Section 3.9.1.1 and UFSAR Tables 3.9.1-1 

and 3.9-1. 

The staff noted the applicant’s footnotes for LRA Tables 4.3-2 and 4.3-3 stated that only “normal 

operation condition,” “upset condition,” and “test condition” transients needed to be tracked 

under the current version and enhanced version of its fatigue AMP. However, the staff also 

noted that there were inconsistencies between the design basis transients that the applicant had 

included in LRA Tables 4.3-2 and 4.3-3 and the design basis transients that were listed in 

UFSAR Section 3.9.1.1 and Tables 3.9.1-1 and 3.9-1. The staff also noted that there were 
Time-Limited Aging Analyses 

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issues with respect to the applicant’s basis for projecting cycles to the expiration of the period of 

extended operation. The following bulleted list gives examples of the types of inconsistencies 

that the staff noted in the LRA prior to LRA Amendment 14: 

 Upset condition and test condition transients in UFSAR Table 3.9-1 are missing from the 

scope of LRA Tables 4.3-2 and 4.3-3. 

 Faulted and Emergency transient events listed in UFSAR Tables 3.9.1-1 and 3.9-1 are 

missing from the scope of LRA Tables 4.3-2 and 4.3-3. 

 Inconsistencies exist between a given transient definition in LRA Tables 4.3-2 and 4.3-3 

from the definition in UFSAR Tables 3.9.1-1 or Table 3.9-1 (i.e., the LRA originally lists 

Transient 50, “Depressurization by MSSV at 100% Power,” as an upset condition and 

UFSAR Table 3.9-1 item I.C.3.a identifies this transient as an emergency condition 

transient) 

 For a given transient, inconsistencies, such that the information for the given transient in 

LRA Section 4.3-2, are contradicted by information for the same transient in LRA 

Table 4.3-3. 

 Proposals to track one design basis transient as a basis for tracking a different design 

basis transient when the UFSAR says that the transients are being applied to a different 

set of components. 

By letter dated April 28, 2010, the applicant submitted LRA Amendment 14 to address these 

issues. In the amendment, the applicant indicated that it had performed a revised recount of the 

design basis transients that had occurred before January 1996 in order to reconstitute a best 

estimate of the transients that occurred from the time of initial operations through 1995. The 

applicant reviewed the following documents to perform the recount activities and its best 

estimate transient recount numbers: control room logs, NRC monthly operating reports, and 

Licensee Event Reports. The staff finds this to be an acceptable basis for performing the 

recount activities because these documents appropriately record applicable normal operating 

condition, upset condition, and test condition transients, from which the applicant may 

reconstitute transient occurrences. 

The applicant said that they added the updated design basis transient recount numbers to those 

transients that were actually tracked and counted in accordance with TS 5.5.5 for the period 

from January 1996 through the end of December 2005. The staff noted that the totals were 

used to establish the applicant’s best count estimate for the design basis transients from initial 

unit operation through end of 2005. The staff also noted that, based on these count totals, the 

applicant used the following linear extrapolation model to project the number of transient 

occurrences that would occur through to the end of the period of extended operation: 

 For most transients, the applicant used Unit 3 time of operation through year 2005 

(18 years) as the basis deriving the linear scaling factor for the analysis (i.e., 60/18 years 

= scaling factor of 3.33). 

 For some transients, the applicant applied a scaling factor of 6.66 when the available 

transient data was only available for a 10-year period (1995–2005). 

 To derive the 60-year projection totals for each transient, the applicant used the highest 

accumulation total from the three unit counting activities to derive the transient total for 

the TLAA. The applicant multiplied this value by the applicable scaling factor (3.33 if the 

count totals were based on counts performed over an 18–20 year period and 6.66 if the 

count totals were based on counts performed over a 10-year period). 
Time-Limited Aging Analyses 

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The staff finds this revised projection basis to be acceptable because it relies on actual transient 

count data and uses the unit with the least amount of operating time to derive the linear scaling 

factor for the applicant’s 60-year transient projections. 

The staff noted that the amendment modified Tables 4.3-2 and 4.3-3 to update the list of 

transients provided in the original LRA, such that the list and descriptions of transients are 

consistent with those with the design basis transients. The staff noted that the applicant’s 

amendment to the tables are consistent with UFSAR Section 3.9.1.1 and UFSAR Tables 3.9.1-1 

and 3.9-1, which are referenced in TS 5.5.5. The staff noted that in the amended Table 4.3-3, 

the applicant increased the number of transients listed from 61 to 83 transients. The staff also 

noted that in amended Table 4.3-3, the applicant provided an update to the cumulative cycle 

counts for the transients from plant start up through the beginning of 2006. The applicant 

provided its revised 60-year transient projections, which were based on the applicant’s updated 

recount activities and new 60-year linear scaling model (except for 6 transients in which the 

applicant still assumed 25-percent of the design basis limit). 

In the update of Tables 4.3-2 and 4.3-3, the applicant no longer used bolded and non-bolded 

text as a basis for designating whether a given design basis transient would be counted or not. 

This resolved the staff’s concern in the original LRA on the inconsistency in counting basis 

information for Transient 8, “RC Pump Starting”; Transient 9, “RC Pump Stopping”; Transient 

10, “Cold Feedwater Following Hot Standby”; Transient 22, “Initiation of Shutdown Cooling”; and 

Transient 34, “Partial Loss of Condenser Cooling at 100% Power.” 

In the update of Table 4.3-3, the applicant no longer tied its tracking of upset condition 

Transient 32 (OBE Condition) as the basis for counting the number of occurrences for the 

Transient 44, “Seismic Event up to and Including One-Half of the Safe Shutdown Earthquake, at 

100% Power.” This revision made the design basis, recount, and 60-year projection bases for 

Transient 32 and Transient 44 consistent with those for the transients in UFSAR Table 3.9.1-1 

and Table 3.9-1, respectively, and resolved the staff’s concern. 

Following modification of LRA Tables 4.3-2 and 4.3-3 in Amendment 14, the staff is unable to 

determine which of the transients the 25-percent assumed occurrences basis is applied. By 

letter dated June 2, 2010, the staff issued RAI 4.3-1 asking the applicant to clarify when the 

25-percent assumed transient occurrence basis was used in LRA Tables 4.3-2 and 4.3-3 and to 

justify why this assumption yields a conservative 60-year cycle basis. This was previously 

identified as part of Open Item 4.3-1. 

In its response dated June 29, 2010, the applicant stated that it elected to retain the 25 percent 

assumed transient accumulation for fourteen transients. The staff noted that the list of these 

transients is provided in Table RAI 4.3-1 of the applicant’s response. The applicant stated that 

for Transients 13, 26, 27, 57, 59, 60, 80, 82, and 83, a review of logs, Licensee Event Reports, 

NRC Monthly Operating Reports and test records revealed that either the transients had not 

occurred between 1985−1995 or that the 25 percent assumption was not exceeded. The staff 

noted that since these transients were confirmed not to have occurred during 1985−1995 or did 

not exceed the 25 percent assumption, it is conservative for the applicant to assume that these 

transients occurred at 25 percent of the design limit. For these transients, the staff finds it 

acceptable that the applicant continued to use the 25 percent assumption because the applicant 

conservatively assumed the transient has occurred even though it was confirmed that the 

transients did not occur or did not exceed this assumption by a review of documentation from 

1985-1995. 

The applicant also stated in its June response that for Transients 8, 9, and 18, the counted 

accumulation of events between 1995−2005 were less than 5 percent of the limiting values. 

The staff noted that for these transients the review of plant records did not confirm an actual 

count because of inconsistencies or lack of specific details in plant records. Therefore, the 
Time-Limited Aging Analyses 

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applicant compared the actual occurrences of these transients and compared it to the 

25 percent assumption used from 1985−1995. The staff noted that this comparison indicated 

that the number of occurrence in the 25 percent assumption was greater than the number of 

actual occurrences from 1995−2005. For these transients, the staff finds it acceptable that the 

applicant continued to use the 25 percent assumption because the applicant conservatively 

assumed a larger of number of occurrences when compared to actual occurrences from 

1995−2005 to account for variations in earlier years of operation. 

The applicant also stated in its June response that for Transients 20 and 21, the tests occur at 

scheduled intervals with occasional tests being performed for post maintenance testing, so the 

rate of occurrence is constant, which lends itself to a reasonably accurate prediction of 

accumulation. The staff noted that the LPSI pump runs were assumed to occur at a rate of 

15.6 occurrences per year for 1985−1995 compared to a rate of 12.7 occurrences per year 

between 1995−2005. For these transients, the staff finds it reasonable that the applicant 

continued to use the 25 percent assumption because of the routine and consistent occurrence 

of these transients. The applicant’s assumption was conservative compared to the actual 

occurrences from 1995−2005. 

The applicant stated the transient totals were projected to the end of the period of extended 

operation for information only. The applicant also stated there will be specific and targeted 

action limits to ensure actual fatigue limits are not exceeded. These corrective actions will be 

triggered by the limit established in the enhanced Metal Fatigue Program. 

The staff finds the applicant’s response to RAI 4.3-1 acceptable because the applicant justified 

its use of the 25 percent assumption for the transients as described above to obtain a 

conservative baseline for transient occurrences. Also, it is acceptable because the applicant will 

use the enhanced Metal Fatigue Program for continued tracking of these transients. This will 

ensure that when an action limit is reached, corrective actions are taken to maintain fatigue 

usage below the design limit of 1.0. The staff’s concern described in RAI 4.3-1 is resolved and 

this part of Open Item 4.3-1 is closed. 

In addition, the staff noted that the update of LRA Table 4.3-3 indicated that the applicant would 

not count Transient 3 (5 percent per minute ramp increase from 15 percent to 100 percent 

power) and Transient 4 (5 percent per minute ramp decrease from 15 percent to 100 percent 

power). The staff noted that these transients are in UFSAR Table 3.9-1 and UFSAR 

Section 3.9.1.1, which is referenced in TS 5.5.5. By letter dated June 2, 2010, the staff issued 

RAI 4.3-2 asking the applicant to clarify with justification whether these transients are required 

to be counted per TS 5.5.5 and UFSAR Section 3.9.1.1. If so, the staff asked that the applicant 

clarify the actions that it will take to resolve the apparent inconsistency if it determines there is a 

valid technical basis for not counting these transients. The staff also asked the applicant to 

clarify whether Transient 3 or Transient 4 has ever occurred and to justify its basis for not 

counting these transients. This was previously identified as part of Open Item 4.3-1. 

In its response to RAI 4.3-2 requests 1 and 2, dated June 29, 2010, the applicant stated the 

program specified in TS.5.5.5 provides controls to track the UFSAR Section 3.9.1.1 cyclic and 

transient occurrences to ensure that components are maintained within the design limits. The 

applicant further stated that the controls to track cyclic and transient occurrences are 

implemented by either counting the occurrences or by accounting for the occurrences such that 

components are maintained within the design limits. The applicant also stated that a Licensing 

Document Change Request is being developed to add this clarification to UFSAR 

Section 3.9.1.1. 

The applicant stated that the intent of Transients 3 and 4 was primarily to address the daily 

changes in grid demand that have been historically observed at other plants. The applicant 

stated that its design accommodates these types of cyclic load swings as well as the infrequent 
Time-Limited Aging Analyses 

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variations in power required by equipment maintenance, Technical Specifications action 

statements, or other operational considerations. 

The applicant stated that it has followed a base load strategy since initial operation in each of 

the three units and that using a 90-percent capacity factor and 60 years of operation, one can 

calculate that 15,000 power change cycles would require one cycle every 31.6 hours. The staff 

noted that unless a plant operates with a load following strategy, this number is not credible 

since power changes for maintenance, Technical Specifications action statements and 

operational considerations are infrequent. The applicant stated that its operating strategy does 

not include load following, therefore, these transients are accounted for such that components 

are maintained within the design limits. 

The applicant stated that there is no design feature that would prevent it from making power 

changes to load-follow at the request of the load dispatcher. However, a review performed by 

the applicant of control room logs for the period of 1985−1995 to reconstruct transient history 

did not identify any load following power changes as defined in UFSAR Table 3.9.1-1. The staff 

noted that the applicant also reviewed dispatch procedures, the PVNGS owner-participant 

agreement, and a recent operating agent filing of annual resource planning. The applicant 

stated that this review determined that in the event of a grid condition requiring power reduction, 

the PVNGS units have priority to operate as base load power (not fluctuating), so that fossil-fuel 

power plants absorb changes in consumer demand. Further, power generation planning 

models used by the applicant indicate the intent to operate PVNGS as a base load plant. 

The applicant stated that its reviews support the conclusion that it has not experienced 

Transients 3 or 4 due to load following and that the intention for the foreseeable future is to 

continue to operate its units as base loaded units. The applicant provided a table showing the 

number of power changes that occurred in each unit during the 24-month period of 2006−2007. 

The staff noted that the power changes experienced by each unit were the result of refueling 

outages, maintenance, post reactor trip startups or Technical Specifications action statements. 

Based on its review, the staff finds the applicant’s response to RAI 4.3-2, requests 1 and 2 

acceptable because: (1) the applicant demonstrated that power changes are the result of 

refueling outages, maintenance, post reactor trip startups or TS action statements and not the 

result of load following, (2) the applicant’s review confirmed that load following power changes 

have not occurred from 1985−1995, (3) the applicant's intent is to operate the plant as a base 

load plant, thus accounting for Transients 3 and 4, and (4) the applicant will update its UFSAR 

to clarify that it can track transient occurrences by counting the occurrences or by accounting for 

the occurrences. The staff’s concern described in RAI 4.3-2, request 1 and 2 is resolved and 

this part of Open Item 4.3-1 is closed. 

In its response to RAI 4.3-2, request 3, dated June 29, 2010, the applicant stated that the 

analyses for all three units include the same load following cycles (15,000 increase and 

15,000 decrease) and the differences are not due to differences in geometry, materials, loading, 

or transients, but are due to modeling and analysis methods and assumptions. The applicant 

stated that one difference is that the Unit 1 analysis used a more conservative treatment of 

vortex shedding. The applicant further stated that some modeling differences resulted in a 

slightly different limiting location between the three units and arithmetic load addition was used 

instead of vector load addition at the limiting Unit 1 location. Furthermore, the vortex shedding 

difference produced a larger number of assumed vortex shedding load cycles for Unit 1 which 

was a significant factor in the difference. 

The staff was unclear if vortex shedding was accounted for in the fatigue analysis for Units 2 

and 3 and why the Unit 1 analysis treats vortex shedding so conservatively. It was also not 

clear to the staff why the stress ranges were slightly lower for the analyses for Units 2 and 3 as 

compared to Unit 1. The staff held a teleconference with the applicant on September 22, 2010, 
Time-Limited Aging Analyses 

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for clarification. By letter dated October 13, 2010, the applicant clarified its response to 

RAI 4.3-2, request 3, by stating that vortex shedding at the instrument nozzle is present at all 

times while the unit is in operation or the reactor coolant pumps are running, therefore, it is 

applicable to all transients associated with the reactor vessel instrument nozzle analysis. The 

applicant stated that CE designed the instrument nozzle such that the natural frequency of the 

nozzle (approximately 347 cycles per second) was not close to the vortex shedding frequency 

(254 cycles per second) to avoid a resonance condition, and it accounted for the hydraulic loads 

imposed on the nozzle and J-weld attachment to the vessel wall. 

The applicant stated that the reports for all three units considered vortex shedding in the 

analyses and the same analyst prepared all three of the reports: Unit 1 in 1978, Unit 2 in 1979, 

and Unit 3 in 1981. The applicant explained that the main differences between each of the 

analyses are as follows: 

 The reports for Units 2 and 3 utilized a more thorough evaluation in that 

more cuts were used in the determination of stresses in the critical areas 

of the instrument nozzle. 

 All three reports account for the operating loads, external loads as well as 

hydraulic loads from vortex shedding, but the reports for Units 2 and 3 

implicitly demonstrate that the vortex shedding hydraulic loads and their 

corresponding alternating stresses are below the endurance limit. As 

such, it is not required to be superimposed as a separate transient with all 

the other design transients. Nevertheless, this external load was included 

with the other loads in the fatigue analysis and it was shown that the CUF 

was below 1.0. 

This is consistent with the ASME NB-3200 fatigue analysis where vibration is not combined with 

other service loads in the fatigue evaluation. The Unit 1 report performed a more simplified 

conservative analysis and normalized all of the plant transients to 254 cps so that the vortex 

shedding load transient (with equivalent 109 cycles) could be superimposed as a separate 

transient and paired up with other plant design transients. In addition, the Unit 1 report utilized a 

commercial fatigue curve in lieu of the ASME Figure 1-9.2 to calculate a usage factor beyond 

106

 cycles which resulted in the higher CUF factor. 

The staff determined that the “thorough evaluation” performed by the applicant in the Units 2 

and 3 reports is reasonable since the applicant used more cuts in the determination of stresses 

which provides a more refined model of stresses in the components. The staff also noted that 

the applicant demonstrated in the Unit 2 and 3 analyses that the vortex shedding hydraulic 

loads and their corresponding alternating stresses are below the endurance limit. The staff 

noted that if the alternating stresses are below the endurance limit the fatigue life can be 

considered infinite because of the extremely large number of cycles the material can endure 

(107

 cycles). The staff noted that all three analyses considered the effects of vortex shedding. 

Furthermore, for the Unit 1 analyses the applicant used a simplified method by normalizing the 

vortex shedding transient so it was possible to pair the vortex shedding transient with other plant 

design transients. The staff finds this to be a conservative approach because the applicant 

paired the vortex shedding transient with other transients even though the vortex shedding 

hydraulic loads and its alternating stresses are below the endurance limit. The staff noted that 

this conservative treatment accounts for the larger CUF value. 

Based on its review, the staff finds the applicant’s response to RAI 4.3-2, request 3, as 

amended, acceptable because the applicant accounted for the operating loads, external loads 

and hydraulic loads from vortex shedding in the analyses for Units 1, 2 and 3, and because the 

applicant conservatively addressed vortex shedding in the Unit 1 analyses even though the 

alternating stresses were below the endurance limit. Finally, the response is acceptable 
Time-Limited Aging Analyses 

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because the applicant clarified why the CUF for the RPV instrument nozzle was higher in the 

Unit 1 analysis when compared to the Unit 2 and 3 analyses. The staff’s concern described in 

RAI 4.3-2, request 3 is resolved and this part of Open Item 4.3-1 is closed. 

In the updated LRA Table 4.3-2, the applicant lists Transient 17, “Initiation of Auxiliary Spray,” 

as an applicable normal operating condition transient. In the updated LRA Table 4.3-3, the 

applicant stated that it will correlate the tracking of Transient 17 to the tracking of pressurizer 

cooldown events, which is listed in these updated tables as Transient 12, “Pressurizer cooldown 

from 563oF to 70oF at a rate of ≤ 200oF/hr.” It is not clear to the staff whether Transient 17 is 

referring to an initiation of the pressurizer spray system or an initiation of the containment spray 

system. It is also not clear to the staff why it is valid to correlate the tracking of Transient 17 to 

the tracking of Transient 12. By letter dated July 21, 2010, the staff issued RAI 4.3-8 asking the 

applicant clarify whether Transient 17 is referring to an initiation of the pressurizer spray system 

or an initiation of the containment spray system. The staff also asked the applicant to provide 

its basis for correlating Transient 17 to Transient 12. This was previously identified as part of 

Open Item 4.3-1. 

In its response dated August 12, 2010, the applicant stated that Transient 17 in LRA Table 4.3-2 

and 4.3-3, “Initiation of auxiliary spray during cooldown,” refers to the initiation of auxiliary 

pressurizer spray during pressurizer cooldown. The applicant also stated that auxiliary 

pressurizer spray is used to complete pressurizer cooldown when the main pressurizer spray 

becomes unavailable during plant cooldown. During plant cooldown and depressurization, the 

reactor coolant pumps must be secured prior to full depressurization; this results in a loss of the 

reactor coolant pump differential pressure which drives the normal pressure spray. The 

applicant concluded that the initiation of auxiliary spray during cooldown (Transient 17) is 

related to the number of pressurizer cooldowns (Transient 12). The staff noted that based on 

the applicant’s operating practices it is reasonable to correlate the tracking of Transient 17 to 

the tracking of Transient 12. The staff confirmed the applicant’s response by verifying the 

information in the UFSAR Section 5.4.10 that discusses that the auxiliary spray line is provided 

to allow cooling if the reactor coolant pumps are secured. 

Based on its review, the staff finds the applicant’s response to RAI 4.3-8 acceptable because 

the applicant clarified the initiation of the transient and provided the relationship between the 

two transients. The applicant explained the sequence of events to initiate auxiliary spray during 

cooldown which provided the basis for the correlation between Transient 17 and Transient 12. 

The staff’s concern described in RAI 4.3-8 is resolved and this part of Open Item 4.3-1 is closed. 

The staff noted that the update of LRA Table 4.3-3 provided counting and 60-year projections 

for Transient 25, “Standby to SI hot leg injection check valve stroke test to standby (using the 

high-pressure safety injection (HPSI) pump).” The applicant stated that the test is conducted 

during refueling outages and that the transient is not currently counted because it was recently 

identified and added to UFSAR Table 3.9-1. The applicant also stated that the transient will be 

counted when it is added to the scope of the transient CC procedure. The staff noted that the 

applicant identified 16 occurrences of this transient for Units 1 and 3, and 17 occurrences for 

Unit 2, through December 31, 2005. The staff also noted this transient is projected to occur 

57 times through the end of the period of extended operation. The staff determined there is an 

inconsistency in the recording of occurrences for this transient between January 1, 2006, and 

the time when the transient will be accounted in a future revision of the transient CC procedure. 

By letter dated July 21, 2010, the staff issued RAI 4.3-9, asking the applicant to clarify if the 

transient CC procedure has been updated to include Transient 25 and, if not, when the 

procedure will be updated to include this transient. The staff also asked that the applicant to 

explain how it will ensure that it accounts for all occurrences of Transient 25. This was 

previously identified as part of Open Item 4.3-1. 
Time-Limited Aging Analyses 

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The applicant's August 12, 2010, response stated that in LRA Amendment 14 (April 28, 2010) 

the applicant committed (Commitment No. 55) to the following: 

The transient in UFSAR Table 3.9-1, items I.E.1.b and III.A.1.f, “Standby to SI hot 

leg injection check valve stroke test to standby (using the HPSI pump)” will be 

added to the CC surveillance procedure 73T-9RC02 by August 25, 2010. 

The applicant also stated that LRA Table 4.3-3 was revised in Amendment 14 to include the 

total number of occurrences for the period 1985−2005 based on plant refueling history. 

Based on its review, the staff finds the applicant’s response to RAI 4.3-9 acceptable because 

the CC surveillance procedure was updated to include Transient 25 and the applicant’s 

enhanced Metal Fatigue Program will monitor this transient during the period of extended 

operation to ensure that it does not exceed the design limit. The staff’s concern described in 

RAI 4.3-9 is resolved. This part of Open Item 4.3-1 is closed. 

In the update to Table 4.3-3, the applicant provided its counting and 60-year projections for 

Transient 79, “Reactor coolant system leak test.” For this transient, the applicant stated that its 

recent recount found that the transient occurred five times for Unit 1, four times for Unit 2, and 

two times for Unit 3 through end of December 2005. It is not clear to the staff whether this 

transient represents the system leak test for the RCP boundary, mandated by ASME Code 

Section XI, Table IWB-2500-1, Examination Category B-P and 10 CFR 50.55a. The staff noted 

that this ASME Code requirement involves pressurizing the RCP boundary once every refueling 

outage to normal operating pressure and performing a visual examination of the system’s 

components for evidence of reactor coolant leakage. The staff noted that the applicant has 

been operating for about 22–24 years of licensed operation. Thus, based on the time from 

initial operation, the staff estimates that the RCS leak test would have occurred approximately 

14–16 times since initial operations of the units. By letter dated July 21, 2010, the staff issued 

RAI 4.3-10 asking the applicant clarify whether Transient 79 is different from the system leak 

test that is required by ASME Code Section XI. If the transient and the ASME Code Section XI 

system leak are different, the staff asked the applicant to clarify how it will track the ASME Code 

Section XI system leak. Furthermore, if these two are not different, the applicant must justify the 

number of occurrences stated in the LRA. This was previously identified as part of Open 

Item 4.3-1. 

In its response dated August 12, 2010, the applicant indicated that the Transient 79, “Reactor 

Coolant System Leak Test,” test condition is listed in UFSAR Table 3.9.1-1 and does represent 

the ASME Code Section XI system leak test. The applicant explained that the associated 

ASME Code fatigue analyses determined the cumulative fatigue resulting from the specified 

transients in UFSAR Table 3.9.1-1, including 500 heatup and cooldown cycles in which the 

pressure and temperature range from 15 psia and 80 degrees F to 2250 psia and 

565 degrees F and back to 15 psia and 80 degrees F. Furthermore, the analyses also 

considers 200 additional transients in which the pressure cycles from 400 psia and 

160 degrees F to 2250 psia and 400 degrees F and back to 400 psia and 160 degrees F. The 

staff noted that for the ASME Code fatigue analyses, the fatigue effects for these two transients 

were determined as separate events and is additive in the analyses. 

In actual operating practice, however, the applicant stated that the ASME Code Section XI leak 

test is performed at normal operating pressure and temperature (2250 psia and 565 degrees F, 

respectively) in Mode 3 hot standby as part of the normal plant heat up. The RCS pressure and 

temperature are not typically reduced as part of or following the leak test. The staff finds it 

reasonable that the applicant determined that no actual fatigue effects occur as a result of the 

test. The fatigue effects are due only to the plant heatup because the RCS pressure and 

temperature are not reduced and cycled as a separate evolution from normal heatup during 
Time-Limited Aging Analyses 

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actual operating practice. The staff also finds it reasonable that the applicant’s fatigue 

monitoring program records the plant evolution only as a plant heatup. 

The applicant stated that even if the RCS pressure and temperature were reduced due to the 

need for repairs, the evolution would be recorded as a heatup and cooldown cycle since the 

transient profile would be better represented by the heatup and cooldown profile. The staff finds 

this acceptable because the applicant has accounted for the plant heatup and cooldown 

evolutions and ASME Code Section XI leak tests and the associated fatigue effects. The staff 

noted that the Transient 79 events counted to date are RCS leak tests where the units were 

cycled from cold conditions to normal operating pressure and temperature (2250 psia and 

565 degrees F) and back to cold conditions, as part of pre-operational tests. 

Based on its review, the staff finds the applicant’s response to RAI 4.3-10 acceptable because 

the applicant clarified that its operating practice is to perform the ASME Code Section XI leak 

test concurrently with a plant heatup without a separate thermal transient and, therefore, the 

fatigue effects are appropriately accounted for as a plant heatup transient and not as a separate 

leak test transient. Further, the applicant clarified that the ASME Code fatigue analyses account 

for the fatigue effects of plant heatup, cooldown, and ASME Code Section XI leak test as 

separate transients. The staff’s concern described in RAI 4.3-10 is resolved and this part of 

Open Item 4.3-1 is closed. 

Based on its review, the staff finds the applicant has demonstrated it will monitor transients with 

its enhanced Metal Fatigue Program and take corrective actions prior to the design limit 

exceeding 1.0 because the applicant has accounted for all actual transient occurrences or 

provided conservative assumptions, as described above, such that there is a baseline that can 

be monitored by the enhanced Metal Fatigue of Reactor Coolant Pressure Boundary Program to 

ensure design limits and design calculations remain valid. The staff also finds the applicant has 

demonstrated that existing CUF or implicit fatigue calculations remain valid during the period of 

extended operation acceptable because the applicant has shown that the number of assumed 

design transients will not be exceeded during the period of extended operation. 

4.3.1.4.3 Conclusion 

On the basis of its review, the staff concludes that the applicant has an appropriate baseline for 

all transients and that these transients will be monitored by the enhanced Metal Fatigue 

Program such that the effects of aging due to fatigue on the intended functions will be 

adequately managed for the period of extended operation. 

4.3.1.5 Enhanced Metal Fatigue Reactor Coolant Pressure Boundary Program Scope, 

Action Limits, and Corrective Actions 

4.3.1.5.1 Summary of Technical Information in the License Renewal Application 

In LRA Amendments 14 (dated April 28, 2010) and 16 (dated May 27, 2010), the applicant 

revised the bases and discussion provided in LRA Section 4.3.1.5. This section provides the 

scope and basis for defining the action limits for the applicant’s enhanced metal fatigue AMP 

and the corrective action options the applicant will carry out if it reaches an action limit on CC or 

CUF monitoring. 

4.3.1.5.2 Staff Evaluation 

Scope and Method. The staff noted that in the update of LRA Section 4.3.1.5, “Scope” and 

“Method” subsections, the applicant stated that the scope of the enhanced metal fatigue AMP 

will include all ASME Code Section III Class 1 components and components with a Class 1 

fatigue analysis. The staff confirmed that the applicant is applying the enhanced metal fatigue 

AMP as the basis for dispositioning CUF-based TLAAs, as noted in applicable subsections in 

LRA Section 4.3.2, 4.3.3, and 4.3.4. 
Time-Limited Aging Analyses 

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The applicant noted that the enhanced metal fatigue AMP uses five monitoring methods, 

consistent with the updated information in LRA Table 4.3-4: (1) CC monitoring, (2) CBF-C 

monitoring, (3) CBF-PC monitoring, (4) CBF-EP monitoring, or (5) SBF monitoring. The staff 

evaluated the appropriateness of these methods in SER Section 4.3.1.2 and found them 

acceptable. 

The applicant stated that transient event cycles required to be monitored by TS 5.5.5 will 

continue to be tracked to ensure that the numbers of transient events assumed by the design 

basis calculations will not be exceeded. The staff noted that, in the update of LRA Table 4.3-3, 

the applicant said it would need to track many of the design basis transients. The staff has 

evaluated these transients in SER Section 4.3.1.4.2 and found them acceptable. 

Action Limits. The staff noted that, in the update of LRA Section 4.3.1.5, the applicant stated 

that the current metal fatigue AMP is based on CC monitoring with the exception of the 

pressurizer spray nozzle. This is the limiting Class 1 component for CUF, which is currently 

monitored using the applicant’s CBF-PC method of CUF monitoring. The staff noted that the 

applicant clarified that the current program sets action limits on CC monitoring at 90 percent of 

the design basis limit values for the transients and action limits on CUF monitoring of the 

pressurizer spray nozzle at 0.65. 

The staff noted that in the enhanced metal fatigue AMP (amended), corrective action limits will 

ensure that corrective actions are taken before the design limits are exceeded. These limits 

ensure that the applicant initiates re-evaluation or other appropriate corrective actions while 

sufficient margin remains to allow at least one occurrence of the worst case (highest fatigue 

usage per cycle), low probability transient that is included in the design specifications. 

The staff noted that the applicant clarified for NUREG/CR-6260 locations, that the CUF 

calculations would include application of the appropriate Fen environmental factor. This is 

consistent with the GALL Report Metal Fatigue AMP, which recommends the “acceptance 

criteria” program element “... involves maintaining the fatigue usage below the design code limit 

considering environmental fatigue effects as described under the program description.” 

The staff noted that the applicant’s action limit basis in the Action Limit Margins Section is 

consistent with the staff’s recommendation in the GALL Report. Based on this review, the staff 

finds the basis for the program’s action limits to be acceptable because the applicant reflected 

this basis in the update of LRA enhanced metal fatigue AMP, and it is consistent with the 

recommendation in the “acceptance criteria” program element in the GALL Report Metal Fatigue 

AMP. 

The applicant stated that, for action limits on CC, it will establish the limits based on the design 

limit on a specified number of accumulated cycles. The staff noted that an applicant’s decision 

on the degree of conservatism that should be applied to action limits on CC is not mandated by 

any NRC requirements. As a minimum, the applicant would be required to take appropriate 

corrective action if the design limit for a design basis transient was reached. Based on 

Commitment No. 39, the applicant will establish the action limits on CC for the enhanced metal 

fatigue AMP that will be implemented during the period of extended operation, and this action 

limit will include an appropriate margin on the design limit. The staff finds this acceptable. 

Corrective Actions. The staff noted that the update to LRA Section 4.3.1.5, “Cycle Count Action 

Limits and Corrective Actions” states: 

Since sufficient margin must be maintained to accommodate any design transient 

regardless of probability, the enhanced Metal Fatigue of Reactor Coolant 

Pressure Boundary program (B3.1) corrective actions will be taken before the 

remaining number of allowable occurrences for any specified transient becomes 

less than one. Corrective actions will be required when the cycle count for any of 
Time-Limited Aging Analyses 

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the significant contributors to usage factor is projected to reach the action limit 

defined the enhanced Metal Fatigue of Reactor Coolant Pressure Boundary 

program (B3.1) before the end of the next fuel cycle. 

The staff noted that the applicant will require CC corrective actions only for those design basis 

transients that the applicant considers significant contributors to fatigue usage. By letter dated 

July 21, 2010, the staff issued RAI 4.3-11, asking the applicant to clarify the definition of the 

term “significant contributors to usage factor” and explain how this is associated with the 

corrective action limits in the enhanced Metal Fatigue Program. This was previously identified 

as part of Open Item 4.3-1. 

In its response dated August 12, 2010, the applicant stated that all of the transients listed in 

UFSAR Tables 3.9.1-1 and 3.9-1, as shown in LRA Table 4.3-2 are significant contributors to 

fatigue usage factor. The applicant also stated that each transient in LRA Table 4.3-2 will have 

appropriate corrective action limits associated with it and these limits will reflect the UFSAR 

transient limits and assumptions made in the analyses of record. 

Based on its review, the staff finds the applicant’s response to RAI 4.3-11 acceptable because 

the applicant clarified that the “significant contributors” to fatigue include all transients listed in 

the UFSAR tables, and because the CC corrective action limits associated with all transients 

listed in LRA Table 4.3-2 will be tracked by the enhanced Metal Fatigue Program. This will 

ensure that the assumptions made in the analyses of record and design limits are not exceeded. 

The staff’s concern described in RAI 4.3-11 is resolved and this part of Open Item 4.3-1 is 

closed. 

The applicant stated that the enhanced metal fatigue AMP will use an automated 

three-dimensional, six-element stress tensor SBF monitoring management software module for 

the monitored locations and that “cycle-based CUFs will be calculated periodically.” In the 

update of LRA Section 4.3.1, the applicant said that, of the four monitoring methods that involve 

cycle counting (CC monitoring, CBF-C monitoring, CBF-PC monitoring, or CBF-EP monitoring), 

only the three CBF methods would involve both CC and periodic updates of the CUF 

calculations. The staff noted that in the update of LRA Section 4.3.1.2, the applicant said that 

the CC monitoring method would not perform periodic updates of a component’s CUF values, 

but if the action limit is reached, then corrective actions are necessary. 

The staff noted that the applicant stated that CUF corrective actions will be required when the 

calculated CUF (from cycle-based or SBF monitoring) is projected to reach a value of 1.0 within 

the next two or three fuel cycles. The staff also noted that the applicant’s basis also factored Fen

environmental adjustments into the selection of its CUF based action limits. The staff finds this 

to be a reasonable basis for applying CUF based corrective actions when compared to the 

“acceptance criteria” program element in the GALL Report Metal Fatigue AMP, which 

recommends that action limits on CUFs be taken before the design limit is reached and that the 

acceptance criteria should account for environmental effects. 

However, the staff also noted that the applicant said that corrective actions must also be taken 

while there is still sufficient margin to accommodate at least one occurrence of the worst case 

(highest fatigue usage per cycle) design transient event, in order to accommodate occurrence of 

a low probability transient. The staff noted that this basis statement appeared to be more 

relevant to CC activities and not to CUF monitoring activities. The staff has evaluated the action 

limits for CC monitoring earlier in this evaluation. 

The applicant’s updated basis included the following seven possible corrective actions: 

(1) Determine whether the scope of the enhance fatigue management program must be 

enlarged to include additional affected reactor coolant pressure boundary locations 
Time-Limited Aging Analyses 

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(2) Adjust fatigue monitoring methods to confirm continued conformance to the Code design 

limit 

(3) Repair or modify the component 

(4) Replace the component 

(5) Perform a more rigorous analysis of the component to demonstrate that the design code 

limit will not be exceeded 

(6) Modify plant operating practices to reduce the fatigue usage accumulation rate 

(7) Perform a flaw tolerance evaluation, impose component-specific inspections under 

ASME Code Section XI Appendices A or C (or their successors), and obtain required 

approval of the NRC 

The staff noted that all of these corrective actions on CUF monitoring are acceptable for 

addressing a component whose CUF value is approaching a value of 1.0. Specifically, the staff 

noted that corrective actions 1, 2, 5, and 6 would all ensure that the CUF value for a component 

would remain within the ASME Code allowable limit of 1.0. The staff also noted that corrective 

action options 3, 4, and 7 would address those components for which the applicant could not 

ensure that the CUF value would remain below a value of 1.0. 

With regard to corrective action 1, the applicant says it is only applicable to RCP boundary 

components. However, in its review of LRA Section 4.3.2, the staff confirmed that the TLAA 

includes the CUF results for some ASME Code Class 2 components that were analyzed to 

ASME Code Section III CUF requirements for Code Class 1 components. As a result, the staff 

noted that the action in corrective action 1 might also be applicable to those ASME Code 

Class 2 components that were analyzed to ASME Code Section III CUF requirements for Code 

Class 1 components. 

By letter dated July 21, 2010, the staff issued RAI 4.3-12 requesting the applicant clarify if the 

scope of corrective action 1 on CUF monitoring includes all components with ASME Code 

Section III CUF calculations for Code Class 1 components and ASME Code Class 2 

components that were analyzed to ASME Code Section III CUF requirements for Code Class 1 

components. If the scope of correction action 1 does not include both sets of components, the 

staff asked that the applicant justify why they are not within scope. This was previously 

identified as part of Open Item 4.3-1. 

In its response dated August 12, 2010, the applicant stated that the scope of the enhanced 

Metal Fatigue Program includes the ASME Code Section III Class 1 components and 

components with Class 1 fatigue analysis, which includes Class 2 components that were 

analyzed to ASME Code Section III CUF requirements for Class 1 components. 

Based on its review, the staff finds the applicant’s response to RAI 4.3-12 acceptable because 

the applicant clarified that the scope of the enhanced Metal Fatigue Program includes all 

components, including Class 2 and 3 components, with a CUF analysis. Further, the response 

is acceptable because the applicant’s program will ensure that the design limit of 1.0 is not 

exceeded or corrective actions will be taken to reanalyze, repair, or replace the component 

before the design limit is exceeded. The staff finds that this approach provides effective 

corrective actions for these components. The staff’s concern described in RAI 4.3-12 is 

resolved. This part of Open Item 4.3-1 is closed. 

The staff noted that the GALL Report states that a program consistent with GALL AMP X.M1 is 

an acceptable option for managing metal fatigue for the reactor coolant pressure boundary, 

considering environmental effects and no further evaluation is recommended for license renewal 

if the applicant selects this option pursuant to 10 CFR 54.21(c)(1)(iii) to evaluate metal fatigue 

for the reactor coolant pressure boundary. 
Time-Limited Aging Analyses 

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Based on its review, the staff finds the applicant has demonstrated it will monitor transients with 

its enhanced Metal Fatigue Program and take corrective actions prior to the design limit 

exceeding 1.0 because the applicant provided the details of the scope, action limits and 

corrective actions associated with its enhanced Metal Fatigue Program and the staff has found 

these consistent with the recommendations in the GALL Report Metal Fatigue AMP. 

4.3.1.5.3 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated that the 

effects of aging on the intended functions will be adequately managed for the period of 

extended operation. 

4.3.2 American Society of Mechanical Engineers III Fatigue Analysis of Class 1 Vessels, 

Piping, and Components 

LRA Section 4.3.2 summarizes the evaluation of the CUF analyses that comprise the “ASME III 

Fatigue Analysis of Class 1 Vessels, Piping and Components,” for the period of extended 

operation. These TLAAs are based on the analyses in the applicant’s current design basis CUF 

calculations for these components. In these TLAAs, the applicant provides its bases for 

dispositioning the CUF analyses for its ASME Code Class 1 reactor vessel, pressurizer, piping, 

and SG components and for the Class 2 SG components that were analyzed to ASME Code 

Section III CUF criteria, in accordance with the TLAA acceptance criteria in 

10 CFR 54.21(c)(1)(i), (ii), or (iii). 

4.3.2.1 Reactor Pressure Vessel, Nozzles, Head, and Studs 

4.3.2.1.1 Summary of Technical Information in the Application 

LRA Section 4.3.2.1 and Amendment 16 dated May 27, 2010, summarize the evaluation of the 

fatigue analyses for the reactor pressure vessels which were designed, built, and analyzed by 

Combustion Engineering to the standards of ASME Code Section III, Subsection NB (Class 1), 

1971 Edition with addenda through winter 1973. The applicant stated that pressure-retaining 

and support components of the reactor pressure vessels are subject to an ASME Boiler and 

Pressure Vessel Code, Division 1, Section III, fatigue analysis. Furthermore, these analyses 

have been updated to incorporate redefinitions of loads and design basis events, operating 

changes, and a power uprate with SG replacement. The applicant further stated that the 

currently applicable fatigue analyses of these components are TLAAs. 

The amended LRA Section 4.3.2.1 dispositions all of the analyses in this section consistent with 

10 CFR 54.21(c)(1)(ii), that the analyses have been projected to the end of the period of 

extended operation, or 10 CFR 54.21(c)(1)(iii), that the enhanced Metal Fatigue Program will 

track the transients identified in these analyses to ensure that appropriate reevaluation or other 

corrective action will be initiated if an action limit is reached. 

4.3.2.1.2 Staff Evaluation 

The staff reviewed this section using the guidance of SRP-LR Sections 4.3.2.1.1.2 and 

4.3.2.1.1.3 to verify that the analyses in this section demonstrate, consistent with 

10 CFR 54.21(c)(1)(ii), that the analyses have been projected to the end of the period of 

extended operation, or consistent with 10 CFR 54.21(c)(1)(iii), that the effects of aging on the 

intended functions of these components will be adequately managed during the period of 

extended operation. 

LRA Section 4.3.2.1 provides a CUF value of 0.823 for the RPV studs and a CUF value of 

0.954 for the RPV bottom head support or shear lugs. LRA Section 4.3.2.1 also states that the 

RPV studs are the more limiting component because they will experience more severe stresses 

during each transient event, even though they are limited to a lower design limit on the number 
Time-Limited Aging Analyses 

 4-43 

of allowable heatup and cooldown events. The staff noted that in the updated LRA Table 4.3-4, 

the applicant stated that both of these component locations will be monitored using CC 

monitoring methods. The applicant’s CC monitoring methods do not include automatic periodic 

updates of CUF calculations. Therefore, it is not clear to the staff if CC will be applied only to 

the RPV studs, even though the RPV lugs have an existing CUF of 0.954. 

By letter dated July 21, 2010, the staff issued RAI 4.3-14 requesting the applicant clarify 

whether it is using CC monitoring methods on the RPV studs. The staff requested the following 

additional actions if the cycle-based monitoring will be performed only on the RPV studs: 

(1) summarize transients that were used for the CUF calculations for the RPV studs and RPV 

bottom head lugs, and (2) clarify the quantitative contribution to fatigue usage for each transient 

analyzed. This was previously identified as part of Open Item 4.3-1. 

In its response dated August 12, 2010, the applicant stated that both the RPV studs and RPV 

external bottom head shear lugs will be monitored by CC and appropriate corrective action limits 

will be applied to both. 

Based on its review, the staff finds the applicant’s response to RAI 4.3-14 acceptable because 

the applicant clarified that each component, studs and RPV external bottom head shear lugs, 

will be monitored individually by CC, and action limits for the enhanced Metal Fatigue Program 

will be established to allow for corrective actions before the design basis number of events is 

exceeded. The staff’s concern described in RAI 4.3-14 is resolved and this part of Open 

Item 4.3-1 is closed. 

Based on its review, the staff finds the applicant has demonstrated pursuant to 

10 CFR 54.21(c)(1)(ii), that the analyses for the reactor pressure vessel, nozzles, and head 

components are acceptable because the applicant’s revised fatigue analyses for the reactor 

pressure vessel, nozzles, and head components demonstrate that the design limit of 1.0 is met 

for the period of extended operation. The staff also finds that the applicant has demonstrated 

pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended functions for the 

reactor vessel studs will be managed during the period of extended operation because the 

reactor vessel studs will be managed by the applicant’s enhanced Metal Fatigue Program which 

ensures that the number of cycles assumed in the design calculation are not exceeded and the 

CUF will not exceed the code limit of 1.0. 

4.3.2.1.3 Updated Final Safety Analysis Report Supplement 

LRA Section A3.2.1.1 provides the UFSAR supplement summarizing the evaluation of the 

fatigue analyses for the reactor pressure vessel, nozzles, head, and studs. Based on its review 

of the UFSAR supplement, the staff concludes that the applicant provided an adequate 

summary description of its actions to address the TLAA for the reactor pressure vessel, nozzles, 

head, and studs is adequate, as required by 10 CFR 54.21(d). 

4.3.2.1.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(ii), that the fatigue analyses for the reactor pressure vessel, nozzle and 

head components have been projected to the end of the period of extended operation. The staff 

also concludes that the applicant has demonstrated, pursuant to10 CFR 54.21(c)(1)(iii) that the 

effects of aging on the intended functions of the reactor vessel studs will be adequately 

managed for the period of extended operation. The staff also concludes that the UFSAR 

supplement contains an appropriate summary description of the TLAA evaluation, as required 

by 10 CFR 54.21(d). 
Time-Limited Aging Analyses 

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4.3.2.2 Control Element Drive Mechanism Nozzle Pressure Housings 

4.3.2.2.1 Summary of Technical Information in the Application 

LRA Section 4.3.2.2 and Amendment 16 dated May 27, 2010, summarize the evaluation of the 

fatigue analyses of the CEDM and reactor vessel level monitoring system pressure housings. 

The applicant stated that the CEDM and reactor vessel level monitoring system pressure 

housings will be replaced and the replacements are designed to ASME Code Section III 

Subsection NB. The applicant also stated that the fatigue analyses of the replacement 

components are sufficient for a 40-year design life, based on the design basis transient events 

specified for the original reactor vessel heads. The design life of these replacement heads, 

nozzles, and CEDM and reactor vessel level monitoring system pressure housings therefore 

extends beyond the end of the period of extended operation. The applicant provided a 

disposition of this TLAA in accordance with 10 CFR 54.21(c)(1)(ii), that the analyses have been 

projected to the end of the period of extended operation. 

4.3.2.2.2 Staff Evaluation 

The staff reviewed LRA Section 4.3.2.2 and Amendment 16 to verify pursuant to 

10 CFR 54.21(c)(1)(ii), that the analyses have been projected to the end of the period of 

extended operation. 

The applicant stated that it is replacing reactor vessel heads for all three units, including their 

nozzles, CEDM pressure housings, RVLMS pressure housing, and caps for the spare nozzles. 

As of December 1, 2010, the applicant stated that Units 1, 2, and 3 reactor vessel heads have 

been replaced. 

The applicant stated that the CEDM pressure housings replacements are designed to ASME 

Code Section III Subsection NB, 1998 Edition with addenda up to and including the 2000 

Addenda, for a 40-year operating period. The applicant also stated that the design report for the 

replacements calculated fatigue usage factors at the two limiting locations: 0.4210 in the motor 

housing and 0.2240 in the lower end of the upper pressure housing. 

The applicant stated that the reactor vessel level monitoring system pressure housings 

replacements are designed to ASME Code Section III Subsection NB, 1998 Edition with 

addenda up to and including the 2000 Addenda, as ASME III NCA-1260 Code Class 1 

appurtenances; for a 40-year operating period. The applicant also reported a usage factor of 

0.654 in the upper flange. 

Effects of Power Uprate and SG Replacement on the CEDM and Reactor Vessel Level 

Monitoring System Pressure Housing Analyses. LRA Section 4.3.2.2 and Amendment 16 state 

that the revised OBE and faulted loads on the original CEDM nozzle are less than the maximum 

allowed in the analyses of record. Thus, there is no change to the original design report fatigue 

usage. Furthermore, the applicant explained that the analyses of the replacement CEDM and 

reactor vessel level monitoring system pressure housings were based on the original set of 

design basis transient events, and were also not affected by the power uprate and SG 

replacement modifications. 

Effects of Combustion Engineering Infobulletin 88-09. The applicant stated that the CE Owner’s 

Group review did not identify any effects on the original fatigue analysis of the CEDM. The 

applicant further explained that the conclusions of the analysis of the replacement CEDM and 

RVLMS pressure housings, based on the original set of design basis transient events, were also 

not affected by the Infobulletin 88-09 evaluation. 

Based on its review, the staff finds the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(ii), that the analyses for the CEDM and reactor vessel level monitoring 

system pressure housings have been projected to the end of the period of extended operation 
Time-Limited Aging Analyses 

 4-45 

because the fatigue analyses of the replacement components are sufficient beyond the period 

of extended operation. Thus, fatigue usage factors in the housings are below the design limit of 

1.0 for the period of extended operation. 

4.3.2.2.3 Updated Final Safety Analysis Report Supplement 

LRA Section A3.2.1.2 provides the UFSAR supplement summarizing the evaluation of the 

fatigue analyses for the CEDM and reactor vessel level monitoring system pressure housings. 

Based on its review of the UFSAR supplement, the staff concludes that the applicant provided 

an adequate summary description of its actions to address the TLAA for the CEDM and reactor 

vessel level monitoring system pressure housings as required by 10 CFR 54.21(d). 

4.3.2.2.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(ii), that the fatigue analyses for the CEDM and RVLMS pressure housings 

have been projected to the end of the period of extended operation. The staff also concludes 

that the UFSAR supplement contains an appropriate summary description of the TLAA 

evaluation, as required by 10 CFR 54.21(d). 

4.3.2.3 Reactor Coolant Pump Pressure Boundary Components 

4.3.2.3.1 Summary of Technical Information in the Application 

LRA Section 4.3.2.3 and Amendment 16 dated May 27, 2010, summarize the evaluation of the 

fatigue analyses of the reactor coolant pump pressure boundary components. The applicant 

stated that these components are designed to ASME Code Section III, Subsection NB. The 

applicant also stated that the analysis was reexamined for the power uprate and steam 

generator replacement modifications. The applicant provided a disposition of this TLAA in 

accordance with 10 CFR 54.21(c)(1)(iii), that the effects of aging will be adequately managed for 

the period of extended operation. 

4.3.2.3.2 Staff Evaluation 

The staff reviewed LRA Section 4.3.2.3 and Amendment 16 to verify pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended functions will be adequately 

managed for the period of extended operation. 

The applicant stated that the reactor coolant pump pressure boundary components are 

designed to ASME Code Section III, Subsection NB, 1974 Edition (no addenda). The applicant 

also stated that a fatigue analysis, in accordance with Subparagraph NB-3222.4(e), was 

performed only for pump casing components. The high pressure cooling system and seal 

housing adapters invoked the fatigue analysis waiver of NB-3222.4(d), or were designed to 

requirements other than those of Section III Class 1. 

The applicant stated that the maximum total CUF for all components is 0.988 for the pump 

casing closure studs. The analysis of the pump casing closure studs initially resulted in usage 

factors greater than 1.0. To reduce the usage factor below 1.0, the applicant explained that the 

number of heatup and cooldown cycles, which are the most significant contributors to usage 

factor in all pump components, was reduced to 475 events. The applicant stated that the 

reduced number of heatup and cooldown cycles is incorporated into the fatigue-monitoring 

program and is under review for addition to UFSAR Section 3.9.1.1. 

Effects of Power Uprate and Steam Generator Replacement on the CEDM and RVLMS 

Pressure Housing Analyses. LRA Section 4.3.2.3 and Amendment 16 state that the original 

fatigue analyses of record are still valid and the effects of the steam generator replacements 

and power uprate loads on the analysis of record have been reconciled. 
Time-Limited Aging Analyses 

 4-46 

Effects of Combustion Engineering Infobulletin 88-09. The applicant stated that the CE Owner’s 

Group review did not identify any effects on the fatigue analysis of the reactor coolant pumps. 

Based on its review, the staff finds the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended functions of the reactor coolant 

pump pressure boundary components will be adequately managed for the period of extended 

operation because action limits of the enhanced Metal Fatigue Program will be established to 

permit completion of corrective actions before the design basis number of events specified in 

the Design Specification, UFSAR Table 3.9-1, and the RCP closure studs’ more restrictive 

number of heatup and cooldown events are exceeded. Thus, the fatigue usage factor will not 

exceed the design limit of 1.0 during the period of extended operation. 

4.3.2.3.3 Updated Final Safety Analysis Report Supplement 

LRA Section A3.2.1.3 provides the UFSAR supplement summarizing the evaluation of the 

fatigue analyses for the reactor coolant pump pressure boundary components. Based on its 

review of the UFSAR supplement, the staff concludes that the applicant provided an adequate 

summary description of its actions to address the TLAA for the reactor coolant pump pressure 

boundary components as required by 10 CFR 54.21(d). 

4.3.2.3.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended functions of the reactor coolant 

pump pressure boundary components will be adequately managed for the period of extended 

operation. The staff also concludes that the UFSAR supplement contains an appropriate 

summary description of the TLAA evaluation, as required by 10 CFR 54.21(d). 

4.3.2.4 Pressurizer and Pressurizer Nozzles 

4.3.2.4.1 Summary of Technical Information in the Application 

The pressurizers are designed to the ASME Code Section III, Subsection NB (Class 1), 

1971 Edition with addenda through winter 1973. The pressurizers are welded, vertical 

cylindrical pressure vessels with hemispherical heads, fabricated of carbon steel with the interior 

surface clad with stainless steel. A cylindrical support skirt and flange is attached to the lower 

head shell with a forged knuckle support ring. 

The central vertical surge nozzle, two vertical lower level instrument nozzles, and 36 heater 

sleeves penetrate the lower head. Four shear lugs, welded to the upper shell, stabilize the 

vessel against seismic and other overturning loads. The central vertical spray nozzle, manway, 

four horizontal upper instrument nozzles, and four horizontal safety valve nozzles penetrate the 

upper head. 

The surge, spray, and safety valve nozzles attached to the pressurizer contain safe ends for 

welding to the attached stainless steel piping. Recently, the applicant installed weld overlays on 

these nozzles, safe ends, and safe end welds to mitigate potential PWSCC. All of the Alloy 600 

instrument nozzles have been replaced with Alloy 690 materials, which are less susceptible to 

PWSCC. 

The heater sleeves and heaters have all been replaced with Alloy 690 heater sleeves, which are 

attached to the lower vessel head by half-nozzle repairs and welded to external reinforcing 

pads. The heater sheaths are attached to the outer ends of the Alloy 690 heater sleeves by 

fillet seal welds. The sheaths of the electric heater, the welds between the end plug and sheath, 

and the fillet seal welds to the heater sleeves, are Class 1 pressure boundary welds. The Unit 1 

heater sleeve (B18) and Unit 2 heater sleeves (A06 and B18) have been closed with welded 

Type 316 stainless steel plugs. 
Time-Limited Aging Analyses 

 4-47 

The pressurizers have operated since startup with a continuous spray flow to prevent boron 

concentration stratification and to mitigate spray line and nozzle fatigue. This continuous flow is 

achieved via regulating bypass valves around each of the two main spray valves. 

Table 4.3-7 from LRA Amendment 16 (May 27, 2010) provides a disposition for each 

pressurizer component analysis. With the design basis set of transients, including power 

uprate, SG replacement, and other effects described above, the worst-case calculated 40-year 

fatigue usage factors exceed 0.9 in a few pressurizer components. Other fracture mechanics or 

fatigue analyses depend on the limiting number of occurrences assumed for a 40-year design 

life. 

Some of the revised time-dependent component evaluations were based on a 60-year extended 

licensed operating period and, if valid for the period of extended operation, are not TLAAs. 

Others evaluations were for shorter than 40 years and did not extend to the end of the current 

licensed operating period, and therefore were not TLAAs. The fatigue analyses for materials 

adjacent to the surge and spray nozzle overlay repairs extend to the period of extended 

operation, but were able to meet the 1.0 usage factor acceptance criterion only for a 40-year life 

and are therefore TLAAs. 

For those analyses that are TLAAs, the applicant dispositioned them in accordance with 

10 CFR 54.21(c)(1)(iii), that the effects of aging will be adequately managed for the period of 

extended operation using the enhanced metal fatigue AMP. 

4.3.2.4.2 Staff Evaluation 

The staff reviewed LRA Section 4.3.2.4 to verify, pursuant to 10 CFR 54.21(c)(1)(iii), that the 

effects of aging on the intended function(s) of the pressurizer and pressurizer nozzles will be 

adequately managed for the period of extended operation. 

TLAAs of the pressurizer and pressurizer nozzle are focused on the crack growth calculations 

and CUF calculations that were done as part of the CLB in light of additional 20 years of service 

beyond the current operating license. The affect of the period of the extended operation on the 

crack growth calculations and CUF calculations is related to the transient cycles used. 

The applicant stated that pressure retaining and support components of the pressurizer are 

subject to an ASME, Section III, fatigue analysis. These analyses have been updated to 

incorporate updated definitions of loads, design basis events, operating changes, power uprate, 

and modifications to include the following: 

 Effects of indications in a Unit 2 pressurizer support skirt forging weld 

 Effects on the pressurizer of NRC Bulletin 88-11 thermal stratification in the surge line 

not included in the original analyses 

 Effects on the pressurizer of insurge-outsurge transients not included in the original 

analyses 

 Effects on the pressurizer of CE Infobulletin 88-09 “Nonconservative Calculation of 

Cumulative Fatigue Usage” 

 Replacement instrument nozzles 

 Crack growth and fracture mechanics stability analyses of postulated defects in original 

heater sleeve attachment welds remaining in the pressurizer lower heads 

 Replacement heaters 

 Replacement heater sleeves and their welds to the heaters 

 Thermal effects on the Unit 3 pressurizer of incorrectly installed replacement heaters 
Time-Limited Aging Analyses 

 4-48 

 Compressive weld overlays of the surge, spray, and safety valve nozzles and safe ends 

and welds 

The staff grouped the above items into the following components and events in this evaluation: 

 Pressurizer support skirt forging weld 

 Impact of power uprate and SG replacement 

 Pressurizer surge line nozzle 

 Pressurizer heater sleeves 

 Pressurizer overheating event 

 Weld overlay of the surge line, spray, and safety valve nozzles 

Pressurizer Support Skirt Forging Weld. Section 4.3.2.4 of the LRA (page 4.3–39) states that 

the 1991 CE Owners Group (CEOG) review of CE Infobulletin 88-09, “Nonconservative 

Calculation of Cumulative Fatigue Usage,” found that the fatigue usage factor in the 

worst-affected location (bottom head-support skirt) of the PVNGS Unit 1, 2, and 3 pressurizers 

might increase 32 percent above the design basis calculated value of 0.8895. Therefore, the 

applicant evaluated these effects further and amended the design reports. The revised 

worst-location 40-year design basis CUF, including these effects, is 0.7223. 

In RAI 4.3.2.4-1, the staff asked the applicant to supply the CUF for the worst location at the 

pressurizer for the period of extended operation because the above information supplies the 

CUF for the worst location for the 40-year design life. The staff also asked the applicant to 

discuss whether the fatigue analysis of the pressurizer bottom head support skirt is a TLAA. 

The applicant's March 1, 2010, response to RAI 4.3.2.4-1 stated that the pressurizer bottom 

head support skirt is the most affected location of the Infobulletin 88-09 reanalysis, not that it is 

the highest (i.e., the worst) CUF location as determined by the ASME Code analysis of the 

pressurizer. 

The applicant explained that in Units 1 and 2, the highest CUF locations for a fatigue TLAA are 

the short heater sleeve plugs (LRA Table 4.3-7, line 15), with a CUF of 1.0. In Unit 3, the 

highest CUF location for a fatigue TLAA is the spray nozzle and safe end with overlay repair 

(LRA Table 4.3-7, line 20), with a 40-year calculated CUF of 0.9923. These values show that 

60-year usage factors, calculated on the same bases, would exceed the ASME Code allowable 

of 1.0. Disposition of these TLAAs for the period of extended operation depends on 

10 CFR 54.21(c)(1)(iii) aging management using the enhanced metal fatigue AMP which the 

applicant identified in the amended LRA. 

The applicant stated that all fatigue analyses of the pressurizer and its subcomponents are 

TLAAs, except those already extended to a 60-year design life under analyses for the CLB per 

10 CFR 54.3(a)(3), and those are not the basis for a safety determination per 

10 CFR 54.3(a)(4). 

The staff finds that the applicant has clarified that the CUF of 0.7233 from the support skirt is not 

the worst CUF for the pressurizer. The worst case CUF for Units 1 and 2 is in the short heater 

sleeve plugs and for Unit 3 is the overlaid spray nozzle. The applicant also noted that the 

enhanced metal fatigue AMP will be used to monitor the worst case CUFs to ensure that they 

will not exceed the ASME Code allowable of 1.0. Therefore, the staff’s concern in RAI 4.3.2.4-1 

is resolved. 

In Section 4.3.2.4 of the LRA, the applicant reported that two flaws were detected in the Unit 2 

pressurizer support skirt-forging weld and that the fatigue crack growth analysis predicted 

growth from the as-found size of 0.59 inch to a size of 0.6921 inch over the design life. In 

RAI 4.3.2.4-2, the staff asked the applicant to discuss how many years were assumed for the 

design life and were assumed in the fatigue crack growth calculation of the detected flaws. The 
Time-Limited Aging Analyses 

 4-49 

applicant's March 1, 2010, response stated that the fatigue crack growth analysis has shown 

that no repair is required for continued operation over the service life of the vessel, which, at the 

time of the analysis (1993), was understood to be 40 years. The applicant stated that a 60-year 

analysis is not required under the license renewal rule if it manages the aging effect. 

As stated in LRA Section 4.3.2.4, the linear elastic fracture mechanics fatigue crack growth 

analysis of indications in the Unit 2 pressurizer support skirt-forging weld is valid for up to 

500 plant startup and shutdown cycles, 480 plant trips, and 2 million normal and upset cycles. 

The Metal Fatigue of Reactor Coolant Pressure Boundary Program (enhanced metal fatigue 

AMP) will track these events, and action limits will ensure that appropriate corrective actions are 

completed before the design basis number of these events is exceeded. Appropriate corrective 

actions may include repair, replacement, or reanalysis. Growth of the Unit 2 pressurizer skirt 

indications will be managed for the period of extended operation in accordance with 

10 CFR 54.21(c)(1)(iii). The parameter in the fatigue crack growth calculation that is affected by 

the time is the transient cycles used. The transient cycles will be different between 40 years 

and 60 years. The applicant will use the enhanced metal fatigue AMP to monitor the transient 

cycles to ensure that the transient cycles assumed in the fatigue crack growth calculation for the 

cracks found in the pressurizer support skirt-forging weld bound the actual transient cycles at 

the end of 60 years. 

The staff held a teleconference with the applicant on September 22, 2010, to clarify how design 

basis transient cycle tracking and counting activities are accounted for in the CLB for ASME 

Code Section XI supplemental fatigue flaw growth or cycle dependent fracture mechanics 

evaluations. The staff also requested the applicant to justify the use of design basis transient 

cycle tracking and counting activities as the basis to disposition the ASME Code Section XI 

analyses in LRA Section 4.7.4 in accordance with 10 CFR 54.21(c)(1)(iii), if the scope of the 

applicant’s CLB does not include this activity. 

By letter dated October 13, 2010, the applicant described how it will use CC methods to track 

these supplemental evaluations. The staff reviewed the response and finds it acceptable that 

the applicant will use its enhanced Metal Fatigue Program to monitor the transient cycles used 

in the fatigue crack growth calculations. The staff’s evaluation of the applicant’s clarification is 

documented in SER Section 4.7.4.2. 

The staff finds it acceptable that the applicant will use the enhanced metal fatigue AMP to 

monitor the transient cycles used in the fatigue crack growth calculation for the detected flaws in 

the Unit 2 pressurizer support skirt to ensure that the crack growth calculation is valid during the 

period of extended operation. Therefore, the staff’s concern in RAI 4.3.2.4-2 is resolved. 

Impact of Power Uprate and Steam Generator Replacement. In LRA, Section 4.3.2.4, the 

applicant states that power uprate and SG replacement have no effect on the design reports for 

any of the pressurizers in the three units. In RAI 4.3.2.4-3, the staff asked the applicant to 

reference the design reports associated with pressurizer and pressurizer nozzles that have 

been reviewed to determine the affect of power uprate and SG replacement. The staff asked 

that the applicant describe these reports briefly in the context of Section 4.3.2.4 and clarify 

whether the loadings on the pressurizer and pressurizer nozzles are affected by the power 

uprate and SG replacement. 

The applicant's March 1, 2010, response to RAI 4.3.2.4-3 provided a list of the power uprate 

and replacement SG evaluation reports. 

The power uprate licensing reports are included in letters from the applicant, dated 

December 21, 2001, and July 9, 2004. The reports did not explicitly cite or revise the analyses 

of record. Instead, these reports reviewed the supporting design transients as documented in 

the code design specifications for nuclear steam supply system SCs. 
Time-Limited Aging Analyses 

 4-50 

In the reports, the applicant concluded that the original design transients are more limiting than 

the corresponding limiting calculated transients associated with the power uprate. Hence, the 

original SC design specifications remain bounding to the new operating conditions associated 

with the power uprate. 

The applicant stated further that the power uprate and replacement SG evaluations 

demonstrated that the loadings on the pressurizer remain within the conditions assumed for the 

analysis of record. Loads on the pressurizer and its nozzles remained less than or equal to 

those used for the analyses of record, and, therefore, no changes to the analyses of record 

were necessary. 

By letter dated May 21, 2010, the applicant submitted Amendment 15, which supplemented the 

response to RAI 4.3.2.4-3 and further clarified that the Westinghouse design report addendum 

for the pressurizer confirms that the power uprate and SG replacement modifications have no 

effect on the pressurizer design reports for any of the three units. This conclusion applies to the 

severity of the design basis transient events, is unaffected by the number of occurrences of 

each transient event assumed by the analyses, and is unaffected by the design life. In 

conclusion, the power uprate and SG replacement modifications have no effect on the 

pressurizer design reports through the period of extended operation. The staff’s concern in 

RAI 4.3.2.4-3 is resolved. 

The staff finds that the applicant has demonstrated that power uprate and SG replacement do 

not significantly affect the loading on the pressurizer and its nozzles. 

Pressurizer Surge Line Nozzle. LRA Section 4.3.2.4 states that the original stress and fatigue 

analysis of the pressurizer surge line nozzle have been superseded by the reanalysis for a 

compressive overlay, which included the thermal stratification and insurge-outsurge effects. In 

RAI 4.3.2.4-4, the staff asked the applicant to describe the analysis input, method, results, and 

acceptance criteria in detail, demonstrating that the structural integrity of the surge nozzle will 

be maintained to the end of 60 years. 

The applicant's March 1, 2010, response to RAI 4.3.2.4-4 stated that the reanalysis of the 

overlaid surge nozzle is a worst-case calculation of the projected usage factor for a 60-year 

lifetime. The calculation for the 60-year cycle usage factor for overlaid surge line nozzle 

multiplied the 40-year cycle usage factor of 0.960 by 1.5 to obtain a 60-year value of 1.440. 

However, the pressurizer surge line nozzle will be monitored for fatigue usage, and the fatigue 

CUF will not exceed the code limit of 1.0, so long as the number of applied load cycles does not 

exceed the number specified by the design specification for this nozzle and used in the original 

analysis. The analysis includes effects of thermal stratification and insurge-outsurge. 

The staff finds that the CUF for the surge line nozzle is predicted to exceed the allowable of 1.0 

at the end of 60 years. However, the applicant will monitor the CUF for the surge line nozzle 

based on the enhanced metal fatigue AMP to ensure that it will not exceed the CUF allowable 

of 1.0. Before the CUF exceeds the allowable code limit, the metal fatigue program requires 

corrective actions. The staff finds that the structural integrity of the pressurizer surge line will be 

maintained during the period of extended operation because the applicant is using appropriate 

monitoring methods to ensure that the pressurizer surge line nozzles will not exceed a CUF 

allowable of 1.0. Therefore, the staff’s concern in RAI 4.3.2.4-4 is resolved. 

Pressurizer Heater Sleeves. PWR operating experience has shown that Alloy 82/182 welds that 

join the pressurizer heater sleeves to the pressurizer shell are susceptible to PWSCC. LRA 

Section 4.3.2.4 discusses the fatigue crack growth analysis in the original pressurizer heater 

sleeve attachment welds. In RAI 4.3.2.4-5, the staff asked the applicant to complete the 

following tasks: 

 Discuss the postulated initial cracks in the original sleeve-to-inner-wall attachment welds 
Time-Limited Aging Analyses 

 4-51 

 Discuss the projected final flaw size for the postulated cracks at the end of 60 years 

 Discuss the allowable flaw size 

 Discuss the results 

 Describe the methods used in the “subsequent” and “code design” reports 

 Provide the references for these reports 

The applicant's March 1, 2010, response to RAI 4.3.2.4-5 stated that the postulated initial crack 

size in the crack growth analyses was a flaw size of 0.6 inches in the Alloy 82/182 weld. The 

projected final flaw size at the end of 60 years is 1.16 inches. The fracture mechanics analysis 

permits an allowable flaw size of 1.2 inch. The fatigue crack growth analysis described in the 

LRA was performed in support of the temporary mechanical nozzle seal assembly (MNSA) 

repairs to three Unit 3 pressurizer heater sleeves and was performed for a 60-year period. As a 

result of the replacement of all heater sleeves with the half-nozzle repair method, the fatigue 

crack growth analysis of the remnant nozzles, performed in support of the MNSA repairs, has 

been superseded by the analyses done to support the heater sleeve replacement modification 

and associated RR 29. This RR asked for relief from the requirements of the ASME Code 

Section XI, IWA-3300, IWA-4310, IWB-2420, IWB-3242.4, and IWB-3610 for the pressurizer 

heater sleeve and Alloy 82/182 remnant nozzles. 

The applicant performed a fatigue crack growth analysis for the pressurizer heater sleeve 

half-nozzle repair supporting RR 29. By letter dated November 5, 2004, the staff approved 

RR 29. The applicant stated that these analyses are superseding and applicable to all three 

units. A subsequent evaluation of effects of the Unit 3 lower head overheating events 

determined that the calculated increase in the growth of the postulated defect would be a 

negligible 4.44E-5 inch. This evaluation was, therefore, not included in the Unit 3 code design 

report. The applicant stated that this evaluation applied only to the brief period of time for which 

the Unit 3 pressurizer lower head was subject to overheating; therefore, it is not a TLAA, since it 

does not meet the criteria of 10 CFR 54.4(a)(4). 

The currently applicable analyses used finite-element models to calculate stress intensity 

factors for postulated flaws for various operating conditions and calculated the crack growth per 

cycle for the significant contributors to crack growth, using the methodology of the 1992 edition 

of the ASME Code Section XI for a water environment. The applicant’s analyses then 

determined the maximum permissible crack size for which the most limiting allowed stress 

intensity would not be exceeded, based on the assumption that the applied stress intensity 

factor is proportional to the square root of the crack dimension. The crack growth was 

calculated as the sum of the products of lifetime design cycles times their respective crack 

growth increments per cycle. 

The applicant stated that these analyses assume a 60-year design life, and are, therefore, not 

TLAAs, per 10 CFR 54.3(a)(3). The currently applicable analyses and supporting calculations 

were incorporated by reference, unchanged, in the three pressurizer code design reports. 

The applicant stated that LRA Amendment 10 corrected the heading for this discussion, and 

two paragraphs below it in the LRA, to recognize the RR and associated analysis. It also 

specified the analysis results discussed above. 

The staff finds that the applicant has clarified the analyses of the heater sleeve repairs. The 

analyses document the technical basis of the heater sleeve repairs, which the staff previously 

approved. The staff finds that the applicant has responded to RAI 4.3.2.4-5 satisfactorily, and 

the staff’s concern is resolved. 

LRA Section 4.3.2.4 states that for the half-nozzle repair method, the original sleeve-to-inner 

wall attachment welds (i.e., J-groove welds) are analyzed for 60 years and, therefore, the 

analysis is not a TLAA. The staff notes that other welds and components were used for the 
Time-Limited Aging Analyses 

 4-52 

half-nozzle repair (e.g., welds were used to join the half nozzle to the weld pad). In 

RAI 4.3.2.4-6, the staff asked the applicant to discuss why the fatigue analysis of the half 

nozzles, associated new attachment welds, and weld pads are not discussed as part of the 

review. 

The applicant's March 1, 2010, response to RAI 4.3.2.4-6 stated that the fatigue analyses of the 

pressurizer heater sleeve half-nozzle repairs for all three units were evaluated for a period of 

60 years. These analyses are, therefore, not TLAAs per 10 CFR 54.3(a)(3). The 60-year usage 

factors calculated by these repair analyses can be found in LRA Table 4.3-7, item 16 for Unit 2 

and item 17 for Units 1 and 3. The applicant noted that LRA Table 4.3-7, item 16, is an analysis 

intended to be applicable to all three units; however, this half nozzle repair was installed only in 

the Unit 2 pressurizer. Item 16 is, therefore, a design basis analysis for Unit 2 only. Item 17 is 

the equivalent analysis for Units 1 and 3. 

The staff finds that the applicant analyzed the repaired heater sleeve by the half-nozzle repair 

method for a period of 60 years as shown in LRA Table 4.3-7, items 16 and 17. Therefore, the 

analyses for the half-nozzle repair do not require a TLAA evaluation. The staff finds this 

acceptable because the applicant’s fatigue analysis has demonstrated that the repaired heater 

sleeves will maintain its structural integrity at the end of 60 years. The staff’s concern in 

RAI 4.3.2.4-6 is resolved. 

LRA Section 4.3.2.4 states, “[t]he analysis of the weld pads does not explicitly supersede the 

results of the fatigue analysis with the tapped anchor holes. Therefore, both fatigue analysis 

results apply ....” In RAI 4.3.2.4-7, the staff asked the applicant to discuss whether the anchor 

holes and weld pads on the pressurizer bottom are a TLAA, clarify the above two statements in 

the context of TLAA, and clarify whether the CUFs for the anchor bolts and weld pads for 

60 years are within the allowable factor of 1.0. 

The applicant's March 1, 2010, response to RAI 4.3.2.4-7 stated that the anchor hole analysis 

was for a 40-year design basis set of cycles and is, therefore, a TLAA as shown in LRA 

Table 4.3-7, item 12. The fatigue analysis of the weld pads was for a 60-year design basis set 

of cycles and is, therefore, not a TLAA as shown in LRA Table 4.3-7, item 17. The applicant 

stated that LRA Table 4.3-7, item 16, is an analysis intended to be applicable to all three units; 

however, the replacement heater sleeve was installed only in the Unit 2 pressurizer. Item 16 is, 

therefore, a design basis analysis for Unit 2 only. Item 17 is the equivalent analysis for Units 1 

and 3. 

The applicant explained that the statement, “[t]he analysis of the weld pads does not explicitly 

supersede the results of the fatigue analysis with the tapped anchor holes. Therefore, both 

fatigue analysis results apply ...,” means that the fatigue analysis that evaluated the effects of 

the anchor holes as shown in LRA Table 4.3-7, item 12, was not included in the superseding 

analysis of the weld pads as shown in LRA Table 4.3-7, item 17, that overlaid them. Therefore, 

the results of both analyses are applicable to the safety determination of the pressurizer 

pressure boundary. 

The 40-year Unit 3 anchor hole analysis resulted in a maximum CUF of 0.443, which, projected 

to the end of the period of extended operation, would be 0.6645. The 60-year Units 1 and 3 

weld pad analysis resulted in a maximum CUF of 0.551. 

The staff finds that the applicant has clarified the CUFs in items 12, 16 and 17 of LRA 

Table 4.3-7. LRA Table 4.3-7, item 12 is related to the MNSA attachment holes in the Unit 3 

lower head. LRA Table 4.3-7, item 16 is related to the heater sleeve half-nozzle repair with a 

weld pad for all three units, but the repair is only installed in Unit 2. LRA Table 4.3-7, item 17 is 

related to the heater sleeve MNSA weld pad repair for Units 1 and 3. The staff’s concern in 

RAI 4.3.2.4-7 is resolved. 
Time-Limited Aging Analyses 

 4-53 

Pressurizer Overheating Event. In 2005, Framatome identified a fabrication error that had 

installed longer-than-specified replacement heaters in the Unit 3 pressurizer, extending them 

into the lower region of the heater sleeves. This error subjected local regions of the surrounding 

pressurizer head base metal to temperatures above those for which design stress intensity 

values are given in the ASME Code Section III, Appendix I. The applicant stated that all 36 of 

these Framatome heaters have since been replaced. 

The Unit 3 pressurizer is designed to the ASME Code Section III, 1971 edition through 

winter 1973 addenda, installed to 1974 edition–1975 addenda. The base metal is SA-533, 

Grade A, Class 1, carbon steel. This ASME Code material has a maximum temperature of 

700 degrees F for which design stress intensity values are given; this is also the limiting 

temperature for application of the ASME Code Section III, NB-1120, Figure I-9.1. The applicant 

found that the pressurizer base material surrounding the heater sleeves had been subjected to 

temperatures up to 779 degrees F for up to 3,700 hours. By letter dated June 28, 2005, APS 

submitted a RR for an alternative to NB-1120 for the Unit 3 pressurizer lower head, including an 

evaluation of the creep effects for the Unit 3 pressurizer lower head. 

The applicant’s evaluation applied the elevated temperature rules of the ASME Code Section III, 

Subsection NH, which permits design to specific Subsection NB-3000 rules if creep and 

relaxation are negligible. The evaluation demonstrated that creep was negligible for the 

3,700-hour exposure period; therefore, the ASME Code Section III, Subsection NB rules could 

be used, with the adjusted design stress intensity factors. The applicant found no immediate 

adverse effects on the overheated material, and the staff granted the relief. Although this relief 

was asked “for the remainder of plant life,” as is appropriate for a request supported, in part, by 

an evaluation of fatigue effects, the supporting evaluation of creep effects was limited to the 

3,700-hour exposure to elevated temperature, and the evaluation of the creep effects is 

therefore not a TLAA. However, overheating did affect the code fatigue analysis. 

In RAI 4.3.2.4-8 and RAI 4.3.2.4-9, the staff asked the applicant to provide the technical basis 

supporting that the evaluation of creep effects is not a TLAA. The applicant's March 1, 2010, 

response stated that the evaluation of the creep effect is not a TLAA because the effect ended 

with the replacement of the heaters. The evaluation of the creep effect is, therefore, not a TLAA 

because its assumptions are not time-limited as defined by the current operating term as 

specified in 10 CFR 54.3(a)(3). The evaluation and its conclusions will not change, therefore, 

with an extension to the licensed operating period. 

The applicant stated further that the 2005 overheating event did not affect the currently installed 

heaters or their code fatigue analyses because the affected heaters were replaced, but the 

event did affect the code fatigue analysis of the Unit 3 pressurizer lower head. The effects of 

the overheating on the code fatigue analysis of the pressurizer lower head were evaluated for a 

60-year design life, as summarized in LRA Table 4.3-7, item 18. Since this addendum to the 

design report was done for a 60-year design life, PVNGS did not classify it as a TLAA; however, 

the affected code design report is a TLAA. 

The staff’s concern was that excessive temperatures beyond the design limit might degrade the 

material property of the pressurizer shell; however, the applicant demonstrated that the 

overheating event is not time-dependent, and the creep effect is negligible. The staff finds that 

because the applicant will be implementing the enhanced metal fatigue AMP to monitor certain 

components of the pressurizer, the nozzles, and heater sleeves, these components will be 

inspected per the ASME Code Section XI, and any potential degradation of the pressurizer due 

to the creep effects should be detected. The staff’s concerns in RAIs 4.3.2.4-8 and 4.3.2.4-9 

are resolved. 

Weld Overlay of the Surge line, Spray and Safety Valve Nozzles. The applicant stated that the 

weld overlay of the surge line, spray valve, and safety valve nozzles are supported by fracture 
Time-Limited Aging Analyses 

 4-54 

mechanics analyses and periodic inspections under ASME Code Section XI as the means to 

address aging in the overlaid welds. The applicant stated that the fracture mechanics and 

fatigue crack growth analyses of the overlaid nozzles assume 1.5 times the transient cycles 

used in the 40-year design basis, but they do not support safety determinations for a defined 

design lifetime. Therefore, they are not TLAAs. However, the revised fatigue analyses of the 

adjacent materials affected by the overlays are time-dependent and are TLAAs unless 

successfully projected to the end of the period of extended operation. The revised fatigue 

analyses include the period from initial operation to overlay installation since the adjacent 

materials were not replaced. 

In RAI 4.3.2.4-10, the staff asked the applicant, (1) to clarify whether the CUF calculation and 

fatigue crack growth calculation were calculated for the adjacent materials to the end of 

60 years, (2) to submit the revised fatigue analyses for the adjacent materials or describe in 

detail the analysis input, methods, acceptance criteria, and result, (3) to identify all the 

pressurizer nozzles in all three units that have been weld overlaid and identify “the adjacent 

materials” affected by the weld overlays, and (4) to discuss the actions that will be taken as a 

result of the TLAA determination. 

The applicant's March 1, 2010, response to RAI 4.3.2.4-10 stated that crack growth analyses 

per the ASME Code Section XI, IWB-3640 address potential growth of cracks in the susceptible 

dissimilar weld metal overlay region, but no fatigue crack growth analysis was done for 

materials adjacent to the overlay. The fatigue crack growth analysis pertains to original 

materials under the overlay. In effect, the analyses assume a 60-year design life. 

The flaw growth analyses for the weld overlays projected flaw sizes either to the end of the 

60-year design life or to the next scheduled ISI; or the analyses determined the maximum time 

permitted between ISIs to support the safety determination. In none of these cases did the flaw 

evaluation support a safety determination for a time period defined by the current licensed 

operating term, and, therefore, the flaw evaluation was not a TLAA in any of these cases since it 

does not meet the criteria of 10 CFR 54.3(a)(3). 

The applicant stated that the ASME Code Section III fatigue analyses were done only for 

regions adjacent to the overlay not affected by cracks or assumed cracks. CUFs were 

calculated adjacent to the overlay on a similar (i.e., 60-year) basis. Therefore, CUF analyses 

that met the ASME Code fatigue usage factor limit of 1.0 for 60 years were determined not to be 

TLAAs. Calculations for fatigue in the surge and spray nozzles that did not meet the 60-year 

life, and qualified the location for only 40 years, were determined to be TLAAs. The adjacent 

materials are those determined by the analyses to have effects on their design stresses due to 

the overlays. LRA Table 4.3-7, items 19, 20, and 21, show CUFs for surge, spray, and safety 

nozzles for all three units. 

The applicant calculated a very low CUF for the safety valve nozzles for a 60-year life as shown 

in LRA Table 4.3-7, item 21. This analysis is, therefore, not a TLAA per 10 CFR 54.3(a)(3); 

however, the CUF calculations in the surge and spray nozzles for a 60-year life were higher. 

For the surge and spray nozzles, the applicant was able to demonstrate an acceptable fatigue 

usage for only the design basis number of events assumed for 40 years as shown in LRA 

Table 4.3-7, items 19 and 20. Fatigue for the surge and spray nozzles are managed, therefore, 

by the enhanced metal fatigue AMP for the period of extended operation. 

The staff finds that the applicant has clarified the flaw growth calculations and CUF calculations 

for the overlaid surge line, safety valve, and spray valve nozzles. The staff agrees that the flaw 

growth calculations for the postulated flaw in the overlaid nozzles assumed transient cycles for 

60 years and, because the calculations were performed for 60 years, the flaw growth 

calculations are not TLAAs. The CUF calculations for the surge line and spray valve nozzles 

are TLAA because the CUFs were calculated for 40 years. The safety valve CUF calculation is 
Time-Limited Aging Analyses 

 4-55 

not a TLAA because it was performed for 60 years. The applicant will use the enhanced metal 

fatigue AMP to monitor the CUFs of the surge line and spray valve nozzles, and the staff finds 

this acceptable. Therefore, the staff’s concern in RAI 4.3.2.4-10 is resolved. 

LRA Section 4.3.2.4 discusses the fatigue usage factors for the surge and spray nozzles for a 

60-year life as being 1.44 and 1.49, respectively. The applicant stated that the surge nozzle is 

monitored for fatigue usage, and the fatigue usage factor will not exceed the code limit of 1.0 as 

long as the number of applied load cycles does not exceed the number specified by the design 

specification used in the analyses. In RAI 4.3.2.4-11, the staff asked the applicant to clarify 

whether the spray nozzle will be monitored for fatigue usage and discuss why a plastic analysis 

was not done in accordance with NB-3228 of the ASME Code Section III when the CUFs for 

surge and spray piping exceed 1.0, as calculated by the elastic analysis of NB-322. LRA 

Section 4.3.2.9 discusses a plastic analysis done by CE on the surge line that lowered the CUF. 

The applicant's March 1, 2010, response to RAI 4.3.2.4-11 stated that, as shown in LRA 

Table 4.3-4, item 17, the spray nozzle will be monitored by the enhanced metal fatigue AMP, 

which will maintain the usage factor of the surge and spray nozzles at less than 1.0 for the 

period of extended operation or ensure that other acceptable actions are taken to maintain the 

basis of the safety determination. The applicant stated that a plastic analysis was not required 

since a monitoring method is being used. LRA Section 4.3.2.9 (and Section 4.3.4) provides the 

plastic analysis of the surge line because it has been performed in support of the safety 

determination for the current licensed operating term and is, therefore, a TLAA. The staff finds 

that LRA Table 4.3-4, items 16 and 17, state that the surge line and spray nozzle will be 

monitored by the enhanced metal fatigue AMP because of high CUFs. The staff finds that 

because the surge line and spray valve nozzles will be monitored by the enhanced metal fatigue 

AMP, the structural integrity of these nozzles will be maintained. Therefore, the staff’s concern 

has been addressed and RAI 4.3.2.4-11 is resolved. 

LRA Section 4.3.2.4 states that the enhanced metal fatigue AMP will ensure that the fatigue 

usage factors, based on those transient events, will remain within the ASME Code limit of 1.0 

for the period of extended operation, or will ensure that re-evaluation or other corrective actions 

will be taken before the design basis number of these events is exceeded. In RAI 4.3.2.4-15, 

the staff asked the applicant to identify the pressurizer subcomponents that will be reanalyzed in 

the context of Section 4.3.2.4. 

The applicant's March 1, 2010, response to RAI 4.3.2.4-15 stated that a subcomponent will be 

reanalyzed or reanalyzed if it is determined by the enhanced metal fatigue AMP that fatigue in 

the subcomponent has reached an action limit that requires mitigation of fatigue effects and that 

re-evaluation or reanalysis is the preferred mitigation action. Other possible corrective actions 

include repair, replacement, or a fatigue crack growth analysis plus augmented inspection. The 

pressurizer subcomponents that will be reanalyzed will be determined by the state of fatigue 

effects in the pressurizer at that time, as tracked by the enhanced metal fatigue AMP, and upon 

review of the affected Class 1 pressurizer analyses. LRA Section 4.3.1 and Appendix B3.1 

provide further description of the enhanced metal fatigue AMP, including locations to be 

monitored and the bases for action limits. The staff finds that the applicant has satisfactorily 

addressed the circumstances in which the re-evaluation of the fatigue usage factors will be 

performed. Therefore, the staff’s concern in RAI 4.3.2.4-15 is resolved. 

In summary, the staff finds that the applicant has adequately addressed time-dependent 

analyses (i.e., CUF calculations and crack growth calculations) of the pressurizer and 

associated components in all three units in terms of TLAAs. Therefore, the staff finds that the 

pressurizer will maintain its structural integrity during the period of extended operation. 
Time-Limited Aging Analyses 

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4.3.2.4.3 Updated Final Safety Analysis Report Supplement 

The applicant provided an UFSAR supplement summary description of its TLAA of the 

pressurizer and pressurizer nozzles in LRA Section A3.2.1.4. Based on its review of the 

UFSAR supplement, the staff concludes that the summary description of the applicant’s actions 

to address the TLAA for the pressurizer and pressurizer nozzles is adequate. 

4.3.2.4.4 Conclusion 

Based on its review, the staff concludes pursuant to 10 CFR 54.21(c)(1)(iii), that the applicant 

has demonstrated that the effects of aging on the intended function of the pressurizer and 

pressurizer nozzles will be adequately managed for the period of extended operation. The 

UFSAR supplement contains an appropriate summary description of the TLAA evaluation of the 

pressurizer and pressurizer nozzles, as required by 10 CFR 54.21(d). 

4.3.2.5 Steam Generator American Society of Mechanical Engineers Code, Section III 

Class 1, Class 2 Secondary Side, and Feedwater Nozzle Fatigue Analyses 

4.3.2.5.1 Summary of Technical Information in the Application 

LRA Section 4.3.2.5 and Amendment 16 dated May 27, 2010, summarize the evaluation of the 

fatigue analyses of ASME Code Section III, Class 1 SG, Class 2 secondary side, and the 

feedwater nozzles. The applicant stated that the replacement SGs are designed to ASME Code 

Section III, Subsection NB (Class 1) and NC (Class 2). The LRA identified that the Unit 1 and 3 

SGs will be within their 40-year design life at the end of the period of extended operation, and 

the Unit 2 SGs will be at year 42 of operation at the end of the period of extended operation. 

The original LRA dispositioned the Unit 2 SG TLAAs in accordance with 10 CFR 54.21(c)(1)(iii), 

that the effects of aging on the intended function(s) will be adequately managed for the period of 

extended operation. The Units 1 and 3 SG TLAAs were dispositioned in accordance with 

10 CFR 54.21(c)(1)(i), that the analyses remain valid during the period of extended operation. 

4.3.2.5.2 Staff Evaluation 

The staff reviewed LRA Section 4.3.2.5 and Amendment 16 to verify, pursuant to 

10 CFR 54.21(c)(1)(i), that the TLAA of the ASME Code Section III Class 1 SG, Class 2 

secondary side, and feedwater nozzles remain valid during the period of extended operation. 

Further, the staff's review evaluated, pursuant to 10 CFR 54.21(c)(1)(iii), if the effects of aging 

on the intended function(s) of the ASME Code Section III Class 1 SG, Class 2 secondary side, 

and feedwater nozzles will be adequately managed for the period of extended operation. 

The applicant stated that pressure-retaining and support components of the primary coolant 

side of the SGs are subject to an ASME Code Section III fatigue analysis. Although the 

secondary side is Class 2, all pressure retaining parts of the SGs satisfy the Class 1 criteria, 

including Section III fatigue analysis. 

The staff reviewed LRA Section 4.3.2.5 as related to the replacement recirculating SG tube CUF 

calculations. The applicant stated that this analysis is not a TLAA because the safety 

determination does not depend on it and due to periodic SG tube inspection schedules. The 

staff does not consider the applicant's apparent use of SCC mechanisms and ASME Code 

examinations as a valid basis for concluding that the CUF calculations would not qualify the 

tubes for metal fatigue during the remainder of the licensed life of the tubes. By letter July 21, 

2010, the staff issued RAI 4.3-13, requesting that the applicant justify its basis for concluding 

that the CUF calculation for the replacement recirculating SG tubes is not a TLAA. 

The applicant responded to RAI 4.3-13 by letter dated August 12, 2010 (Amendment 22). The 

staff’s evaluation of RAI 4.3-13 is documented in SER Section 3.1.2.2.1. The staff noted that 

the applicant amended LRA Section 4.3.2.5 to identify the SG tube fatigue analysis as a TLAA 
Time-Limited Aging Analyses 

 4-57 

and to disposition the TLAA for the SG tubes in accordance with 10 CFR 54.21(c)(1)(i). The 

applicant stated that the cyclic stress range for the SG tubes is less than the endurance limit, 

and this allows the SG tubes to withstand an infinite number of cycles, so the CUF was 

determined to be zero. The applicant further explained that since the SG tube CUF is zero, the 

analysis of record remains valid through the period of extended operation for all three PVNGS 

units. The staff finds it acceptable that the applicant amended its LRA to identify the SG tube 

code fatigue analysis as a TLAA, because this analysis meets the definition of a TLAA as 

defined in 10 CFR 54.3. The staff finds it acceptable that the SG tube code fatigue TLAA is 

dispositioned in accordance with 10 CFR 54.21(c)(1)(i), because the CUF value for the SG 

tubes was calculated to be zero for all three units and, therefore, the SG tubes will endure an 

infinite number of cycles. The staff’s concern in RAI 4.3-13 related to the SG tube code fatigue 

analysis is resolved. 

LRA Table 4.3-8 provides the design basis CUF for the replacement SGs (considering the 

power uprate) for all three units. The applicant explained that although the replacement SG 

designs are essentially identical, the Unit 2 code analysis was performed first, under separate 

contract. The calculated CUFs therefore differ in some components. Furthermore, the applicant 

stated that since the ASME code does not specify all locations which must be analyzed, this left 

many of the detailed choices to the experience and skill of the analyst. For example, the Unit 2 

analyst did not elect to perform a fatigue analysis at the support skirt opening or in the 

economizer cylinder near the tubesheet while the Unit 1 and 3 analyst did so. 

For the high usage factors calculated for the primary manway and secondary handhole studs, 

the applicant stated that the fatigue analysis determines the replacement interval of those 

components, and the fatigue analysis is, therefore, not a TLAA for these studs. 

The applicant also stated that the worst-case usage factors calculated for the specified set of 

design basis transients for the replacement SGs (considering the power uprate) exceed 0.9 in 

several SG components. The applicant explained that fatigue usage factors in the SG 

components do not depend on effects that are time-dependent at steady-state conditions, but 

depend only on effects of operational and upset transient events. The applicant chose to apply 

aging management to all the SGs and will use the enhanced Metal Fatigue Program to track 

events and ensure that appropriate reevaluation or other corrective action will be initiated if an 

action limit is reached. 

Based on its review, the staff finds the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(i), that the TLAA analyses for the SG tubes remains valid during the period 

of extended operation because the cyclic stress range for the SG tubes is less than the 

endurance limit allowing an infinite number of cycles. The staff also finds the applicant has 

demonstrated, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended 

functions of the replacement SG pressure boundaries with Class 1 analyses, with the exception 

of the SG tubes, will be adequately managed for the period of extended operation because 

action limits of the enhanced Metal Fatigue Program will ensure completion of corrective actions 

before the design basis number of events is exceeded. Thus, the fatigue usage factor will not 

exceed the design limit of 1.0 during the period of extended operation. 

4.3.2.5.3 Updated Final Safety Analysis Report Supplement 

LRA Section A3.2.1.5 provides the UFSAR supplement summarizing the evaluation of the 

fatigue analyses for ASME Code Section III Class 1 SG, Class 2 secondary side, and feedwater 

nozzles. Based on its review of the UFSAR supplement, the staff concludes that the applicant 

provided an adequate summary description of its actions to address the TLAA for the ASME 

Code Section III Class 1 SG, Class 2 secondary side, and feedwater nozzles, as required by 

10 CFR 54.21(d). 
Time-Limited Aging Analyses 

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4.3.2.5.4 Conclusion 

On the basis of its review, the staff concludes that, pursuant to 10 CFR 54.21(c)(1)(i), the 

applicant has demonstrated that the fatigue analysis for the SG tubes remain valid for the period 

of extended operation. Pursuant to 10 CFR 54.21(c)(1)(iii), the applicant has demonstrated that 

the effects of aging on the intended functions of the ASME Code Section III Class 1 SG, Class 2 

secondary side, and feedwater nozzles will be adequately managed for the period of extended 

operation. The UFSAR supplement contains an appropriate summary description of the TLAA 

evaluation, as required by 10 CFR 54.21(d). 

4.3.2.6 American Society of Mechanical Engineers Code, Section III, Class 1 Valves 

4.3.2.6.1 Summary of Technical Information in the Application 

LRA Section 4.3.2.6 and Amendment 16 dated May 27, 2010, summarize the evaluation of the 

fatigue analyses of the ASME Code Section III, Class 1 valves. The applicant stated that those 

valves are designed to ASME Code Section III, Subsection NB. The applicant also stated while 

ASME Code requires a fatigue analysis only for Class 1 valves with an inlet greater than 

four inches nominal, some Class 1 valves with an inlet four inches or less also require a fatigue 

analysis. The applicant dispositioned these TLAAs in accordance with 10 CFR 54.21(c)(1)(iii), 

that the effects of aging on the intended functions will be adequately managed for the period of 

extended operation. 

4.3.2.6.2 Staff Evaluation 

The staff reviewed LRA Section 4.3.2.6 and Amendment 16 to verify pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended functions will be adequately 

managed for the period of extended operation. 

In LRA Table 4.3-9, the applicant listed the Class 1 valves and corresponding design basis CUF 

values. The table showed that the calculated worst-case usage factors are 0.702 and 0.7656, in 

the 16-inch shutdown cooling suction isolation valves and 2-inch charging line isolation valves, 

respectively. The applicant explained that fatigue usage factors in these valves do not depend 

on effects that are time-dependent at steady-state conditions, but depend only on effects of 

operational, abnormal, and upset transient events. 

Effects of Power Uprate and SG Replacement on the CEDM and RVLMS Pressure Housing 

Analyses. LRA Section 4.3.2.6 and Amendment 16 state that the original fatigue analyses of 

record are still valid and the effects of the SG replacements and power uprate loads on the 

analysis of record have been reconciled. 

Effects of Combustion Engineering Infobulletin 88-09. The applicant stated that the CE Owner’s 

Group review did not identify any effects on the fatigue analysis of the ASME III Class 1 valves. 

Based on its review, the staff finds the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended functions of the ASME III 

Class 1 valves will be adequately managed for the period of extended operation because the 

action limits of the enhanced Metal Fatigue Program will ensure completion of corrective actions 

before the design basis number of events is exceeded. Thus, the fatigue usage factor will not 

exceed the design limit of 1.0 during the period of extended operation. 

4.3.2.6.3 Updated Final Safety Analysis Report Supplement 

LRA Section A3.2.1.3 provides the UFSAR supplement summarizing the evaluation of the 

fatigue analyses for the ASME Code Section III, Class 1 valves. Based on its review of the 

UFSAR supplement, the staff concludes that the applicant provided an adequate summary 

description of its actions to address the TLAA for the ASME Code Class 1 valves as required by 

10 CFR 54.21(d). 
Time-Limited Aging Analyses 

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4.3.2.6.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended functions of the ASME Code 

Section III, Class 1 valves will be adequately managed for the period of extended operation. 

The staff also concludes that the UFSAR supplement contains an appropriate summary 

description of the TLAA evaluation as required by 10 CFR 54.21(d). 

4.3.2.7 American Society of Mechanical Engineers III Class 1 Piping and Piping 

Nozzles 

4.3.2.7.1 Summary of Technical Information in the Application 

The ASME Code Class 1 reactor coolant main loop piping is designed to the ASME Code 

Section III, Subsection NB, 1974 edition with addenda through summer 1974. The main loop 

piping fatigue analysis was performed to the 1974 edition with addenda through summer 1974. 

The fatigue analyses of piping outside the main loop used the 1974 edition with addenda 

through winter 1975 or the 1977 edition with addenda through summer 1979. These fatigue 

analyses have been updated to incorporate redefinitions of loads and design basis events, 

operating changes, power uprate, SG replacement, and minor modifications. The currently 

applicable fatigue analyses of the Class 1 piping are TLAAs. 

4.3.2.7.2 Staff Evaluation 

The staff reviewed LRA Section 4.3.2.7 to verify, pursuant to 10 CFR 54.21(c)(1)(iii), that the 

effects of aging on the intended function(s) of the ASME Code Section III, Class 1, piping and 

piping nozzles will be adequately managed for the period of extended operation. 

The applicant stated that in the primary coolant piping, the most limiting calculated design basis 

usage factors occur in the charging nozzles and approach the limit of 1.0 due to transient 

thermal stresses from normal operating and upset injection events. The applicant stated that, 

with the exception of the charging line nozzles and possibly the pressurizer surge line discussed 

in Section 4.3.2.9, fatigue usage factors in these components do not depend on effects that are 

time-dependent at steady-state conditions but depend only on effects of operational, abnormal, 

and upset transient events. The applicant stated that the Metal Fatigue AMP will track these 

transient events, and the design basis fatigue usage factor limit of 1.0 will not be exceeded in 

these locations without an appropriate evaluation and any necessary mitigating actions. 

The applicant stated that original codes of record did not invoke the requirement for cycle-based 

stress limit for pipe support and, as permitted by code rules, later editions were not invoked for 

any pipe support reanalysis. The staff finds that the pipe supports were designed without 

considering cycle-based stresses per the ASME Code Section III requirements; therefore, pipe 

supports do not have a TLAA. 

The staff reviewed the following subsections: 

 Effects of Power Uprate and SG Replacement on the Piping Fatigue Analyses 

 Charging Lines and Nozzles 

 Reduced Wall Thickness in the RCS 

 Alloy 600 Hot Leg Small-Bore Nozzle Repairs 

 Alloy 600 Hot Leg Small-bore Half Nozzle Repairs 

 Effect of Unit 3 MNSA Holes on Reactor Coolant Piping 

 Redesigned RCS Thermowells 

 Safety Injection Nozzle Thermal Sleeves and Auxiliary Spray Line 

 Hot Leg Surge and Shutdown Cooling Nozzle Weld Overlays 

 Disposition: Aging Management per 10 CFR 54.21(c)(1)(iii) 
Time-Limited Aging Analyses 

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Effects of Power Uprate and Steam Generator Replacement on the Piping Fatigue Analyses. 

LRA Section 4.3.2.7 states that RCS piping, nozzles, RTD thermowells, and other Class 1 

piping satisfy the CLB design number of transients under power uprate and SG replacement. 

However, it is not clear to the staff whether the piping components have been analyzed for 

60 years. By letter dated January 14, 2010, the staff issued RAI 4.3.2.7-1 asking the applicant 

to clarify whether the Class 1 piping components satisfy the allowable CUF of 1.0 using a 

projected number of transients at the end of 60 years. 

The applicant's March 1, 2010, response to RAI 4.3.2.7-1 stated that the RCS piping, nozzle, 

RTD thermowell, and other Class 1 piping component analyses that were not based on a 

60-year life, are TLAAs. The applicant stated that the disposition of these TLAAs depends on 

the enhanced metal fatigue AMP to ensure that the 40-year design numbers of transients will 

not be exceeded during 60 years of operation without appropriate corrective actions. These 

TLAAs will, therefore, be managed for the period of extended operation in accordance with 

10 CFR 54.21(c)(1)(iii). 

The staff finds that because the CUF calculations of Class 1 piping were not performed for 

60 years, the applicant will use the enhanced metal fatigue AMP to monitor the transient cycles 

used in the fatigue analyses to ensure they are bound by the actual cycles during the period of 

extended operation. The staff finds that the applicant’s use of the enhanced metal fatigue AMP 

to monitor the transient cycles is acceptable and the staff’s concern in RAI 4.3.2.7-1 is resolved. 

Charging Lines and Nozzles. LRA Section 4.3.2.7 states that the Metal Fatigue of Reactor 

Coolant Pressure Boundary Program will calculate SBF in the chemical and volume control 

system charging nozzle. By letter dated January 14, 2010, the staff issued RAI 4.3.2.7-2, 

asking the applicant to describe the SBF analysis in detail, such as the analysis input, analytical 

procedures and method, acceptance criteria, and results. By letter dated March 1, 2010, in 

response to RAI 4.3.2.7-2, the applicant stated that the calculation has not yet been done. 

The future SBF monitoring program is discussed in the disposition of LRA Sections 4.3.2.7 

and 4.3.1, as follows: 

Stress-based fatigue (SBF) monitoring will compute a “real time” stress history 

for a given component from actual temperature, pressure, and flow histories. 

SBF is intended for those high-fatigue components where a more refined 

approach is necessary to show long-term structural acceptability. SBF 

monitoring depends on “global-to-local” correlation or “transfer” functions which 

calculate local transient pressures and temperatures from data collected by the 

limited number of plant instruments, and from them, local stresses and fatigue 

usage. 

The applicant stated that the SBF monitoring method is an enhancement to the metal fatigue 

AMP. Furthermore, the analysis details, such as the analysis input, analytical procedures and 

method, and acceptance criteria have not yet been completed. For SBF monitoring, the 

applicant has committed to the use of a fatigue-monitoring software program that incorporates a 

three-dimensional, six-element model, meeting the ASME Code Section III, NB-3200 

requirements. This will be implemented at least two years before the period of extended 

operation. By letter dated February 19, 2010, the applicant submitted Amendment 9, which 

updated Commitment No. 39 in LRA Appendix A, Table A4-1, to include the use of the 

three-dimensional, six-element fatigue-monitoring model. 

By letter dated May 27, 2010, the applicant submitted Amendment 16 which revised the 

monitoring method for the charging lines and nozzles to use a CBF-EP monitoring method. The 

staff noted that this method of monitoring is consistent with the recommendations of the 

“parameters monitored/inspected” program element of GALL AMP X.M1, which states that more 

detailed local monitoring of the plant transient may be used to compute the actual fatigue usage 
Time-Limited Aging Analyses 

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for each transient. The staff’s review of the applicant CBF-EP monitoring method is 

documented in SER Section 4.3.1.2.2. 

The staff finds it acceptable that the applicant will use the CBF-EP monitoring method for the 

charging lines and nozzles because it monitors the transient events and thermals cycles to 

ensure that the usage factor in the CVCS charging nozzles is within the ASME Code Section III 

allowable limit of 1.0, consistent with the recommendations of GALL AMP X.M1. The staff’s 

concern in RAI 4.3.2.7-2 is resolved. 

Reduced Wall thickness in the Reactor Coolant System. The applicant reviewed the fatigue 

analysis for the RCS hot leg and cold leg piping for the SG replacement and power uprate. As a 

result of the review, the applicant amended two design reports that account for two piping 

configurations. 

The LRA states that the first modification involved the intended design configuration, which 

assumes full carbon steel field welds. These results continue to remain applicable to the actual 

pipe runs, but not the field welds. This configuration results in a maximum calculated usage 

factor well below 1.0 for the hot leg and hot leg elbow. This fatigue analysis assumes the 

design basis transients for a 40-year plant life; therefore, it is a TLAA that will be managed 

through the enhanced metal fatigue AMP. 

The LRA states that the second configuration assumed reduced piping wall thicknesses at both 

“postulated” and “acceptable” minimum wall thicknesses. The postulated minimum wall 

thickness values were bounding values for all three units. The acceptable minimum wall 

thickness values were based on design condition stress limits. This evaluation also evaluated 

all design basis transients for a 40-year plant life. All of the fatigue calculations use 

conservative bending stress intensification factors that are specifically applicable only to the 

crotch region of elbows. This evaluation also assumed a reduced wall thickness for the entire 

pipe run, rather than the welds. This evaluation concluded that the acceptable minimum wall 

thickness values in all field weld locations meet all ASME Code requirements. 

The applicant stated that the evaluation for reduced wall thicknesses calculated fatigue usage 

factors approaching 1.0. Fatigue in RCS piping can be adequately managed during the period 

of extended operation using the CC method. The applicant also stated that CC monitoring will 

ensure that re-evaluation or other corrective action is initiated if the CC action limit is reached. 

The applicant stated that this is adequate to manage the fatigue in the welds because the 

revised calculated fatigue usage in the welds has the same transient event cycle count basis. 

Action limits will permit completion of corrective actions before the design basis number of 

events is exceeded. 

By letter dated February 14, 2010, the staff issued RAI 4.3.2.7-3, asking that the applicant do 

four things: (1) clarify why the fatigue usage factor for the RCS hot and cold leg piping with 

reduced wall thickness was not calculated for 60 years, (2) list all Alloy 82/182 welds in the RCS 

hot leg and cold leg piping, (3) discuss whether there are any indications or flaws detected in 

the Alloy 82/182 welds that remained in service, and (4) if there are flaws in the Alloy 82/182 

welds, perform a fatigue crack growth analysis for the 60-year plant life or justify why flaw 

evaluations are not need to demonstrate the structural integrity of the affected welds at the end 

of 60 years. 

The applicant's March 1, 2010, response to RAI 4.3.2.7-3 stated that fatigue usage factors in 

the RCS hot and cold leg piping with reduced wall thickness were not projected to 60 years 

because the disposition of the TLAA depends on the enhanced metal fatigue AMP to ensure 

that the 40-year design numbers of transients will not be exceeded during 60 years of operation 

without appropriate corrective actions. These TLAAs will, therefore, be managed for the period 

of extended operation in accordance with 10 CFR 54.21(c)(1)(iii). The applicant stated further 

that there are no Alloy 82/182 welds in the main loop RCS hot and cold leg piping. 
Time-Limited Aging Analyses 

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The staff finds that it is acceptable that the applicant will use the enhanced metal fatigue AMP to 

ensure that the 40-year design basis transients will not be exceeded during the period of 

extended operation. The staff concern in RAI 4.3.2.7-3 is resolved. 

Alloy 600 Hot Leg Small-Bore Nozzle Repairs. The applicant stated that all the Alloy 600 

instrumentation nozzles have been replaced in the hot legs and pressurizer for all three units in 

an effort to reduce the potential for PWSCC. Welded plugs, full nozzle, half nozzle, and 

three-quarter nozzle repairs have been used for the inservice RTDs. The half nozzle repair 

applies to the removal of the lower half (axial length) of the original nozzle. The three-quarter 

nozzle repair applies to the removal of lower three-quarter length of the original nozzle. The full 

nozzle repair applies to the removal of the entire original nozzle and installation of a complete 

new nozzle. The methods and new design basis for the repairs used in the RCS hot leg 

small-bore nozzles are discussed below. The pressurizer nozzle repairs are evaluated in SER 

Section 4.3.2.4. 

LRA Section 4.3.2.7 states that the original RCS hot legs contained 27 Alloy 600 small-bore 

nozzles in each unit. In 1992, the applicant replaced seven pressure differential transmitter 

(PDT) nozzles and one sample nozzle in Unit 2 with full nozzles. The applicant stated that the 

remaining hot leg small-bore nozzles were replaced with the Alloy 690 half-nozzle design. 

However, it is not clear to the staff whether these remaining nozzles are located in Unit 1, 2, or 3 

and it is not clear why small-bore nozzles in Units 1 and 3 are not discussed in this section. By 

letter dated February 14, 2010, the staff issued RAI 4.3.2.7-4, asking the applicant to complete 

the following tasks: 

 Provide a table, similar to Table 4.3-7, with the following information: list all 

27 small-bore nozzles for each unit, identify the type of the nozzle (e.g., RTD or PDT) or 

systems, identify the repair method for each nozzle, identify whether a fatigue analysis 

was performed for 60 years for each nozzle, and specify whether a TLAA is needed. 

 If a nozzle is not analyzed for 60 years, perform a fatigue analysis for 60 years, or justify 

why a fatigue analysis is not needed to demonstrate that that small-bore nozzle satisfy 

the ASME Code Section III allowable usage factor of 1.0 at the end of 60 years. 

 Discuss whether cold leg piping contains small-bore Alloy 600 nozzles, whether they 

were replaced with Alloy 690 nozzles, and whether their fatigue usage factors were 

analyzed for 60 years. 

By letter dated March 1, 2010, in response to RAI 4.3.2.7-4, the applicant provided the following 

account of the small-bore nozzle repairs for hot leg piping (Table 4.3-1). 

Table 4.3-1. Alloy 600 Small-Bore Hot Leg Nozzle Repairs 

Unit Number and Type of Nozzle Repair Type Maximum CUF 

1 9 Pressure and sampling Half nozzle repair Fatigue waiver

 8 Spare RTD Welded plugs 0.051

 10 Inservice RTD Three quarter nozzle repair 0.0105

2 8 (7 PDT and 1 sampling) Full nozzle repair 0.863

 1 Pressure and sampling Half nozzle repair Fatigue waiver

 8 Spare RTD Welded plugs 0.051

 10 In service RTD Three quarter nozzle repair 0.0105

3 9 Pressure and sampling Half nozzle repair Fatigue waiver

 8 Spare RTD Welded plugs 0.051
Time-Limited Aging Analyses 

 4-63 

Unit Number and Type of Nozzle Repair Type Maximum CUF 

 10 Inservice RTD Three quarter nozzle repair 0.0105

 

The applicant stated that the TLAAs for the above hot leg small-bore nozzles will be managed 

by the enhanced metal fatigue AMP for the period of extended operation in accordance with 

10 CFR 54.21(c)(1)(iii). The disposition of these TLAAs depends on the enhanced metal fatigue 

AMP to ensure that the number of transients for the 40-year design will not be exceeded during 

60 years of operation without appropriate corrective actions. 

The applicant stated that the RCS cold leg piping still contains 12 small-bore Alloy 600 nozzles. 

The maximum CUF associated with the cold leg RTD nozzles is 0.0591. The fatigue analysis 

was performed using the 40-year design numbers of transients. These TLAAs will, therefore, be 

managed by the enhanced metal fatigue AMP for the period of extended operation in 

accordance with 10 CFR 54.21(c)(1)(iii). The enhanced metal fatigue AMP will ensure that the 

numbers of transients for the 40-year design will not be exceeded during 60 years of operation 

without appropriate corrective actions. 

The staff finds that the applicant has clarified the number and type of the small-bore nozzles in 

the hot leg pipe, the types of repairs, and the maximum CUF for specific components in each 

unit. For the cold leg, there are still 12 Alloy 600 nozzles. The staff finds that the small-bore 

nozzles in the hot leg and cold leg will be managed by the enhanced metal fatigue AMP during 

the period of extended operation. Therefore, their structural integrity will be maintained such 

that they can perform their intended functions. The staff’s concern in RAI 4.3.2.7-4 is resolved. 

Alloy 600 Hot Leg Small-bore Half Nozzle Repairs. LRA Section 4.3.2.7 discusses that the PDT 

and sampling half-nozzle repairs do not need a fatigue analysis (fatigue analysis waiver) as 

required by Section NB-3222.4(d) of the ASME Code Section III. However, the welded plugs for 

the RTD nozzles repairs were analyzed for fatigue per ASME Code Section III, 

Article NB-3222.4(e). By letter dated February 14, 2010, the staff issued RAI 4.3.2.7-5, asking 

the applicant to explain why a fatigue analysis does not need to be performed for the half nozzle 

repair, but one is required for the weld plug repair. 

The applicant's March 1, 2010, response to RAI 4.3.2.7-5 stated that the Class 1 main loop 

piping fatigue analysis was performed to the ASME Code Section III, Subsection NB, 1974 

edition with addenda through summer 1974. The PDT and sampling half-nozzle repairs 

satisfied the fatigue waiver evaluation of ASME Code Section III, Article NB-3222.4(d). Per 

Article NB-3222.4(a), “If the specified operation of the component meets all of the conditions of 

NB-3222.4(d), no analysis for cyclic operation is required...” The NB-3222.4(d) fatigue waiver 

option for the welded plugs was not pursued. 

The staff finds that the applicant followed the requirements of the ASME Code Section III, 

NB-3222.4(a) and NB-3222.4(d) and agrees that the applicant is not required to do a fatigue 

analysis for the PDT and sampling nozzles. The staff’s concern in RAI 4.3.2.7-5 is resolved. 

Effect of Unit 3 MNSA Holes on Reactor Coolant Piping. The applicant stated that a MNSA had 

been installed at a leaking thermowell in Unit 3. This MNSA was replaced with a three-quarter 

nozzle repair via the Alloy 600 replacement program. The tapped holes in the hot leg for the 

MNSA attachment were not repaired after the nozzle replacement. This portion of the Unit 3 hot 

leg has a higher CUF at the tapped hole location, as identified in the MNSA design report. The 

CUF was confirmed in the replacement SG and power uprate design report. The applicant also 

stated that the higher CUFs associated with the MNSA tapped holes will not affect the fatigue 

monitoring of the RCS piping. The enhanced metal fatigue AMP CC monitoring action limit for 

the RCS will initiate re-evaluation or other corrective actions to address this Unit 3 location. 
Time-Limited Aging Analyses 

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Action limits will permit completion of corrective actions before the design basis number of 

events is exceeded. 

The MNSA has been replaced with a three-quarter nozzle repair and the tapped hole is a 

remnant of the MNSA repair. The staff finds that the applicant will use the CC method in the 

metal fatigue program to monitor the fatigue analysis of the tapped hole location at a replaced 

thermowell at Unit 3. The staff finds this acceptable because the applicant will monitor the 

effects of aging with the enhanced metal fatigue AMP such that corrective actions are taken 

before exceeding the design limit. 

Redesigned Reactor Coolant System Thermowells. LRA Section 4.3.2.7, subsection 

“Redesigned Reactor Coolant System Thermowells,” states that the thermowell modifications 

did not affect the previous conclusion concerning fatigue of the thermowells and that there is no 

safety determination based on the plant life for these high-cycle loads. Therefore, this is not a 

TLAA. By letter dated February 14, 2010, the staff issued RAI 4.3.2.7-6, asking the applicant to 

explain why this issue is not a TLAA since the thermowells experience high-cycle fatigue that is 

time-dependent. Also the applicant was requested to perform a fatigue analysis of the 

thermowells for 60 years, or justify why a fatigue usage factor analysis for 60 years is not 

needed to demonstrate that the new thermowell design satisfy the ASME Code Section III 

allowable CUF of 1.0. 

The applicant's March 1, 2010, response to RAI 4.3.2.7-6 stated that the failure mechanism of 

the thermowells was high-cycle fatigue caused by the resonance between the thermowell’s 

natural frequency and the vortex shedding frequencies of the coolant inside the pipe. 

Furthermore, the analysis and testing of the redesigned thermowells determined that the new 

design was not susceptible to this failure mechanism. This determination did not consider the 

plant life; therefore, the evaluation for high-cycle fatigue is not a TLAA, in accordance with 

10 CFR 54.3(a)(3). 

The staff finds that the new redesigned thermowells are not susceptible to high-cycle fatigue 

degradation mechanism, which was caused by resonance between the old thermowell natural 

frequency and the vortex shedding frequencies of the coolant inside the pipe. The staff agrees 

that the evaluation for high-cycle fatigue is not a TLAA and is not required to be considered for 

the new thermowells. This staff’s concern in RAI 4.3.2.7-6 is resolved. 

Safety Injection Nozzle Thermal Sleeves and Auxiliary Spray line. LRA Section 4.3.2.7 

concludes that the modification on thermal sleeves of the safety injection nozzles did not affect 

the previous conclusion concerning fatigue of the safety injection nozzles. However, the 

applicant did not discuss whether the fatigue analysis of the safety injection nozzles or the 

auxiliary spray line was based on 40-year or 60-year transient cycles. Also, the LRA states that 

the CUF, including the effects of thermal gradient in the auxiliary spray line, meets the ASME 

Code Section III, for a 40-year plant life. By letter dated February 14, 2010, the staff issued 

RAI 4.3.2.7-7 and RAI 4.3.2.7-8, asking the applicant to perform a fatigue analysis for 60 years 

or justify why a fatigue analysis of the safety injection nozzles and auxiliary spray line and tee 

for the end of 60 years is not needed to demonstrate that the CUFs of the subject nozzles at the 

end of plant life satisfies the ASME Code Section III allowable of 1.0. The staff also asked 

whether this analysis is a TLAA. 

The applicant's March 1, 2010, response to RAIs 4.3.2.7-7 and 4.3.2.7-8 stated that the fatigue 

analysis of the safety injection nozzles was performed using the 40-year design numbers of 

transient cycles; therefore, it is a TLAA and will be managed for the period of extended 

operation in accordance with 10 CFR 54.21(c)(1)(iii). The disposition of the fatigue analysis of 

the safety injection nozzles depends on the enhanced metal fatigue AMP to ensure that the 

40-year design numbers of transients will not be exceeded during 60 years of operation without 

appropriate corrective actions. The applicant responded that the auxiliary spray line and tee 
Time-Limited Aging Analyses 

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fatigue analysis is a TLAA and will be managed for the period of extended operation in 

accordance with 10 CFR 54.21(c)(1)(iii). The disposition of the fatigue analysis of the auxiliary 

spray line and tee depends on the enhanced metal fatigue AMP to ensure that the 40-year 

design number of transients will not be exceeded during 60 years of operation without 

appropriate corrective actions. 

The staff finds that the applicant has clarified that the fatigue analysis of the safety injection 

nozzles and auxiliary spray line and tee is a TLAA, and the enhanced Metal Fatigue Program 

will monitor the fatigue analysis of the safety injection nozzles. The staff finds that the 

enhanced Metal Fatigue Program will maintain the structural integrity of the safety injection 

nozzles and auxiliary spray line and tee; therefore, the staff’s concerns in RAIs 4.3.2.7-7 

and 4.3.2.7-8 are resolved. 

Hot Leg Surge and Shutdown Cooling Nozzle Weld Overlays. The applicant stated that 

PWSCC is a degradation mechanism for Alloy 82/182 welds. The applicant further stated that 

while no flaws have been detected at PVNGS, it will install full structural weld overlays over the 

pressurizer surge, spray, safety and relief valve nozzles, and the hot leg surge and shutdown 

cooling nozzle welds to ensure structural integrity of the RCS boundary. The applicant stated 

that these weld repairs meet the requirements of ASME Code Class 1 components and are 

supported by fracture mechanics analyses and periodic inspections. The applicant also stated 

that the fracture mechanics analyses of the materials overlaid by the weld repair are not TLAAs. 

The staff determined that it needed further information as discussed below. 

By letter dated February 14, 2010, the staff issued RAI 4.3.2.7-9, asking the applicant to explain 

why the fracture mechanics analyses of the hot leg surge and shutdown cooling nozzles 

overlaid by the weld repair are not TLAAs. By letter dated March 1, 2010, in response to 

RAI 4.3.2.7-9, the applicant stated that the fatigue crack growth analyses calculate the crack 

propagation in order to demonstrate that a postulated crack will not exceed the acceptance 

criterion of the analysis during the inspection interval. The inspection interval is less than the 

plant life; therefore, the fatigue crack growth analyses are not TLAAs, in accordance with 

10 CFR 54.3(a)(3). 

The applicant stated further that the fatigue crack growth analyses of the weld overlay of the hot 

leg surge line and shutdown cooling line nozzles are not TLAAs because the postulated flaw is 

calculated for the inspection interval. The staff agrees that the fatigue crack growth analyses 

are not TLAAs when the nozzles are inspected during every 10-year inspection interval or are 

inspected within the time period before the flaws in the nozzles are projected to reach an 

unacceptable size, as shown in the fatigue crack growth analyses. 

By letter dated May 8, 2008, the applicant submitted for the staff’s review and approval, RR 36 

for the weld overlay repair of the hot leg surge line and shutdown cooling line nozzles for the 

third ISI interval for Units 1 and 3. By letter dated November 10, 2008, the staff authorized the 

use of RR 36. 

In these submittals, the applicant required inspection schedules of the weld overlaid nozzles. 

For example, RR 36 requires that overlaid nozzles be examined during the first or second 

refueling outage following weld overlay installation. Also, RR 36 requires fatigue crack growth 

calculations to be updated periodically to meet certain ASME requirements to ensure structural 

integrity of the subject nozzles. 

Because the weld overlay has been installed on the hot leg surge and shutdown cooling nozzles 

to mitigate potential PWSCC and RR 36 has provided specific periodic inspection requirements, 

the staff finds that the structural integrity of the subject nozzles will be maintained adequately. 

For this case, the staff finds that the fatigue crack growth analyses for the subject nozzles are 

not a TLAA because the fatigue crack growth analyses are performed for every inspection 

interval (i.e. 10 years). The staff’s concern in RAI 4.3.2.7-9 is resolved. 
Time-Limited Aging Analyses 

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Disposition: Aging Management per 10 CFR 54.21(c)(1)(iii). LRA Section 4.3.2.7 states that 

the enhanced metal fatigue AMP will continue to confirm that usage factors and waivers are not 

time-dependent or that re-evaluation or other corrective action is initiated if an action limit is 

reached. By letter dated February 14, 2010, the staff issued RAI 4.3.2.7-10. This RAI asked 

that the applicant specify the exact piping components and systems that will be monitored under 

the enhanced metal fatigue AMP in the context of Section 4.3.2.7 and discuss how often the 

actions will be performed under the enhanced metal fatigue AMP (e.g., monitoring the transient 

cycles and reviewing the records). LRA Section 4.3.1 discusses that a FatiguePro® computer 

software program is used to monitor the transient cycles; however, it is not clear how often the 

applicant performs the monitoring and when corrective actions are taken. 

The applicant's March 1, 2010, response to RAI 4.3.2.7-10 stated that the piping components 

that will be monitored are listed in LRA Table 4.3-4. LRA Section 4.3.1.5 states that the scope 

of the bounding set of monitored locations is sufficient to ensure that fatigue in any other 

locations of concern, not included in the set, is within the same system and subject to the same 

transients, or within a system affected by the same transients. LRA Section 4.3.1.5 states that 

the current metal fatigue AMP requires this evaluation at least once per fuel cycle. This 

schedule will apply to the enhanced metal fatigue AMP for the period of extended operation. 

The staff finds that the applicant has clarified that the piping components in LRA Table 4.3-4 will 

be monitored by the enhanced Metal Fatigue Program at least once per fuel cycle. LRA 

Table 4.3-4 provides a summary of fatigue usages from the Class 1 piping analyses and 

methods of management by the metal fatigue of RCP boundary program. The staff finds that 

the Class 1 piping covered in LRA Table 4.3-4 is sufficiently comprehensive, and the monitoring 

frequency of every fuel cycle is adequate. The staff’s concern in RAI 4.3.2.7-10 is resolved. 

The staff finds that the structural integrity of the Class 1 piping will be maintained during the 

period of extended operation based on the enhanced metal fatigue AMP. 

4.3.2.7.3 Updated Final Safety Analysis Report Supplement 

The applicant supplied a UFSAR supplement summary description of its TLAA of the ASME 

Code Section III, Class 1 Piping and Piping Nozzles in LRA Section A.3.2.1.7. Based on its 

review of the UFSAR supplement in LRA Section A.3.2.1.7, the staff concludes that the 

summary description of the applicant’s actions to address the TLAA for the ASME Code 

Section III, Class 1 Piping and Piping Nozzles is adequate. 

4.3.2.7.4 Conclusion 

On the basis of its review, the staff concludes that, pursuant to 10 CFR 54.21(c)(1)(iii), the 

applicant has demonstrated that the effects of aging on the intended function of the ASME Code 

Section III, Class 1 Piping and Piping Nozzles will be adequately managed for the period of 

extended operation. The UFSAR supplement contains an appropriate summary description of 

the TLAA evaluation of the ASME Code Section III, Class 1 Piping and Piping Nozzles, as 

required by 10 CFR 54.21(d). 

4.3.2.8 Absence of Supplemental Fatigue Analysis Time-Limited Aging Analyses in 

Response to Bulletin 88-08 for Intermittent Thermal Cycles due to 

Thermal-Cycle-Driven Interface Valve Leaks and Similar Cyclic Phenomena 

The staff reviewed LRA Section 4.3.2.8 to verify that the supplemental fatigue analysis 

time-limiting aging analyses in response to Bulletin 88-08 for intermittent thermal cycles due to 

thermal-cycle-driven interface valve leaks and similar cyclic phenomena are not TLAAs. The 

staff’s evaluation is found in SER Section 4.1.3.1.5. 
Time-Limited Aging Analyses 

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4.3.2.9 Bulletin 88-11 Revised Fatigue Analysis of the Pressurizer Surge Line for 

Thermal Cycling and Stratification 

4.3.2.9.1 Summary of Technical Information in the Application 

LRA Section 4.3.2.9 states that the pressurizer surge lines are designed to the ASME Code 

Section III, Subsection NB, 1977 edition with addenda through summer 1979. The surge line 

design was reanalyzed in 1991 through the CEOG in response to concerns expressed in 

Bulletin 88-11, “Pressurizer Surge Line Thermal Stratification.” The purpose of Bulletin 88-11 

was to request that licensees establish and implement a program to confirm pressurizer surge 

line integrity in view of the occurrence of thermal stratification and to require licensees to inform 

the staff of the actions taken to resolve this issue. The applicant dispositions this TLAA in 

accordance with 10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended functions of 

the pressurizer surge line will be adequately managed for the period of extended operation. 

4.3.2.9.2 Staff Evaluation 

The staff reviewed LRA Section 4.3.2.9 to verify, per 10 54.21(c)(1)(iii), that the effects of aging 

on the intended function(s) of the pressurizer surge line will be adequately managed for the 

period of extended operation. 

Effects of Thermal Stratification on the Surge Line Piping Fatigue Analysis. As a result of 

thermal stratification occurring in pressurizer surge lines in the 1980s, the staff published 

Bulletin 88-11 to alert PWR licensees about the issue and to require licensees to mitigate 

thermal stratification and monitor potential degradation. Bulletin 88-11 requires PWR licensees 

to visually inspect the surge line, demonstrate that the surge line meets applicable design 

codes, and update stress and fatigue stress analyses of the surge line. 

The applicant stated that CE performed a fatigue evaluation of surge lines in CEOG plants with 

thermal stratification loading. The analysis assumed the design basis number of 500 heatup 

transients. The CEOG analysis is based on a limiting set of thermal stratification transients 

defined from data collected from several CE units, not including PVNGS, but used the PVNGS 

surge line for the limiting analysis because its geometry produced the most-limiting stresses. 

Insurge-outsurge and thermal stratification effects doubled the 40-year CUF of the original 

analysis of record at the limiting location in the surge line elbow at the pressurizer. 

The applicant reported that the elastic analysis produced a CUF of 1.65 in the surge line elbow. 

To decrease the CUF below the ASME fatigue limit of 1.0, CE performed a plastic analysis, 

resulting in a limiting CUF of 0.937 in the surge line elbow. This CEOG limiting-case analysis is 

conservative because it did not include any credit for mitigating actions, or the actual severity of 

transients, experienced during operation. A reanalysis for more realistic transients should, 

therefore, be able to demonstrate considerable margin. PVNGS collected and reduced their 

data independently from the other plants; hence, there is no specific thermal transient 

information from PVNGS within the CEOG report. However, in the absence of any analysis 

more specific to PVNGS, the applicant confirmed this bounding analysis as the fatigue analysis 

of record for this component. 

By letter dated February 14, 2010, the staff issued RAI 4.3.2.9-1, asking the applicant to 

describe the analyses in detail including methodology, input, acceptance criteria, and results 

and to clarify whether the CUF analysis is based on a 40-year period or 60-year period. LRA 

Section 4.3.2.9 states that the Metal Fatigue of Reactor Coolant Pressure Boundary Aging 

Management Program will be used to monitor the surge line. The staff asked the applicant to 

discuss whether the metal fatigue AMP will initiate actions based on the elastic analysis result 

(CUF of 1.65) or plastic analysis result (CUF of 0.937). 

The applicant's March 1, 2010, response to RAI 4.3.2.9-1 stated that calculation 13-MC-ZZ-595 

performed fatigue evaluations for the pressurizer surge line, including the Bulletin 88-11 
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additional thermal cycling and stratification effects. This analysis incorporated results of CEOG 

calculation MISC-ME-C-115 and report CEN-387-P. 

The applicant further stated that these analyses found that the highest CUF (i.e., 1.65) in the 

surge line is in the elbow below the pressurizer. The 1.65 CUF is a result of a preliminary 

shakedown analysis per the ASME Code Section III, NB-3228.4. As stated in the scope of 

calculation MISC-ME-C-115, “[t]he fatigue evaluation program developed to analyze the 

shakedown analysis results is used only to rank each point in the elbow. The output from this 

program in no way represents the fatigue usage for the actual transients listed....” The same 

analysis re-analyzed this highest-ranking 1.65 CUF location and calculated an actual CUF 

of 0.778. As stated in the conclusion of calculation MISC-ME-C-115, “[u]sing the transients 

analyzed in the shakedown analysis as a method to rank locations in the limiting surge line 

elbow, the location of greatest usage is analyzed for its actual usage.... The point of highest 

actual usage is U = 0.778.” 

In response to Bulletin 88-11, CEOG performed the evaluation reported in CEN-387-P on 

pressurizer surge line thermal stratification. CEN-387-P reported a plant-specific analysis CUF 

of 0.937 at the surge line elbow location, also using the methods of NB-3228.4. The 

acceptance criterion is a calculated 40-year CUF that is less than or equal to 1.0. This 

plant-specific analysis is the analysis of record for this component at PVNGS. CEN-387-P 

included effects of insurge-outsurge and thermal stratification at the limiting surge line elbow 

location. 

The applicant stated that if CC were used as the fatigue management method, the metal fatigue 

AMP would, therefore, initiate actions based on the analysis of record result (CUF of 0.937). 

However, this is a sample location based on NUREG/CR-6260, “Application of 

NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear Power Plant Components,” and 

when a conservative estimate of the multiplier for effects of the reactor coolant environment is 

used, the calculated CUF becomes several times the code acceptance criterion of 1.0. The 

applicant stated that fatigue in this location will, therefore, be managed by SBF monitoring, and 

the action limits for this location will, therefore, depend on calculated actual fatigue usage, not 

on a 40-year (or 60-year) value determined by the analysis of record. LRA Section 4.3.4 

provides additional information on the NUREG/CR-6260 sample locations, and LRA 

Table 4.3-4, item 24, provides information for monitoring of this location. 

The applicant stated that LRA Section 4.3.2.9 misidentified the 1.65 CUF as the result of an 

elastic analysis. By letter dated March 1, 2010, the applicant submitted Amendment 10, which 

revised the sentence to read, “[a] preliminary shakedown analysis produced...” The related 

paragraphs in LRA Section 4.3.4 also misidentify the 1.65 CUF as the result of an elastic 

analysis and include an unnecessary sentence. In LRA Amendment 10, the applicant revised 

the last paragraph on LRA page 4.3-64 as follows: 

Pressurizer Surge Line (Hot Leg) Elbow (Location 4): Combustion Engineering 

(CE) performed a fatigue evaluation of surge lines in various CE Owners Group 

(CEOG) plants, with thermal stratification loading. The analysis assumed the 

design basis number of 500 heatup transients. A preliminary shakedown 

analysis produced a cumulative usage factor of 1.65 in the comparable (and 

more limiting) surge line pressurizer elbow. To decrease the CUF below the 

ASME fatigue limit of 1.0, CE then performed a plastic analysis resulting in a 

limiting CUF of 0.937 in the pressurizer elbow. APS confirmed this bounding 

analysis as the fatigue analysis of record for this component at PVNGS. See 

Section 4.3.2.9. 

To evaluate effects of the reactor coolant environment, APS re-evaluated the 

CUF in the pressurizer surge line hot leg elbow using design basis transient 
Time-Limited Aging Analyses 

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cycles and ASME Subsection NB-3200 6-component stress tensors. The 

simplified elastic-plastic analysis produced a CUF of 1.9396, which is above the 

ASME code allowable fatigue limit of 1.0. The CE plastic analysis described in 

Section 4.3.2.9 that calculated a CUF of 0.937 is more precise than the APS 

reevaluation; however, the APS hot leg elbow reevaluation will.... 

The staff finds that the applicant has clarified the CUF calculation and the CUF results of the 

pressurizer surge line. Per NRC Bullet 88-11, the applicant has considered the thermal cycles 

and stratification in CUF calculation of the surge line. The metal fatigue program will monitor 

the CUF using the SBF monitoring method. The staff finds that the structural integrity of the 

pressurizer surge line will be adequately monitored during the period of extended operation. 

The staff also finds that the applicant satisfies the TLAA requirements of 10 CFR 54.21(c)(1)(iii) 

because the metal fatigue program will be used to monitor the CUF of the pressurizer surge 

line. The staff’s concern in RAI 4.3.2.9-1 is resolved. 

Effect of Bulletin 88-11 on Risk-Informed Inservice Inspection Program. PVNGS augmented its 

ASME Code Section XI, ISI Program to include inspections of the surge line elbow, which were 

done to address NRC Bulletin 88-11 concerns. PVNGS subsequently proposed the alternative 

Risk-Informed ISI (RI-ISI) in RR-32. The RI-ISI application is based on the EPRI RI- ISI 

Program, which explicitly considered NRC Bulletin 88-11 concerns in its application. Therefore, 

the PVNGS RI-ISI Program addresses the NRC Bulletin 88-11 concerns. 

By letter dated February 14, 2010, the staff issued RAI 4.3.2.9-2, asking the applicant to confirm 

that the surge line elbow is a component that requires a nondestructive examination to be 

performed under the ISI program. This RAI also asks that the applicant, discuss how often the 

surge line elbow will be inspected in each of the 10-year ISI intervals through the sixth interval 

and discuss the nondestructive examination method that will be used for each inspection. 

The applicant's March 1, 2010, response to RAI 4.3.2.9-2 stated that the surge line elbow is 

subject to the ASME Code Section XI, ISI Program. Subsequent to the initial LRA submittal, no 

RR has been filed to permit use of a RI-ISI program for the current, third inspection interval. 

The applicant revised LRA Section 4.3.2.9 as follows: 

PVNGS augmented its ASME Section XI, ISI program to include inspections of 

the surge line elbow, which were performed to address NRC Bulletin 88-11 

concerns. PVNGS subsequently proposed the alternative RI-ISI in RR 32 for the 

third period of the second ISI interval. The RI-ISI application was based on the 

EPRI RI-ISI program, which explicitly considered NRC Bulletin 88-11 concerns in 

its application. The NRC Bulletin 88-11 concerns were therefore addressed by 

the PVNGS RI-ISI program. However the program was approved only for the 

third period of the second ISI interval, and no relief request has been filed for the 

current, third interval. 

The applicant stated that the ASME Code Section XI requires that the surge line elbow in each 

of the PVNGS units be visually (VT-2) examined each refueling outage. The ISI Program is 

revised to the requirements of 10 CFR 50.55a for each inspection interval. 

The staff finds that the applicant will follow the ASME Code Section XI to inspect the pressurizer 

surge line elbow that has the highest CUF. The applicant will visually inspect the elbow each 

refueling outage. The staff finds that the structural integrity of the pressurizer surge line elbow 

will be adequately maintained during the period of extended operation. The staff finds 

acceptable that the implementation of the RI-ISI program is limited to only the third period of the 

second ISI interval. The staff’s concern described in RAI 4.3.2.9-2 is resolved. 

Effects of Power Uprate and Steam Generator Replacement on the Surge Line Piping Fatigue 

Analysis. The applicant stated that the evaluation of the power uprate and SG replacement 
Time-Limited Aging Analyses 

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found that the resulting changes in temperature ranges have no effect on the surge line fatigue 

analysis. 

The applicant stated that the surge line elbow will be subject to SBF monitoring under the 

enhanced Metal Fatigue of Reactor Coolant Pressure Boundary Program. The program will 

maintain a record of the CUF. This record will be reviewed and evaluated at intervals specified 

by the program, at a frequency sufficient to ensure that appropriate corrective action will be 

initiated if an action limit is reached. Action limits will be established to permit completion of 

corrective actions before the code limit is exceeded. The effects of fatigue in the Class 1 surge 

line will thereby be managed for the period of extended operation, in accordance with 

10 CFR 54.21(c)(1)(iii). 

In RAI 4.3.2.9-3, the staff asked the applicant to discuss how often they will review and evaluate 

the record of the worst case CUFs. The applicant's March 1, 2010, response to RAI 4.3.2.9-3 

stated that as stated in LRA Section 4.3.1.5, page 4.3-23, “The PVNGS fatigue management 

program currently ... requires this evaluation at least once per fuel cycle.” This schedule will 

apply to the enhanced metal fatigue AMP for the period of extended operation. The staff finds 

that the monitoring frequency of once per fuel cycle for the CUF of the surge line elbow is 

adequate to ensure its structural integrity because it will ensure the applicant takes corrective 

actions before exceeding the design limit. The staff’s concern described in RAI 4.3.2.9-3 is 

resolved. 

4.3.2.9.3 Updated Final Safety Analysis Report Supplement 

The applicant provided a UFSAR supplement summary description of its TLAA of the 

pressurizer surge line for thermal cycling and stratification in LRA Section A3.2.1.8. On the 

basis of its review of the UFSAR supplement in LRA Section A3.2.1.8, the staff concludes that 

the summary description of the applicant’s actions to address the TLAA for pressurizer surge 

line for thermal cycling and stratification is adequate. 

4.3.2.9.4 Conclusion 

On the basis of its review, the staff concludes that, pursuant to 10 CFR 54.21(c)(1)(iii), the 

applicant has demonstrated that the effects of aging on the intended function of the pressurizer 

surge line for thermal cycling and stratification will be adequately managed for the period of 

extended operation. The UFSAR supplement contains an appropriate summary description of 

the TLAA evaluation of the pressurizer surge line for thermal cycling and stratification, as 

required by 10 CFR 54.21(d). 

4.3.2.10 Class 1 Fatigue Analyses of Class 2 Regenerative and Letdown Heat 

Exchangers 

4.3.2.10.1 Summary of Technical Information in the Application 

LRA Section 4.3.2.10 and Amendment 16 dated May 27, 2010, summarize the evaluation of the 

ASME Code Class 1 fatigue analyses of ASME Code Class 2 regenerative and letdown heat 

exchangers. The applicant stated that the specifications of those exchangers require an ASME 

Code Class 1, NB-3222 analysis, including a fatigue evaluation for a specified set of events, 

each for a specified number of occurrences, for a 40-year design life. The applicant dispositions 

this TLAA in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended 

functions of the ASME Code Class 2 regenerative and letdown heat exchangers will be 

adequately managed for the period of extended operation. 

4.3.2.10.2 Staff Evaluation 

The staff reviewed LRA Section 4.3.2.10 and Amendment 16 to verify pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended functions will be adequately 

managed for the period of extended operation. 
Time-Limited Aging Analyses 

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LRA Amendment 16 revised Section 4.3.2.10 and stated that for both types of heat exchangers, 

the fatigue analyses were performed with transients specified in the CE general specification for 

System 80 plants. The staff noted that the applicant did not identify which transients were 

evaluated in the System 80 CUF calculations for these heat exchangers. Furthermore, the LRA 

stated that the fatigue effects of the heat exchangers are bounded by the fatigue of the charging 

nozzle. However, the current design basis CUF values for the heat exchangers were not 

provided. By letter dated July 21, 2010 the staff issued RAI 4.3-16 requesting the applicant to 

clarify the current design basis CUF values for the regenerative heat exchangers and letdown 

heat exchangers; identify the transients that were evaluated in the CUF calculations of these 

heat exchangers; and identify the design basis limits for the transients analyzed in these 

calculations. This was previously identified as part of Open Item 4.3-1. 

The applicant's response dated August 12, 2010, provided the design basis CUFs for the 

components and identified the charging nozzle as the limiting location. The response also 

explained the design basis transients analyzed and associated limits for the transients. During 

the review of the analyses of record for the heat exchangers, the applicant noted that the 

analysis assumed a higher number of cycles for significant design transients and a lower 

number of cycles for less significant transients than those stated in the UFSAR for several 

transients. The applicant stated that none of the transient limits have been challenged by 

current operating history. The applicant also stated that the inconsistency between the transient 

assumptions in the UFSAR and those in the analyses is in the corrective action process for 

evaluation and resolution (tracking number (CRAI) 3494095). 

Based on its review, the staff finds the applicant’s response to RAI 4.3-16 acceptable because, 

(1) the CUF values confirm that the charge nozzle is the bounding location; (2) the number of 

events in the design basis specifications are consistent with or greater than the number of 

transients that will be used as CC action limits in the enhanced Metal Fatigue Program which 

ensures that the CC action limits are appropriate for the heat exchangers; and (3) the applicant 

identified and initiated an action to track and resolve the inconsistency between the transient 

assumptions in the UFSAR and those in the analysis. The staff’s concern described in 

RAI 4.3-16 is resolved and this part of Open Item 4.3-1 is closed. 

Based on its review, the staff finds the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended functions of the Class 2 

regenerative and letdown heat exchangers will be adequately managed for the period of 

extended operation because the action limits of the enhanced Metal Fatigue Program will be 

established to permit completion of corrective actions before the design basis number of events 

is exceeded. Thus, the fatigue usage factor will not exceed the design limit of 1.0 during the 

period of extended operation. 

4.3.2.10.3 Updated Final Safety Analysis Report Supplement 

LRA Section A3.2.1.9 provides the UFSAR supplement summarizing the evaluation of the 

Class 1 fatigue analyses for Class 2 regenerative and letdown heat exchangers. Based on its 

review of the UFSAR supplement, the staff concludes that the applicant provided an adequate 

summary description of its actions to address the TLAA for the Class 2 regenerative and 

letdown heat exchangers as required by 10 CFR 54.21(d). 

4.3.2.10.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended functions of the Class 2 

regenerative and letdown heat exchangers will be adequately managed for the period of 

extended operation. The staff also concludes that the UFSAR supplement contains an 

appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d). 
Time-Limited Aging Analyses 

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4.3.2.11 Class 1 Fatigue Analyses of Class 2 High-Pressure Safety Injection and 

Low-Pressure Safety Injection Safeguard Pumps for Design Thermal Cycles 

4.3.2.11.1 Summary of Technical Information in the Application 

LRA Section 4.3.2.11 and Amendment 16, dated May 27, 2010, summarize the evaluation of 

the Class 1 fatigue analyses of Class 2 HPSI and LPSI pumps. The applicant stated that the 

design of the Class 2 pumps includes no fatigue analysis. The applicant dispositions this TLAA 

per 10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended functions of the Class 2 

HPSI and LPSI pumps will be adequately managed for the period of extended operation. 

4.3.2.11.2 Staff Evaluation 

The staff reviewed LRA Section 4.3.2.11 and Amendment 16, to verify per 

10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended functions of the Class 2 HPSI 

and LPSI pumps will be adequately managed for the period of extended operation. 

The applicant stated that the design of the Class 2 pumps does not include a fatigue analysis. 

However, UFSAR Section 3.9.3.5.3.3 describes the design for a stated number of thermal 

transient cycles. The applicant stated that the structural integrity and operability analyses for 

both pumps cite the Class 1 methods of ASME Code Section III, Article NB-3222.4 when 

addressing these thermal transients. 

The staff noted that both the HPSI and LPSI pumps are designed for the injection initiation 

transient temperature change of 40 degrees to 300 degrees F. The applicant stated that using 

the design temperature of the transient, ASME Code Section III, Appendix I, Figure I-9.2 allows 

approximately 550 operating cycles and 23,500 operating cycles for the HPSI and LPSI pumps, 

respectively. Since the design of the pumps assumed 10 cycles, the applicant concluded that 

there is sufficient margin to support the period of extended operation. 

The staff noted that the LPSI pumps are designed for the shutdown cooling initiation transient 

temperature change of 70 degrees to 350 degrees F. The applicant stated that by using the 

design temperature of the transient, approximately 18,000 operating cycles are allowed for the 

LPSI pump. Since the design of the pump assumed 500 cycles, the applicant concluded that 

there is sufficient margin to support the period of extended operation. 

Based on its review, the staff finds the applicant has demonstrated, pursuant to 10 CFR 

54.21(c)(1)(iii), that the analyses for the effects of aging on the intended functions of the Class 2 

HPCI and LPCI pumps remain valid for the period of extended operation because the enhanced 

Metal Fatigue Program will track events to ensure that appropriate corrective action will be 

initiated and completed before the design basis number of events is exceeded such that the 

fatigue usage factor will not exceed the design limit of 1.0. 

4.3.2.11.3 Updated Final Safety Analysis Report Supplement 

LRA Section A3.2.1.10 provides the UFSAR supplement summarizing the evaluation of the 

Class 1 fatigue analyses for the Class 2 HPSI and LPSI pumps. Based on its review of the 

UFSAR supplement in the LRA and UFSAR Section 3.9.3.5.3.3, the staff concludes that the 

applicant provided an adequate summary description of its actions to address the TLAA for the 

Class 2 HPSI and LPSI pumps as required by 10 CFR 54.21(d) 

4.3.2.11.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended functions of the Class 2 HPSI 

and LPSI pumps will be adequately managed for the period of extended operation. The staff 

also concludes that the UFSAR supplement contains an appropriate summary description of the 

TLAA evaluation, as required by 10 CFR 54.21(d) 
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4.3.2.12 Class 1 Analysis of Class 2 Main Steam Safety Valves 

4.3.2.12.1 Summary of Technical Information in the Application 

LRA Section 4.3.2.12 and Amendment 16 dated May 27, 2010, summarize the evaluation of the 

Class 1 analysis of Class 2 main steam safety valves (MSSVs). The applicant stated that the 

design of the Class 2 MSSVs includes a Class 1 fatigue analysis to ASME Code Section III, 

Article NB-3550, “Cyclic Loads for Valves.” The applicant stated that since the cyclic design 

basis is described in the UFSAR, the fatigue analysis is, therefore, a TLAA. The applicant 

dispositions this TLAA in accordance with 10 CFR 54.21(c)(1)(i), that the analyses remain valid 

for the period of extended operation. 

4.3.2.12.2 Staff Evaluation 

The staff reviewed LRA Section 4.3.2.12 and Amendment 16, to verify pursuant to 

10 CFR 54.21(c)(1)(i), that the analyses remains valid during the period of extended operation. 

The applicant stated that the design of the Class 2 MSSVs includes a Class 1 fatigue analysis to 

ASME Code Section III, Subsubarticle NB-3550, “Cyclic Loads for Valves.” The applicant 

provided the cyclic design basis as described in the UFSAR Section 5.2.2.4.3.2. The applicant 

further provided usage factors at two critical areas of the valves, the inlet crotch and the disc. 

The two usage factors are less than one-ninth of the design limit of 1.0. Based on its review, 

the staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that the 

Class 1 fatigue analyses for the Class 2 MSSVs remains valid during the period of extended 

operation because the valves are suitable to operate adequately for at least nine times the 

original 40-year design lifetime. 

4.3.2.12.3 Updated Final Safety Analysis Report Supplement 

LRA Section A3.2.1.11 provides the UFSAR supplement summarizing the evaluation of Class 1 

analysis of Class 2 MSSVs. Based on its review of the UFSAR supplement, the staff concludes 

that the applicant provided an adequate summary description of its actions to address the TLAA 

for the Class 2 MSSVs as required by 10 CFR 54.21(d). 

4.3.2.12.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(i), that the Class 1 fatigue analyses for the Class 2 MSSVs remain valid 

during the period of extended operation. The staff also concludes that the UFSAR supplement 

contains an appropriate summary description of the TLAA evaluation, as required by 

10 CFR 54.21(d). 

4.3.2.13 Absence of Time-Limited Aging Analyses in Evaluations of Effects of Vibration 

on the Unit 1, Train A Shutdown Cooling System Suction Line Fatigue Analysis 

and of Vibration Limits Established for its Isolation Valve Actuator 

The staff reviewed LRA Section 4.3.2.13 to verify that the evaluations of the effects of vibration 

on the Unit 1, Train A SCS system suction line fatigue analysis and vibration limits established 

for its isolation valve actuator are not TLAAs. The staff’s evaluation is found in SER 

Section 4.1.3.1.6. 

4.3.2.14 High Energy Line Break Postulation Based on Fatigue Cumulative Usage Factor 

4.3.2.14.1 Summary of Technical Information in the Application 

LRA Section 4.3.2.14 describes the applicant’s TLAA for high energy line break (HELB) 

postulation. Break locations are determined in accordance with Standard Review Plan for 

License Renewal (SRP-LR) Branch Technical Position (BTP) MEB 3-1. Breaks in piping with 

ASME Code Section III, Class 1 fatigue analyses are identified based on the CUF values (with 
Time-Limited Aging Analyses 

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the stated exception of the reactor coolant system primary loops), and these determinations, 

therefore, are TLAAs. The RCS primary loop piping is eliminated from consideration by the leak 

before break (LBB) analyses. The applicant dispositions this TLAA in accordance with 

10 CFR 54.21(c)(1)(iii), that the effects of aging on the HELB postulation will be adequately 

managed for the period of extended operation. 

4.3.2.14.2 Staff Evaluation 

The staff reviewed LRA Section 4.3.2.14, to verify, pursuant to 10 CFR 54.21(c)(1)(iii), that the 

effects of aging on the HELB postulation will be adequately managed for the period of extended 

operation. 

The LRA states that breaks in piping with ASME Code Class 1 fatigue analyses are identified 

based on CUF (with the exception of the RCS primary loops, as stated above, which are 

eliminated by the LBB analyses). Break location postulations, which depend on usage factor, 

will remain valid as long as the calculated usage factors are not exceeded. The applicant also 

stated that the enhanced Metal Fatigue Program will ensure that appropriate reevaluation or 

other corrective actions are initiated if an action limit is reached. Action limits for the HELB 

design basis permit completion of corrective actions before the calculated design basis usage 

factors in Class 1 lines (outside the reactor coolant system primary loops) are exceeded. The 

staff determined that the applicant appropriately accounted for the HELB postulations because 

the break locations remain valid as long as the cumulative usage factors are less than 0.1. 

Based on its review, the staff finds the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of aging on the HELB postulation will be adequately 

managed for the period of extended operation because the enhanced Metal Fatigue Program 

will ensure that appropriate corrective actions will be initiated if an action limit is reached. Action 

limits for the HELB design basis will be established to permit completion of corrective actions 

before the calculated design basis usage factors in Class 1 lines (outside the reactor coolant 

system primary loops) is exceeded. 

4.3.2.14.3 Updated Final Safety Analysis Report Supplement 

LRA Section A3.2.1.12 provides the UFSAR supplement summary description for the HELB 

postulation of TLAAs that were evaluated in LRA Section 4.3.2.14. Based on its review of the 

UFSAR supplement, the staff concludes that the applicant provided an adequate summary 

description of its actions to address the HELB postulation. 

4.3.2.14.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of aging on the HELB postulation will be adequately 

managed for the period of extended operation. The staff also concludes that the UFSAR 

supplement contains an appropriate summary description of the TLAA evaluation, as required 

by 10 CFR 54.21(d). 

4.3.2.15 Absence of Time-Limited Aging Analyses in Fatigue Crack Growth 

Assessments and Fracture Mechanics Stability Analyses for the 

Leak-Before-Break Elimination of Dynamic Effects of Primary Loop Piping 

Failures 

The staff reviewed LRA Section 4.3.2.15 to verify that the LBB (elimination of dynamic effects of 

primary loop piping failures) fatigue crack growth and fracture mechanics stability analyses are 

not TLAAs. The staff’s evaluation is found in SER Section 4.1.3.1.4. 
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4.3.3 Fatigue and Cycle-Based Time-Limited Aging Analyses of American Society of 

Mechanical Engineers III, Subsection NG, Reactor Pressure Vessel Internals 

4.3.3.1 Summary of Technical Information in the License Renewal Application 

LRA Section 4.3.3 summarizes the evaluation of the CUF analyses that comprise the “Fatigue 

and Cycle-Based TLAAs of ASME III Subsection NG Reactor Pressure Vessel Internals,” for the 

period of extended operation. These TLAAs are based on the CUF analyses in the applicant’s 

current design for the applicant reactor vessel internal (RVI) components. The applicant 

dispositions these TLAAs per 10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended 

functions of the reactor vessel internals will be adequately managed for the period of extended 

operation. 

4.3.3.2 Staff Evaluation 

On May 27, 2010, the applicant submitted LRA Amendment 16. In this LRA Amendment, the 

applicant submitted its conforming changes to LRA Section 4.3.3 to address staff concerns that 

were discussed with the applicant in a public meeting on May 6, 2010. 

In LRA Amendment 16, the applicant amended Section 4.3.3 to note that some of the reactor 

vessel internal (RVI) components were designed to the 1974 Edition of the ASME Code 

Section III, Subsection NG, or to more recent endorsed versions of the ASME Code Section III. 

LRA Section 4.3.3 identifies that the design codes require CUF calculations for these ASME 

Code Section III, Subsection NG components and that these analyses are TLAAs. The staff 

noted that the Materials Reliability Program Report (MRP-227) identifies the following CE RVI 

components as ASME Code Class 1 components: 

 Guide lugs and guide lug inserts and bolts 

 Fuel alignment pins 

 RVI components in the upper flange assembly 

The staff noted that the assessment in LRA Section 4.3.3 does not identify which of the RVI 

components were designed to these ASME Code requirements and were required to have a 

CUF calculation. By letter dated July 21, 2010, the staff issued RAI 4.3-17 asking that the 

applicant identify which RVI components are designed to Subsection NG requirements and are 

required to have a CUF design calculation. The staff also asked that the applicant identify the 

design basis CUFs for those components and design basis limits for those transients analyzed. 

The staff also requested the applicant justify the use of cycle-based monitoring if the existing 

design basis CUF value for any RVI component with a high CUF value (e.g. greater than or 

equal to 0.9). This was previously identified as part of Open Item 4.3-1. 

The applicant's response dated August 12, 2010, provided a list of the RVI components as 

described in UFSAR Section 3.9.5. In addition to tabulating the fatigue usage factors of the 

components of the RVI, the applicant also provided the design basis transients and associated 

limiting number of events. The applicant stated that since the RVI fatigue usage factors depend 

on the effects of transient events, the increase in operating life to 60 years will not have a 

significant effect on the fatigue usage factors if the numbers of design transient cycles remain 

within the numbers assumed by the original 40-year analysis. The applicant explained that 

monitoring the transient counts to remain less than their 40-year value will ensure that the CUF 

remain less than design basis CUFs. Furthermore, since any design basis CUF less than 1.0 is 

an acceptable result, the applicant stated that no additional action is required to be taken for 

components with CUFs close to, but less than 1.0. 

Based on its review, the staff finds the applicant’s response to RAI 4.3-17 acceptable because 

the applicant identified the ASME Code Section III, Subsection NG RVI components and 

clarified the design basis CUFs and transients for those components. Further, the applicant will 
Time-Limited Aging Analyses 

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use CC in its enhanced Metal Fatigue Program to track these transients to ensure that when 

action limits are reached, that corrective actions are taken to maintain fatigue usage below the 

design limit of 1.0. The staff’s concern described in RAI 4.3-17 is resolved and this part of Open 

Item 4.3-1 is closed. 

The applicant stated that the fatigue usage factors for the RVI components do not depend on 

flow-induced vibration or other high-cycle effects that are time-dependent at steady-state 

conditions. The staff reviewed UFSAR Section 3.9.2.5 and noted there is a discussion 

regarding flow-induced vibrations and confirmed that there are no TLAAs associated with the 

evaluation of flow-induced vibration or other high-cycle effects. The staff further noted that for 

those RVI components that have a CUF analysis, the usage factor is below the design limit 

of 1.0. 

Based on its review, the staff finds the applicant has demonstrated pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of aging will be adequately managed for the period of 

extended operation because the applicant will use its enhanced Metal Fatigue Program to 

monitor the number of transient cycles to ensure that corrective actions are taken if an action 

limit is reached, to ensure that the assumption made in the design calculations remain valid. 

4.3.3.3 Updated Final Safety Analysis Report Supplement 

LRA Section A3.2.2 provides the UFSAR supplement summarizing the TLAA for the ASME 

Code Section III, Subsection NG RVI components. The staff reviewed LRA Section A3.2.2 

against the acceptance criteria in SRP-LR Sections 4.3.2.3 and 4.3.3.3. Based on its review, 

the UFSAR supplement is consistent with SRP-LR Sections 4.3.2.3 and 4.3.3.3. The staff 

determines that the applicant provided an adequate summary description of its actions to 

address the ASME Code Section III, Subsection NG RVI components, as required by 

10 CFR 54.21(d). 

4.3.3.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended 

functions of the RVI components will be adequately managed for the period of extended 

operation. The staff also concludes that the UFSAR supplement contains an appropriate 

summary description of the TLAA evaluation, as required by 10 CFR 54.21(d). 

4.3.4 Effects of the Reactor Coolant System Environment on Fatigue Life of Piping and 

Components (Generic Safety Issue 190) 

4.3.4.1 Summary of Technical Information in the License Renewal Application 

LRA Section 4.3.4 summarizes the evaluation of the CUF analyses that comprise the “Effects of 

the Reactor Coolant System Environment on Fatigue Life of Piping and Components (Generic 

Safety Issue 190),” for the period of extended operation. These EAF analyses are not 

mandated by applicant’s CLB for ASME Code Class 1 components. Instead, the applicant 

identifies that, although these types of analyses are not part of the existing design basis, they 

were included in order to conform with acceptance criteria and review procedure 

recommendations in the SRP-LR, Sections 4.3.2.2 and 4.3.3.2, respectively. 

The applicant stated that the EAF analyses for its ASME Code Class 1 components were done 

in order to resolve the concerns identified in GSI-190 and in accordance with the staff’s 

recommendations in NUREG/CR-6260 “Application of NUREG/CR-5999 Interim Fatigue Curves 

to Selected Nuclear Power Plant Components.” The applicant stated that NUREG/CR-6260 

recommended that the following CE component locations be analyzed for EAF: 

 Reactor vessel (RV) shell and lower head 
Time-Limited Aging Analyses 

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 RV inlet nozzles 

 RV outlet nozzles 

 Surge line 

 Charging system nozzle 

 Safety injection system nozzle 

 Shutdown cooling line 

In LRA Table 4.3-11, the applicant notes that the following component locations were selected 

as the limiting Class 1 locations that correspond to the EAF assessment locations 

recommended for CE facilities in NUREG/CR-6260: 

 RV shell and lower head 

 RV inlet nozzle 

 RV outlet nozzle 

 Surge line (hot leg) elbow 

 Charging system nozzle (safe end location) 

 Safety injection nozzle (forging knuckle) 

 Safety injection nozzle (safe end) 

 Shutdown cooling line (long radius elbow) 

 Pressurizer heater locations (not identified as locations in NUREG/CR-6260) 

LRA Table 4.3-11 also includes the applicant’s EAF factors (Fen factors) that it used to adjust the 

CUF calculations of these components and the EAF usage factor results (Fen adjusted CUF 

values) that the applicant had calculated for these components at the end of the period of 

extended operation. 

The applicant stated that the EAF analyses for these components are projected to the end of 

the period of extended operation in accordance with the criterion in 10 CFR 54.21(c)(1)(ii). 

Otherwise, the affect of environmentally-assisted, fatigue-induced cracking on the intended 

pressure boundary functions of the components will be managed for the period of extended 

operation in accordance with the TLAA acceptance criterion in 10 CFR 54.21(c)(1)(iii). 

4.3.4.2 Staff Evaluation 

The staff noted that the applicant conservatively addressed the effects of the reactor coolant 

environment on component fatigue life consistent with the guidance in the SRP-LR and the 

staff’s recommendations for resolving Generic Safety Issue No. 190 (GSI-190), dated 

December 26, 1999. The staff also noted that, consistent with Commission Order 

No. CLI-10-17, dated July 8, 2010, the evaluations associated with the effects of the reactor 

coolant environment on component fatigue life do not fall within the definition of a TLAA in 

10 CFR 54.3(a) because these evaluations are not in the applicant’s CLB. Based on 

Commission Order No. CLI-10-17, the staff finds the applicant’s evaluation of the effects of the 

reactor coolant environment on component fatigue life is conservative and is an acceptable 

practice consistent with the staff’s recommendations in the SRP-LR and the closure of GSI-190. 

On May 27, 2010, the applicant submitted LRA Amendment 16 which provided conforming 

changes to LRA Section 4.3.4 to address staff concerns that were discussed in a public meeting 

on May 6, 2010. 

The staff reviewed the applicant’s bases for dispositioning each of the EAF analyses in order to 

confirm whether or not the applicant had provided a valid basis for demonstrating that each of 

the CUF analyses would be acceptable in accordance with 10 CFR 54.21(c)(1)(ii), that the 

analysis has been projected to the end of the period or extended operation, or 

10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended functions will be adequately 

managed for the period of extended operation. 
Time-Limited Aging Analyses 

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LRA Section 4.3.4 states that the maximum applicable environmental factors (Fen) for low alloy 

steel was used for RPV shell and lower head, RPV inlet and outlet nozzles, and safety injection 

nozzle (forging knuckle). These factors were determined following NUREG/CR-6583, “Effects 

of LWR Coolant Environments on Fatigue Design Curves of Carbon and Low-Alloy Steels.” 

However, the staff noted that LRA Section 4.3.4 does not give sufficient information to confirm 

this statement. By letter dated June 2, 2010 the staff issued RAI 4.3-4 asking that the applicant 

demonstrate that the Fen factor used for assessment of the reactor coolant environmental affect 

on the RPV shell and lower head, RPV inlet and outlet nozzles, and safety injection nozzle 

(forging knuckle) are the maximum applicable for a given material. The staff also asked that the 

applicant provide a basis and justification for any assumptions that were made for the 

parameters in the assessment, such as strain rate, dissolved oxygen, temperature, and sulfur 

content. This was previously identified as part of Open Item 4.3-1. 

The applicant's response dated June 29, 2010, stated that the “maximum applicable” Fen factors 

for the low alloy steel RPV shell and lower head, RPV inlet and outlet nozzles, and safety 

injection nozzle (forging knuckle) were all computed using NUREG/CR-6583. The applicant 

further stated that in each case, a constant bounding Fen value was computed, using the 

following assumptions: 

 Low concentration of dissolved oxygen (DO < 0.05 ppm) for times when water 

temperature was above 150 degrees Celsius (302 degrees F) 

 Most conservative value of T* (transformed temperature) (= 200 for LAS) 

 Most conservative value for ε* (transformed total strain rate) (= ln(0.001)) 

 Most conservative value of S* (transformed sulphur content) (= 0.015 for LAS) 

The applicant stated that the dissolved oxygen value was selected based on industry 

experience and confirmed by the PVNGS chemistry staff. The applicant noted only a few 

instances when dissolved oxygen exceeded 0.05 ppm for a relatively short period of time. 

These occurred following the startup of a third RCP while in hot standby after refueling. The 

applicant stated that these infrequent exceptions do not impact the validity of the assumed 

dissolved oxygen level. 

The staff finds the applicant’s operation with a dissolved oxygen level of less than 0.05 ppm is 

reasonable. The applicant stated that it confirmed this level had been maintained with the only 

exceptions occurring during the startup of a third reactor coolant pump in hot standby after 

refueling. The staff noted that this time duration is insignificant when compared to the amount 

of time the plant is operated with dissolved oxygen levels less than 0.05 ppm and, therefore, its 

impact is negligible. 

The staff noted the use of NUREG/CR-6583 is consistent with the GALL Report Metal Fatigue 

Program. The staff confirmed that the assumptions used by the applicant from this report were 

the most conservative for calculating the Fen value for low-alloy steel components and that the 

resultant Fen value is 2.455. The staff noted that the applicant’s use of the Fen value of 2.455 for 

low-alloy steel components is acceptable and appropriate, as described above. 

Based on its review, the staff finds the applicant’s response to RAI 4.3-4 acceptable because 

the applicant justified its use of a dissolved oxygen level of less than 0.05 ppm and used the 

most conservative assumptions from NUREG/CR-6583 to calculate the Fen value for low-alloy 

steel components. Finally, the applicant used a maximum Fen value of 2.455 based on the 

acceptable assumptions described above. The staff’s concern described in RAI 4.3-4 is 

resolved and this part of Open Item 4.3-1 is closed. 

The GALL Report metal fatigue AMP states that the impact of the reactor coolant environment 

on a sample of critical components should include the locations identified in NUREG/CR-6260 
Time-Limited Aging Analyses 

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as a minimum, and that additional locations may be needed. In LRA Table 4.3-11, there are 

eight plant-specific locations listed, based on the seven generic locations identified in 

NUREG/CR-6260, and one additional location (pressurizer heater penetrations). The applicant 

discussed in the response to RAI 4.3-7 (August 12, 2010) that the pressurizer surge line elbow 

is the bounding location for the pressurizer surge line. During its review, the staff was unclear 

whether the applicant verified that the plant-specific components listed in the LRA Table 4.3-11 

per NUREG/CR-6260 were bounding for the generic NUREG/CR-6260 locations. Furthermore, 

the staff noted that the applicant’s plant-specific configuration may contain locations that should 

be analyzed for the effects of the reactor coolant environment in addition to the generic 

locations identified in NUREG/CR-6260. 

The staff requested the applicant confirm and justify that the plant-specific components or 

locations listed in LRA Table 4.3-11 (except the pressurizer surge line pressurizer elbow) are 

bounding for the generic NUREG/CR-6260 locations and the additional location (pressurizer 

heater penetrations). The staff also requested the applicant to confirm and justify that the 

LRA Table 4.3-11 locations selected for EAF analyses consists of the most limiting locations for 

the plant. If these locations are not bounding, clarify the locations that require an EAF analysis 

and the actions that will be taken for these additional locations. 

By letter dated December 3, 2010, the applicant provided additional information to address the 

staff’s concern. The applicant committed (Commitment No. 63) to complete the following: 

a) No later than two years prior to the period of extended operation, APS will 

confirm that the plant-specific components listed in LRA Table 4.3-11 (except the 

pressurizer surge line pressurizer elbow) are bounding for the generic 

NUREG/CR-6260 locations and the additional location (pressurizer heater 

penetrations). If locations are found that are not bounded by the Table 4.3-11 

components, APS will perform new analyses as necessary to bound such 

locations, and 

b) No later than two years prior to the period of extended operation, APS will 

confirm that the LRA Table 4.3-11 locations selected for environmentally assisted 

fatigue analyses consist of the most limiting cumulative usage factor (CUF) 

locations for the plant (beyond the generic EAF locations identified in the 

NUREG/CR- 6260 guidance). If the Table 4.3-11 locations are not bounding, 

APS will perform an environmentally assisted fatigue analysis for the additional 

CUF locations not bounded by the Table 4.3-11 locations. If the component with 

the most limiting CUF is composed of nickel alloy, the methodology used to 

perform the environmentally-assisted fatigue calculation for nickel alloy will be 

consistent with NUREG/CR-6909. 

Based on its review, the staff finds the applicant’s response to draft RAI 4.3.4-1 and 

Commitment No. 63 acceptable because, (1) the applicant committed to confirm that plant 

specific components or locations evaluated for environmental fatigue are the limiting locations to 

ensure that additional locations do not require an EAF analysis, (2) EAF analyses for the 

additional CUF locations not bounded by LRA Table 4.3-11 locations will be performed, 

(3) NUREG/CR-6909 will be used for determining a conservative Fen factor for any new nickel 

alloy components that require EAF analysis, and (4) Commitment No. 63 is consistent with the 

recommendations in SRP-LR Sections 4.3.2.2 and 4.3.3.2, and the GALL Report metal fatigue 

AMP, to consider environmental effects for the NUREG/CR 6260 locations. 

Notes 7 and 9 of LRA Table 4.3-11 state the applicant's reanalysis computed Fen values for load 

set pairs with a significant fatigue contribution for the charging system nozzle (safe end) and the 

safety injection nozzle (safe end), respectively. LRA Section 4.3.4 does not contain sufficient 

information on the assumptions used for the environmental Fen factor calculations. By letter 
Time-Limited Aging Analyses 

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dated June 2, 2010, the staff issued RAI 4.3-5 asking the applicant to describe the methodology 

used for the environmental Fen factor calculation of the charging system nozzle and the safety 

injection nozzle. The staff also asked that the applicant provide a basis for any assumptions 

that were made for the parameters, such as strain rate, dissolved oxygen, and temperature, in 

the assessment of a computed Fen value for the load set pairs with a significant fatigue 

contribution. Lastly, the staff asked the applicant to confirm the value of the maximum Fen factor 

used for all remaining load set pairs. This was previously identified as part of Open Item 4.3-1. 

The applicant's June 29, 2010, response stated that the Fen analyses for these locations are 

documented in detail in plant calculations, and the Fen values were determined for each load-set 

pair using NUREG/CR-5704 for stainless steel components. The applicant further stated that 

the detailed Fen values were computed for load-set pairs that contributed more than 0.001 to the 

CUF for the given location. The applicant further stated that the load-set pairs that contributed 

less usage were conservatively assigned an Fen value of 15.35. The staff noted that the 

applicant provided a table with this information for the charging nozzle and safety injection 

nozzle. 

The staff noted that for the detailed Fen value, the applicant used the maximum temperature for 

each time slice, which is conservative. The applicant stated that a dissolved oxygen 

concentration of less than 0.05 ppm was assumed for stainless steel. The staff noted that 

NUREG/CR-5704 provides guidance to calculate the Fen value for stainless steel and confirmed 

that the assumption of dissolved oxygen less than 0.05 ppm is conservative since it maximizes 

the Fen value. The applicant stated that both the strain rate and water temperature were 

calculated from the design transient specifications and corresponding stress analyses, and thus, 

no assumptions were made for these parameters. 

The staff finds the applicant’s approach reasonable since for load-set pairs that contributed 

more than 0.001 to the CUF, the applicant assumed dissolved oxygen levels that would 

maximize the Fen value for stainless steel. The staff also finds the applicant's approach 

reasonable because it used the strain rate and water temperature that were calculated from the 

design transient specifications and stress analyses, which allows for a more accurately 

calculated Fen value. Finally, the approach is reasonable because the applicant conservatively 

assumed a maximum Fen value of 15.35 for all remaining load-set pairs. 

Based on its review, the staff finds the applicant’s response to RAI 4.3-5 acceptable because 

the applicant provided the details of the methodology used to calculate more accurate Fen

values for the charging nozzle and safety injection nozzle. The staff’s concern described in 

RAI 4.3-4 is resolved and this part of Open Item 4.3-1 is closed. 

The staff noted that for the other stainless steel components that required an EAF analyses, 

which include the surge line (hot leg) elbow and shutdown cooling line (long radius elbow), the 

applicant used an Fen value of 15.35, which is conservative and acceptable because it is the 

maximum that can be calculated consistent with NUREG.CR-5704. 

LRA Section 4.3.4 states that a bounding Fen factor of 1.49 was used for the Alloy 600 

pressurizer heater penetrations as determined from NUREG/CR-6335, “Fatigue Strain - Life 

Behavior of Carbon and Low-Alloy Steels, Austenitic Stainless Steels, and Alloy 600 in LWR 

Environments.” This report provides the statistical characterizations used to derive this Fen

factor of 1.49 for Alloy 600 and also states that the fatigue S-N database (fatigue per load cycle 

curves) for Alloy 600 is extremely limited and does not cover an adequate range of material and 

loading variables that might influence fatigue life. It further states that the data were obtained 

from relatively few heats of material and is inadequate to establish the effect of strain rate on 

fatigue life in air or of temperature in a water environment. 

The staff noted that NUREG/CR-6909, “Effect of LWR Coolant Environments on the Fatigue Life 

of Reactor Materials,” incorporates more recent fatigue data using a larger database for 
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determining the Fen factor of nickel alloys. The staff noted that the applicant's value for Fen

factor of 1.49 for nickel alloys may be non-conservative. NUREG/CR-6909 states that Fen for 

nickel alloys, varies based on temperature, strain rate, and dissolved oxygen. The staff further 

noted that, based on actual plant operating conditions, the Fen factor can vary from 1.0 to 4.52 

based on this methodology. Therefore, the CUF value for the pressurizer heater penetrations 

may be as high as 2.86 using the CUF presented in the LRA and the maximum Fen derived from 

NUREG/CR-6909, which would exceed the design limit of 1.0 when considering environmental 

effects of reactor coolant during the period of extended operation. 

By letter dated June 2, 2010, the staff issued RAI 4.3-6 asking the applicant justify using a value 

of 1.49 for the Fen factor for this nickel alloy component. The staff further asked that the 

applicant describe the current or future planned actions to update the CUF calculation with Fen

factor for the Alloy 600 component only, consistent with the methodology in NUREG/CR-6909. 

If there are no current or future planned actions to update the CUF calculation with Fen factor for 

the Alloy 600 component consistent with the methodology in NUREG/CR-6909, the applicant 

must provide a justification for not performing the update. This was previously identified as part 

of Open Item 4.3-1. 

The applicant's June 29, 2010, response to RAI 4.3-6 included a commitment (Commitment 

No. 57) to confirm the conservatism of the Fen value of 1.49 using the methods specified in 

NUREG/CR-6909 and to use the new Fen value if it is more conservative than the 1.49 value. It 

will complete this commitment no later than two years prior to the period of extended operation. 

The applicant also committed (Commitment No. 58) to perform a reanalysis of the pressurizer 

heater penetrations to consider EAF effects using the methodology given in NUREG/CR-6909. 

The staff finds the applicant’s response to RAI 4.3-6 acceptable because the applicant 

committed (Commitment No. 57) to confirm the conservatism of its use of the Fen value of 1.49 

or perform a reanalysis of the pressurizer heater penetrations using a Fen value calculated using 

the methodology in NUREG/CR-6909. The staff’s concern described in RAI 4.3-4 is resolved 

and this part of Open Item 4.3-1 is closed. 

Based on its review, the staff finds the applicant’s disposition of 10 CFR 54.21(c)(1)(ii) 

acceptable for the reactor vessel inlet and outlet nozzles and RPV shell and lower head 

locations because the applicant has demonstrated that, when considering environmental effects 

of reactor water, the CUF is projected to remain below the design limit of 1.0 for the period of 

extended operation. Further, the applicant will continue to monitor these locations with its 

enhanced Metal Fatigue Program during the period of extended operation. 

Based on its review, the staff finds the applicant’s disposition of 10 CFR 54.21(c)(1)(iii) 

acceptable for the surge line (hot leg) elbow, charging system nozzle (safe end), safety injection 

nozzle (forging knuckle and safe end), shutdown cooling line (long radius elbow) and 

pressurizer heater penetrations. It is acceptable because the applicant will continue to manage 

the effects of EAF for these components with its enhanced Metal Fatigue Program to ensure 

that the design limit of 1.0 is not exceeded, or it will take corrective actions to reanalyze, repair, 

or replace the affected component. Finally, it is acceptable because the applicant committed to 

reanalyze the nickel alloy pressurizer heater penetrations 

4.3.4.3 Updated Final Safety Analysis Report Supplement 

LRA Section A3.2.3 provides the UFSAR supplement summarizing the evaluation of the effects 

of the RCS environment on fatigue life of piping and components (Generic Safety Issue 190). 

The staff reviewed LRA Section A3.2.3 against the acceptance criteria in SRP-LR 

Section 4.3.2.3. Based on its review of the UFSAR supplement, consistent with SRP-LR 

Sections 4.3.2.3 and 4.3.3.3, the staff determines that the applicant provided an adequate 

summary description of its actions to address effects of the reactor coolant system environment 

on fatigue life of piping and components, as required by 10 CFR 54.21(d). 
Time-Limited Aging Analyses 

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4.3.4.4 Conclusion 

On the basis of its review, the staff concludes that the applicant’s evaluations on the effects of 

the reactor coolant environment on component fatigue life is not a TLAA as defined by 

10 CFR 54.3(a) and is consistent with Commission Order No. CLI-10-17 (July 8, 2010). The 

staff also concludes that the applicant has provided an acceptable demonstration, pursuant to 

10 CFR 54.21(c)(1)(ii), that the effects of fatigue, including environmental effects of reactor 

coolant water on the intended functions of the reactor vessel inlet and outlet nozzles, and RPV 

shell and lower head locations, have been projected to the end of the period of extended 

operation. The staff also concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of fatigue, including environmental effects of reactor 

coolant water on the intended functions of the surge line (hot leg) elbow, charging system 

nozzle (safe end), safety injection nozzle (forging knuckle and safe end), shutdown cooling line 

(long radius elbow), and pressurizer heater penetrations, will be adequately managed for the 

period of extended operation. The staff finally concludes that the UFSAR supplement contains 

an appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d). 

4.3.5 Assumed Thermal Cycle Count for Allowable Secondary Stress Range Reduction 

Factor in American National Standards Institute B31.1 and American Society of 

Mechanical Engineers III Class 2 and 3 Piping 

4.3.5.1 Summary of Technical Information in the License Renewal Application 

LRA Section 4.3.5 summarizes the evaluation of “Assumed Thermal Cycle Count for Allowable 

Secondary Stress Range Reduction Factor in ANSI B31.1 and ASME III Class 2 and 3 Piping” 

TLAAs for the period of extended operation. These TLAAs are based on the criteria for 

performing implicit fatigue analyses for ANSI B31.1 piping components, as given in the 

ANSI B31.1 design code, and for ASME Code Class 2 and 3 components, as specified in ASME 

Code Section III, Article NC-3000 for components designed to ASME Code Section III Class 2 

component requirements, and Article ND-3000 for components designed to ASME Code 

Section Class3 component requirements. 

In this TLAA, the applicant noted that, with the exception of the implicit fatigue analyses for the 

reactor coolant hot leg sampling lines and the SG downcomer and feedwater recirculation lines, 

all of the implicit fatigue analyses for the ANSI B31.1 piping components and for the ASME 

Code Class 2 and 3 components remain valid for the period of extended operation in 

accordance with 10 CFR 54.21(c)(1)(i). For these analyses, the applicant states that the total 

number of occurrences for the full thermal transients that are applicable to these components is 

projected to be less than 7,000 through the end of the period of extended operation. 

For the implicit fatigue analyses for the reactor coolant hot leg sampling lines and the SG 

downcomer and feedwater recirculation lines, the applicant states that the analyses have been 

projected through the end of the period of extended in accordance with 10 CFR 54.21(c)(1)(ii). 

For these implicit fatigue analyses, the applicant states that the total number of full thermal 

range transients that are applicable to the lines are projected to be in excess of 7,000 cycle 

occurrences. For these components, applicable stress reduction factors were applied to 

maximum allowable stress limit criteria for the analyses in order to demonstrate that the existing 

stress loadings on the components would still be acceptable for the period of extended 

operation even under the reduced acceptance limit criteria for the analyses. 

4.3.5.2 Staff Evaluation 

On May 27, 2010, the applicant submitted LRA Amendment 16 which included conforming 

changes to LRA Section 4.3.5 to address staff concerns discussed with the applicant in a public 

meeting on May 6, 2010. 
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The staff reviewed the applicant’s bases for dispositioning each of the applicant’s implicit fatigue 

analyses for ANSI B31.1 components and ASME Code Class 2 and 3 components. The staff 

confirmed that the applicant had provided a valid basis for demonstrating that each of the CUF 

analyses would be acceptable in accordance with 10 CFR 54.21(c)(1)(i), that the analysis 

remains acceptable for the period of extended operation, or 10 CFR 54.21(c)(1)(ii) that the 

analysis has been projected to the end of the period or extended operation period of extended 

operation. 

The staff noted that LRA Section 4.3.5 states that the calculated stresses in limiting locations 

were less than the allowable in the revised design analyses for the reactor coolant hot leg 

sample lines piping and the SG downcomer and feedwater recirculation lines piping. However, 

the staff noted that LRA Section 4.3.5 does not give sufficient information for the staff to confirm 

these assertions. By letter dated June 2, 2010, the staff issued RAI 4.3-3 asking the applicant 

supply the code allowable stress limits and the stress ranges obtained in the revised design 

analyses for the reactor coolant hot leg sample line piping and the SG downcomer and 

feedwater recirculation line piping. The staff also asked the applicant to provide the ASME 

Code edition and specific subsection used for the revised design analyses for these piping 

components. This was previously identified as part of Open Item 4.3-1. 

The applicant's June 29, 2010, response provided information related to the reactor coolant hot 

leg sample line piping and the SG downcomer and feedwater recirculation line piping and the 

code allowable stress limits and stress range reduction factors. The staff noted that for the 

reactor coolant hot leg sample line, the applicant used a stress range reduction factor (SRRF) 

of 0.9 because it expected that this component would exceed the original 7,000 cycle limit 

(SRRF = 1.0), with an estimated 8,273 cycles. The staff noted that this is consistent with ASME 

Code Section III and SRP-LR, Table 4.3-1. The staff noted that for the SG downcomer and 

feedwater recirculation line piping, the applicant used an SRRF of 0.8 because it expected that 

this component would exceed the original 10,224 cycle limit (SRRF = 0.9), with an estimated 

15,336 cycles. The staff noted that this is also consistent with ASME Code Section III and 

SRP-LR Table 4.3-1. The staff noted that for both reactor coolant hot leg sample line piping and 

the SG downcomer and feedwater recirculation line piping, the revised allowed stress is less 

than the code allowable limit. 

The applicant identified that the revised design analyses for these piping components was 

performed to the requirements of ASME Code, Section III, 1974 up to and including winter 1975 

Addenda, and the SRRF was obtained from Table NC-3611.2(e)-1. The applicant further stated 

that the comparison of the calculated stress range versus the allowable stress limit was 

performed per the requirements of paragraph NC-3652.3. 

Based on its review, the staff finds the applicant’s response to RAI 4.3-3 acceptable because 

the applicant used the appropriate SRRF of 0.9 and 0.8 for the reactor coolant hot leg sample 

line piping and the SG downcomer and feedwater recirculation line piping, respectively, which is 

consistent with the ASME Code Section III and SRP Table 4.3-1. Further, the response is 

acceptable because the revised allowed stress for these components is less than the ASME 

Code allowable limit. The staff’s concern described in RAI 4.3-3 is resolved and this part of 

Open Item 4.3-1 is closed. 

The amended LRA Section 4.3.5 identified that all implicit fatigue analyses for ANSI B31.1 and 

ASME Class 2 and 3 piping components will be remain valid for the period of extended 

operation except for the implicit fatigue analysis of RCS hot leg sampling lines and the 

recirculating SG downcomer and feedwater recirculation lines. The staff noted that the implicit 

fatigue analysis table provided for the RCS hot leg sampling lines includes a column “Max. 

Calculated Stress per Eq. (11) (psi).” However, the column does not identify the source 

document for the referenced equation 11. Similarly, the implicit fatigue analysis table provided 

for the RSG DC and FW recirculation lines includes a column “Max. Calculated Stress Range 
Time-Limited Aging Analyses 

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per Eq. (10) (psi).” However, the column does not note the source document for the referenced 

equation 10. The staff also noted that in the assessment of the recirculating SG downcomer 

and feedwater recirculation lines, the applicant discussed two different analyses; the original 

implicit fatigue analysis and an updated pipe break analysis. LRA Section 4.3.5 does not clarify 

whether the pipe break analysis has a relationship to the original implicit fatigue analysis for 

these lines. It is also not clear whether both analyses are relied upon for the CLB or whether 

the pipe-break analysis is a replacement for the original implicit fatigue analysis. It is not clear 

to the staff which of the analyses is the current analysis of record for the CLB and thus needs to 

be assessed as a TLAA for these lines. By letter dated July 21, 2010, the staff issued 

RAI 4.3-18 asking the applicant to identify the source documents for the stated equation 

references. The staff also requested the applicant to clarify which of the implicit fatigue 

analyses discussed in LRA Section 4.3.5 for the recirculating SG downcomer and feedwater 

recirculation lines is the analysis of record for these lines (i.e., the original analysis, the pipe 

break analysis, or both analyses). This was previously identified as part of Open Item 4.3-1. 

The applicant's August 12, 2010, response clarified that equations 10 and 11 in LRA 

Section 4.3.5 are those listed in ASME Code Section III, Subsection NC-3600, paragraph NC 

3652.3, for Class 2 piping and Subsection ND-3600, paragraph ND 3652.3, for Class 3 piping. 

The applicant also stated that implicit fatigue analyses, discussed in LRA Section 4.3.5 for the 

recirculating SG downcomer and feedwater recirculation lines, refer to methodology prescribed 

in subsection NC and ND of ASME Code Section III. The analyses determine that if the number 

of full-range thermal cycle is expected to be 7,000 or more, then the ANSI B31.1 and ASME 

Code Section III, Subsection NC and ND for Class 2 and 3 piping require the application of a 

stress range reduction factor to the allowable stress range for expansion stress. The applicant 

stated that these analyses are TLAAs. 

Based on its review, the staff finds the applicant’s response to RAI 4.3-18 acceptable because 

the applicant clarified the 7000-thermal cycles fatigue analysis is the analysis of record for the 

recirculating SG downcomer and feedwater recirculation lines and has been identified as a 

TLAA consistent with 10 CFR 54.21(c)(1). The staff’s concern described in RAI 4.3-18 is 

resolved and this part of Open Item 4.3-1 is closed. 

Based on its review, the staff finds the applicant has demonstrated that, with the exception of 

the reactor coolant hot leg sampling lines and the SG downcomer and feedwater recirculation 

lines, all analyses for the ANSI B31.1 and ASME III Class 2 and 3 piping remain valid for the 

period of extended operation pursuant to 10 CFR 54.21(c)(1)(i). The staff finds it acceptable 

because the number of projected cycles excepted to occur during the period of extended 

operation is significantly lower than the component design life of 7,000 cycles. The staff’s 

evaluation of the applicant’s projection of transients for the period of extended operation is 

documented in SER Section 4.3.1.4.2. The staff also finds the applicant has demonstrated 

pursuant to 10 CFR 54.21(c)(1)(ii), that the analyses for the reactor coolant hot leg sampling 

lines and the SG downcomer and feedwater recirculation lines have been projected through the 

period of extended operation and are acceptable because the applicant applied the applicable 

stress range reduction factor, consistent with ANSI B31.1 and ASME Code Section III 

Subsection NC and ND and the SRP-LR. 

4.3.5.3 Updated Final Safety Analysis Report Supplement 

LRA Section A3.2.4 provides the UFSAR supplement summarizing the TLAAs for ANSI B31.1 

and ASME III Class 2 and 3 piping. The staff reviewed LRA Section A3.2.4 against the 

acceptance criteria in SRP-LR Section 4.3.2.3. Based on its review of the UFSAR supplement, 

consistent with SRP-LR Sections 4.3.2.3 and 4.3.3.3, the staff determines that the applicant 

provided an adequate summary description of its TLAAs for ANSI B31.1 and ASME III Class 2 

and 3 piping, as required by 10 CFR 54.21(d). 
Time-Limited Aging Analyses 

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4.3.5.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(i), that the analyses for the ANSI B31.1 and 

ASME III Class 2 and 3 piping, with the exception of the reactor coolant hot leg sampling lines 

and the SG downcomer and feedwater recirculation lines, remain valid during the period of 

extended operation. Further, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that the analyses for the reactor coolant hot 

leg sampling lines and the SG downcomer and feedwater recirculation lines have been 

projected to the end of the period of extended operation. The staff also concludes that the 

UFSAR supplement contains an appropriate summary description of the TLAA evaluation, as 

required by 10 CFR 54.21(d). 

4.4 Environmental Qualification of Electrical Equipment

The EQ requirements established by 10 CFR Part 50, Appendix A, Criterion 4, and 

10 CFR 50.49 specifically require each applicant to establish a program to qualify electrical 

equipment so that such equipment, in its end of life condition, will meet its performance 

specifications during and following design basis accidents. The 10 CFR 50.49 EQ program is a 

TLAA for purposes of license renewal. Electrical equipment with a qualified life equal to or 

greater than the duration of the current operating term is covered by TLAAs. The TLAA of the 

EQ of electrical components includes certain electrical and instrumentation and control (I&C) 

components that are important to safety and are located in a harsh environment. The harsh 

environment includes those areas subject to environmental effects caused by a LOCA, 

high-energy line break, and a post-LOCA environment. 

4.4.1 Summary of Technical Information in the Application 

LRA Section 4.4, “Environmental Qualification (EQ) of Electrical Equipment,” summarizes the 

applicant’s evaluation of EQ of plant electrical and I&C equipment for the period of extended 

operation. The EQ Program is an existing program established to meet commitments for 

10 CFR 50.49. The applicant also stated that the EQ Program manages applicable component 

thermal, radiation, and cyclical aging effects based on 10 CFR 50.49 for the current operating 

license, using methods of demonstrating qualification for aging and accident conditions 

established by 10 CFR 50.49(f). The applicant selected 10 CFR 54.21(c)(1)(iii) as the means to 

demonstrate the adequacy of the EQ Aging Management Program for the period of extended 

operation. The applicant stated that maintaining qualification through the extended license 

renewal period requires existing EQ evaluations (Electrical Equipment Qualification Data Files) 

to be reanalyzed. The applicant stated that the effects of power uprate and SG replacement 

have been evaluated and equipment re-qualified as required. The applicant further stated that 

the important attributes of reanalysis include analytical methods, data collection and reduction 

methods, underlying assumptions, acceptance criteria, and corrective actions (if acceptance 

criteria are not met). The applicant further stated that, if qualification cannot be extended by 

reanalysis, the component is refurbished or replaced before exceeding the period for which 

current qualification remains valid. 

The applicant concluded that continuing the existing EQ Program ensures that the aging effects 

will be managed and that the EQ components will continue to perform their intended functions 

for the period of extended operation. The applicant also concluded that aging effects addressed 

by the EQ program will thereby be managed for the period of extended operation, in accordance 

with 10 CFR 54.21(c)(1)(iii). 
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4.4.2 Staff Evaluation 

The staff reviewed LRA Section 4.4; Appendix B, Section B3.2; program basis documents; and 

information supplied to the staff during the audit and interviewed plant personnel to determine if 

the applicant’s EQ Program meets the requirements of 10 CFR 54.21(c)(1). The applicant’s EQ 

TLAA Program is implemented per the requirements of 10 CFR 54.21(c)(1)(iii), which requires 

that the effects of aging on the intended functions will be adequately managed for the period of 

extended operation. The staff confirmed the applicant’s EQ Program conforms to the 

requirements of 10 CFR 50.49, including the management of aging effects, to confirm that 

electric equipment requiring EQ will continue to operate consistent with the CLB during the 

period of extended operation. Per the GALL Report, plant EQ Programs that meet the 

requirements of 10 CFR 50.49 are considered acceptable AMPs under license renewal in 

accordance with 10 CFR 54.21(c)(1)(iii). GALL AMP X.E1, “Environmental Qualification (EQ) of 

Electric Components,” provides a means to meet the requirements of 10 CFR 54.21(c)(1)(iii). 

Based on the staff’s review of LRA Section 4.4 and Appendix B, Section B3.2, including the 

audit results, the staff concludes that the applicant’s EQ of Electric Equipment TLAA is carried 

out per the requirements of 10 CFR 54.21(c)(1)(iii). 

Therefore, the staff finds that the applicant’s EQ Program demonstrates, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effect of aging on the intended functions will be adequately 

managed for the period of extended operation. The applicant’s EQ Program is capable of 

managing the qualified life of components within the scope of license renewal, and the 

continued implementation of the EQ Program provides assurance that the aging effects will be 

managed and that electric equipment will continue to perform their intended functions for the 

period of extended operation. 

4.4.3 Updated Final Safety Analysis Report Supplement 

In LRA Appendix A, Section A3.3 provides the UFSAR supplement for the EQ of Electrical 

Equipment Program. The staff reviewed the UFSAR supplement description of the program 

against the recommended description for this type of program as described in SRP-LR 

Tables 4.4-1 and 4.4-2 and noted that it did not include reanalysis attributes consistent with the 

description of the TLAA in LRA Section 4.4 or the AMP in LRA Section B3.2. GALL AMP EQ of 

Electric Components, states that reanalysis of an aging evaluation is normally done to extend 

the qualification by reducing excess conservatism incorporated in the prior evaluation. 

Important attributes of a reanalysis include analytical methods, data collection and reduction 

methods, underlying assumptions, acceptance criteria, and corrective actions (if acceptance 

criteria are not met). 

By letter dated December 29, 2009, the staff issued RAI 4.4-1 to ask the applicant to provide 

justification for not including reanalysis attributes in accordance with 10 CFR 54.21(c)(1)(iii) in 

the UFSAR supplement. The applicant responded by letter dated February 19, 2010, and 

stated LRA Sections A2.2 and A3.3 have been revised to include the following: “[r]eanalysis of 

aging evaluations to extend the qualifications of components is performed on a routine basis as 

part of the EQ Program. Important attributes for the reanalysis of aging evaluations include 

analytical methods, data collection and reduction methods, underlying assumptions, acceptance 

criteria and corrective actions (if acceptance criteria are not met).” 

With the information provided by the applicant’s RAI response, the staff finds the UFSAR 

supplement acceptable because the applicant revised LRA Sections A2.2 and A3.3 to be 

consistent with the guidance of SRP Table 4.4.2. The staff considers RAI 4.4-1 resolved. 

The staff determines that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d). 
Time-Limited Aging Analyses 

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4.4.4 Conclusion 

On the basis of its review of the applicant’s EQ of Electric Equipment TLAA and RAI response, 

the staff concludes that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended functions will be maintained, pursuant to 

10 CFR 54.21(c)(1)(iii), for the period of extended operation. The staff also reviewed the 

UFSAR supplement and concludes that it provides an adequate summary description of the 

program, as required by 10 CFR 54.21(d). 

4.5 Concrete Containment Tendon Prestress Analyses

4.5.1 Summary of Technical Information in the Application 

LRA Section 4.5 summarizes the evaluation of concrete containment tendons prestress for the 

period of extended operation. The LRA states that the containment is a prestressed concrete, 

hemispherical, dome-on-a-cylinder structure with a steel membrane liner. Post-tensioned 

tendons compress the concrete and permit the structure to withstand design-basis accident 

internal pressures. The steel tendons, in tension, relax with time and the concrete structure, 

which the tendons hold in compression, both creeps and shrinks with time. Therefore, the 

applicant stated that to ensure the integrity of the containment pressure boundary under 

design-basis accident loads, an inspection program confirms whether the tendon prestress 

remains within design limits throughout the life of the plant. The applicant further stated that the 

original design predictions of loss of prestress and the regression analyses of surveillance data 

that predict the future performance of the post-tensioning system to the end of design life are 

TLAAs and it dispositioned them in accordance with 10 CFR 54.21(c)(ii). 

The LRA describes the post-tensioning system of each unit as consisting of vertical, 

inverted-U-shaped tendons and horizontal circumferential tendons. The applicant described the 

vertical, inverted-U tendons as anchored through the bottom of the conventionally-reinforced 

concrete basemat. The LRA further states that the horizontal hoop tendons are anchored at 

three exterior buttresses, which are 120 degrees apart. Each hoop tendon extends 

240 degrees around the containment building, passing under an intervening buttress. The 

applicant also stated that the tendons are not bonded to the concrete but inserted in tendon 

ducts after concrete cure and tensioned in the prescribed sequence. Each tendon consists of 

up to 186 one-quarter-inch diameter high-strength steel wires with cold-formed button heads on 

each end bearing on a stressing anchorhead. The total tendon load is carried by shim stack to 

steel bearing plates embedded in the structure. 

LRA, Appendix B, Section B3.3 summarizes the TLAA AMP, “Concrete Containment Tendon 

Prestress Program.” The applicant stated that before September 1996, RG 1.35 governed the 

tendon examinations. Additionally, the applicant stated that the tendon lift-off surveillances 

were done for Units 1 and 3, at one, three, and five years post-structural-integrity test, and at 

each succeeding five-year interval. Unit 2 tendons were examined visually and in other ways, 

but their lift-off test surveillances were encompassed within the Unit 1 tests, under rules then 

applicable to 2-unit plants with virtually identical containments. Beginning with License 

Amendment 151, the program was governed by ASME Code Section XI, Subsection IWL, 1992 

Edition with 1992 Addenda and supplemental requirements in 10 CFR 50.55a. A licensing 

change under approved RR L4 imposed the surveillance of Unit 2 prestress tendon lift-off 

forces, beginning with its 20th year, and extended the surveillance interval to 10 years for all 3 

units. The applicant states that the assessment of the results of the tendon prestressing force 

measurements and acceptance criteria are in accordance with the edition and addenda of 

ASME Code Section XI, Subsection IWL referenced above, as incorporated in 10 CFR 50.55a. 
Time-Limited Aging Analyses 

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The applicant stated that the condition of the containment prestressing system meets the criteria 

for revision for the period of extended operation as described in NUREG-1800, 

Section 4.5.3.1.2. The applicant discussed these criteria as follows: 

 The lift-off trend lines were calculated by regression of individual tendon lift-off data, 

including the results of the 2005, Unit 2, 20-year surveillance. Therefore, these 

calculations are consistent with NRC Information Notice 99-10, “Degradation of 

Prestressing Tendon Systems in Prestressed Concrete containments,” Attachment 3. 

 The regression analysis of surveillance lift-off data extends the trend lines for both the 

vertical and horizontal cylinder tendons to 60 years. 

 The trend line for all tendon groups remain above the minimum required values (MRVs) 

for the period of extended operation. 

4.5.2 Staff Evaluation 

The staff reviewed LRA Section 4.5 to verify using SRP-LR Section 4.5.3.1.2, that the trend of 

prestressing forces in each tendon group was projected to the end of the period of extended 

operation and the projected prestressing forces were above their respective MRVs per 

10 CFR 54.21(c)(1)(ii). Also, the staff reviewed LRA Section 4.5 to verify that the trend lines for 

each tendon group, presented in LRA Figures 4.5-1–4.5-6, are based on individual tendon lift-off 

forces as specified in Information Notice 99-10. The figures show that the projected 

prestressing forces trend lines for the vertical and horizontal tendons remain above their 

respective MRVs through the period of extended operation. The trend lines also remain above 

RG 1.35.1 predicted prestress forces through the period of extended operation; except for Unit 3 

horizontal tendon prestress (Figure 4.5-3), indicating that the loss of prestress is less than 

originally predicted. As stated by the applicant, the trend lines do not include the Unit 1, 25-year 

tendons lift-off surveillance results. The applicant explained in LRA Section 4.5 that the 

surveillance was not completed in time to be included in the LRA. By letter dated 

March 2, 2010, the staff issued RAI 4.5-1 to ask the applicant to provide the tendon regression 

analyses that include the results of 25-year containment tendon prestressing surveillance for 

Unit 1. 

The applicant's April 1, 2010, response to RAI 4.5-1 stated that it is revising the regression 

analysis to incorporate the Unit 1, 25-year tendon surveillance data. The applicant committed to 

submitting the revised LRA Figures 4.5-1, 4.5-2, 4.5-5, and 4.5-6 in LRA amendment by 

May 28, 2010. The applicant also explained that the evaluation of the Unit 1, 25-year 

surveillance data shows that the recalculated regression lines for horizontal and vertical tendons 

will remain well above their respective MRVs through the period of extended operation. By 

letter dated May 21, 2010, the applicant submitted the revised LRA Figures 4.5-1, 4.5-2, 4.5-5, 

and 4.5-6. The staff’s review of the figures confirmed that the revised regression analysis 

incorporates the Unit 1, 25-year tendon surveillance data and that the prestress, for each 

tendon group, will remain above their respective MRVs through the period of extended 

operation. The staff finds the applicant’s response acceptable because the projected 

prestressing forces trend lines will remain above their respective MRVs through the period of 

extended operation. The staff’s concern in RAI 4.5-1 is resolved. 

In LRA Section 4.5, the applicant credits, per 10 CFR 54.21(c)(1)(iii), the “Concrete 

Containment Tendon Prestress” AMP, described in LRA Section B3.3, for managing loss of 

prestress in the tendons during the period of extended operation. The staff reviewed LRA 

Section B3.3 in accordance with the guidance in SRP-LR Section 4.5.3.1.3, to verify the 

applicant identified the appropriate program as described and evaluated in the GALL Report. 

The applicant stated that the AMP is an existing program that, following enhancement, will be 

consistent with NUREG-1801, Section X.S1, “Concrete Containment Tendon Prestress.” The 
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staff noted that the applicant referenced RR L4, which permits the 10-year interval between 

tendon prestress surveillance for the three PVNGS units during the current 40-year term. By 

letter dated March 2, 2010, the staff issued RAI 4.5-2 to ask the applicant to provide information 

on how the aging of the containment tendons will be managed during the period of extended 

operation. 

The applicant's April 1, 2010, response to RAI 4.5-2 stated that aging of the tendons will be 

managed through inspections as described in the applicable edition and addenda of the ASME 

Code Section XI, Subsection IWL, in accordance with 10 CFR 50.55(a), including any NRC 

approved RRs. The staff finds the applicant’s response acceptable because the tendon 

prestress surveillance interval will be in accordance with the applicable edition and addenda of 

ASME Code Section XI, Subsection IWL incorporated in 10 CFR 50.55(a) during the period of 

extended operation. The staff’s concern in RAI 4.5-2 is resolved. 

In LRA Section 4.5, the applicant provided Table 4.5-1, Tendon Regression Analysis Input Data 

for PVNGS Units 1, 2, and 3. The staff’s review of the tabulated tendon lift-off data observed 

that only the “shop end” force is provided for tendons H21-04, V07, and V015. Also, the lift-off 

force for tendon H21-04 was measured in the third year surveillance and again in the fifth year 

and the Unit 3 dome horizontal tendon lift-off average forces are greater than the wall horizontal 

lift-off average forces, in some cases by nearly 100 kips. By letter dated, March 2, 2010, the 

staff issued RAI 4.5-3 to ask the applicant to explain the anomalies and confirm they have no 

affect on its conclusion that regression analysis trend lines show that tendon prestress will 

remain above their respective MRVs through the end of the period of extended operation. 

By letter dated May 21, 2010, the applicant responded to RAI 4.5-3 and addressed each 

anomaly identified by the staff as well as other self-identified anomalies. In its response, the 

applicant provided technical and licensing bases for its conclusions to show that the anomalies 

have no significant effect on the regression analysis results. The staff reviewed the applicant’s 

response and found the applicant has adequately addressed the issue because it explained the 

anomalies and confirmed they have no affect on the regression analysis conclusion. The staff’s 

concern in RAI 4.5-3 is resolved. 

The staff reviewed the applicant’s operating experience related to the containment tendon 

prestress force. The results of the review are documented in the staff evaluation of the 

applicant’s Concrete Containment Tendon Prestress Program in SER Section B3.3. The results 

show that the applicant’s program has adequately considered plant-specific operating 

experience. 

Based on this review, the staff concludes the applicant has noted the appropriate program and 

has stated the GALL Report is applicable to its plant with respect to its program that assesses 

the concrete containment tendon prestressing forces. 

4.5.3 Updated Final Safety Analysis Report Supplement 

The applicant provided a UFSAR supplement summary description of its TLAA evaluation of 

concrete containment tendon prestress in LRA Section A3.4. Based on its review of the UFSAR 

supplement, the staff concludes that the summary description of the applicant’s actions to 

address concrete containment tendon prestress is adequate. 

4.5.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21 (c)(1)(ii), that the effects of aging on the concrete containment prestressing 

tendons have been projected to the end of the period of extended operation. The staff also 

concludes that the applicant has appropriately credited, pursuant to 10 CFR 54.21(c)(1)(iii), the 

Concrete Containment Tendon Prestress Program for managing loss of tendon prestress during 
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the period of extended operation. Additionally, the staff determined that the UFSAR supplement 

contains an appropriate summary description of the TLAA on containment tendon loss of 

prestress analysis for the period of extended operation, as required by 10 CFR 54.21(d). 

4.6 Containment Liner Plate, Equipment Hatch and Personnel Air Locks, 

Penetrations, and Polar Crane Brackets

4.6.1 Absence of a Time-Limited Aging Analysis for Containment Liner Plate, Polar 

Crane Brackets, Equipment Hatch and Personnel Air Locks, and Containment 

Penetrations (Except Main Steam, Main Feedwater, and Recirculation Sump 

Suction Penetrations) 

4.6.1.1 Summary of Technical Information in the Application 

The post-tensioned concrete containments were designed in accordance with ASME Boiler and 

Pressure Vessel Code, Section III, Division 2, Article CC-3000, supplemented by the design 

methods and criteria of Bechtel Topical Reports BC-TOP-1, “Containment Building Liner Plate 

Design Report,” Revision 1, and BC-TOP-5-A, “Prestressed Concrete Nuclear Reactor 

Containment Structures,” Revision 3. The interior of the containments is lined with steel 

membrane liners designed to BC-TOP-1 Revision 1. No credit is taken for the liner for the 

pressure design of the containment, but the liner and penetrations ensure the containments are 

leak-tight, and their electrical, process, personnel airlock, and equipment hatch penetrations are 

part of the containment pressure boundary. 

LRA Section 4.6.1 summarizes the evaluation of absence of a TLAA for containment liner plate, 

polar crane bracket, equipment hatch, air lock, and containment penetration design (except 

main stream, main feedwater, and recirculation sump suction penetrations) for the period of 

extended operation. The liner plate provides a leak-tight barrier to prevent uncontrolled release 

of fission products from the containment during normal plant operation and in the unlikely event 

of an accident. SRP-LR Section 4.6.1 notes that in some designs, “fatigue of the liner plates or 

metal containments may be considered in the design based on an assumed number of loading 

cycles for the current operating term.” The cyclic loads include reactor building interior 

temperature variation during the heatup and cooldown of the RCS, a LOCA, annual outdoor 

temperature variations, thermal loads due to the high energy containment penetration piping 

lines (such as steam and feedwater lines), seismic loads, and pressurization due to periodic 

Type A integrated leak rate tests. The applicant states that its examination of the controlling 

reports BC-TOP-1, BC-TOP-5A, the design specification, and design report found no evidence 

that heatup and cooldown or seasonal temperature variations were considered cyclic loads on 

the containment building and liner. The applicant further states that the UFSAR contains no 

description of cyclic loads or design cycles for the entire containment building; but UFSAR 

Section 3.8.1.5.4.B describes design cycles that are to be included in the design of the liner 

plate and penetrations. However, the review of the design specification, design report, and 

design calculations found time-dependent aspects of some penetration designs but none for 

liner plate design; therefore, the liner plate design is not supported by a TLAA. 

The applicant also explained that the polar crane is supported on a system of girders, which are 

supported by a series of brackets that are attached to the containment shell. BC-TOP-1 

Revision 1 reviews design of the polar crane brackets. The report does not include or specify 

the requirement for a fatigue analysis, or any other design for a stated number of crane lifts, 

cyclic loads, or other cyclic events. Therefore, design of the polar crane brackets for a finite 

number of loads is not supported by a TLAA. 

For the equipment hatch and personnel air locks, the applicant said that the components were 

designed to ASME Code Section III, Division 1, Subsection NE - Class MC Components, 
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1974 W74. Subparagraph NE-3222.4 gives rules for a fatigue analysis of MC components for 

cyclic loads, if specified. However, the review of licensing basis documents, specifications, and 

the design report identified no time-dependent analyses. Designs of the equipment hatch and 

personnel air locks are, therefore, not supported by TLAAs. 

For containment penetrations, the applicant stated that a search of the licensing basis and the 

review of the design documents found no evidence of any TLAAs applicable to containment 

penetrations; except for the main stream, main feedwater penetration design in BC-TOP-1 

Part II, supporting design calculations described in Section 4.6.2 below, and the recirculation 

sump suction penetration design described in Section 4.6.3 below. The containment 

penetrations include no bellows or expansion joints whose design is supported by a TLAA. 

4.6.1.2 Staff Evaluation 

The staff reviewed LRA Section 4.6.1 to evaluate the absence of a TLAA for the containment 

liner plate, polar crane brackets, equipment hatch and personnel air locks, and containment 

penetrations (except main stream, main feedwater, and recirculation sump suction 

penetrations). The containments were designed in accordance with ASME Boiler and Pressure 

Vessel Code Section III, Division 2, Article CC-3000, supplemented by the design methods and 

criteria of BC-TOP-1 and BC-TOP-5-A. The staff noted that BC-TOP-1 and BC-TOP-5-A do not 

include a fatigue analysis or require evaluation of these components for cyclic loading; except 

by a reference to ASME Code Section III, Division 2, Article CC-3760, which requires the 

designer to ensure suitability of the liner plate for cyclic loads established in the design 

specification. The staff noted that UFSAR Section 3.8.1.5.4.B says that 500 thermal cycles due 

to variation in the interior temperature of the containment during the heatup and cooldown of the 

reactor, 40 cycles due to annual outdoor temperature variation, and 1 LOCA cycle are 

considered in the liner design for its 40-year life. As a result, the staff issued RAI 4.6-1 asking 

the applicant to evaluate the liner plate system for cyclic loading during the period of extended 

operation, consistent with UFSAR 3.8.1.5.4.B, or give additional technical basis to demonstrate 

that this evaluation is not required. 

By letter dated April 1, 2010, the applicant stated that the containment liner plate system was 

evaluated for cyclic loading during the period of extend operation consistent with UFSAR 

Section 3.8.1.5.4.B requirements. The applicant concluded that the design basis analyses are 

conservative and remain valid for the period of extended operation, pursuant to 

10 CFR 54.4(c)(1)(i). 

In its review of the analyses, the staff noted that the applicant did not provide the actual thermal 

cycles for the current term and the projected thermal cycles through the period of extended 

operation. However, the applicant stated that the assumed 500 containment interior operational 

heatup and cooldown cycles correspond to 81⁄3 cycles per year for 60-year plant life, which is 

conservative. The staff agrees that 81⁄3 thermal cycles per year are conservative and finds the 

applicant’s response acceptable because the containment liner plate system is evaluated for 

cyclic loading, consistent with UFSAR Section 3.8.1.5.4.B. The applicant noted that Palo Verde 

Action Request 3451141 was initiated to clarify UFSAR Section 3.8.1.5.4.B. The staff’s concern 

in RAI 4.6-1 is resolved. 

For polar crane brackets, equipment hatch and personnel air locks, and containment 

penetrations (except main stream, main feedwater, and recirculation sump suction 

penetrations), the staff agrees with the applicant that neither the Bechtel Topical Reports nor the 

ASME Code editions and addenda invoked by them impose a fatigue analysis or evaluation for 

cyclic loading. 
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4.6.1.3 Updated Final Safety Analysis Report Supplement 

The applicant provided a UFSAR supplement summary description of its TLAA evauation in 

LRA Section A3.5, as provided in Amendment 17 (June 21, 2010). Based on its review of the 

UFSAR supplement, the staff concludes that the summary description of the applicant's actions 

to address design cycles for the containment liner plate is adequate. 

4.6.1.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(i), that the evaluation for the containment liner plate system remains valid 

during the period of extended operation. Additionally, the absence of a TLAA for the polar crane 

brackets, equipment hatch and personnel air locks, and containment penetrations (except main 

steam, main feedwater, and recirculation sump suction penetrations) for the period of extended 

operation is adequate. The staff also concludes that the UFSAR supplement contains an 

appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d). 

4.6.2 Design Cycles for the Main Steam and Main Feedwater Penetrations 

4.6.2.1 Summary of Technical Information in the Application 

LRA Section 4.6.2 summarizes the evaluation of design cycles for the main steam and main 

feedwater penetrations for the period of extended operation. The applicant states that the 

design of main steam line penetrations includes 100 lifetime steady state operating thermal 

gradient plus normal operating cyclic loads (i.e., Loading Condition V) and 10 steady state 

operating thermal gradient plus steam pipe rupture cyclic loads (i.e., Loading Condition IV), as 

specified in BC-TOP-1. The BC-TOP-1 analysis of effects of Loading Condition IV and V cyclic 

loads does not calculate a usage factor but uses a simplified ASME Code Section III, 

Subparagraph NB-3228.3, elastic-plastic analysis to compare the maximum allowed alternating 

stress range to the calculated maximum alternating stress intensity. The applicant noted that 

neither BC-TOP-1 nor the main steam penetration design calculation explicitly include the main 

feedwater penetrations; but the design calculation for “remaining penetrations” refers to the 

main steam penetration design calculation for both main steam and main feedwater 

penetrations. The applicant concluded the assumed cyclic loads for the main steam 

penetrations and the elastic-plastic evaluation of BC-TOP-1 is applicable to the main feedwater 

penetrations. 

The LRA states that the original design basis 100 operating thermal cycles (Load Condition V) 

assumed for the main stream penetrations (also applicable to main feedwater penetrations) will 

be exceeded during the period of extended operation. The applicant stated that based on its 

plant operating experience, 250 full-range thermal cycles (BC-TOP-1 Part II “Condition V” 

events) could be expected in 60 years. The applicant then used 250 cycles in its evaluation of 

the TLAA, in addition to the 10 Loading Condition IV events, and concluded that the design 

analyses of the main steam and main feedwater penetrations remain valid for the period of 

extended operation. 

4.6.2.2 Staff Evaluation 

The staff reviewed LRA Section 4.6.2 to verify, pursuant to 10 CFR 54.21(c)(1)(i), that the 

analyses remain valid for the period of extended operation. The main steam penetrations 

analyses, also applicable to the main feedwater penetrations, are based on BC-TOP-1 Loading 

Condition V thermal cycle events, which are directly dependent on startup-shutdown cycles, and 

Loading Condition IV events, which do not change with the licensed plant life. Based on plant 

operating experience, the applicant projected 250 Load Condition V thermal cycles for 60 years. 

The design basis equivalent usage factor for the 10 assumed condition IV events is 0.270, and 

the design basis equivalent usage factor for the original assumed 100 Condition V events is 
Time-Limited Aging Analyses 

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0.028. Using the projected 250 Condition V events, multiplied by a factor of 10 for a total of 

2500 cycles, the applicant calculated the equivalent usage factor: 

0.270 + (2500/100) x 0.028 = 0.970 < 1.0 

The staff finds the calculated usage factor of 0.97 near the acceptable limit of 1.0. However, the 

use of 2500 cycles in the analyses is conservative, and additional margin is available in the 

design. The staff finds that the calculations will remain valid during the period of extended 

operation in accordance with 10 CFR 54.21(c)(1)(i). 

4.6.2.3 Updated Final Safety Analysis Report Supplement 

The applicant provided a UFSAR supplement summary description of its TLAA evaluation of 

design cycles for the main steam and feedwater line penetrations in LRA Section A3.5. Based 

on its review of the UFSAR supplement, the staff concludes that the summary description of the 

applicant’s actions to address design cycles for the main steam and main feedwater line 

penetrations is adequate. 

4.6.2.4 Conclusion 

Based on its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(i), that for design cycles for the main steam and main feedwater line 

penetrations, the analyses remain valid for the period of extended operation. The staff also 

concludes that the UFSAR supplement contains an appropriate summary description of the 

TLAA evaluation, as required by 10 CFR 54.21(d). 

4.6.3 Design Cycles for the Recirculation Sump Suction Line Penetrations 

4.6.3.1 Summary of Technical Information in the Application 

LRA Section 4.6.3 summarizes the evaluation of design cycles for the recirculation sump 

suction line penetrations for the period of extended operation. The applicant stated that 

recirculation suction line penetrations were evaluated for ASME Code Section III, NE-3222.4(d) 

“Vessels Not Requiring Analysis for Cyclic Operation” exemption from fatigue analysis. The 

exemption criteria depend on the number of cycles for which loads are applied, therefore, the 

exemption is a TLAA. In this TLAA, the applicant noted that the analysis for the design cycles 

for the recirculation sump suction line penetrations 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 LRA Section 4.6.3 to verify pursuant to 10 CFR 54.21(c)(1)(i), that the 

analysis remains valid for the period of extended operation. The applicant stated that the 

analysis of the recirculation sump suction line penetrations was based on the alternating stress 

range for pressure cycles. The analysis demonstrated that the allowable number of cycles is 

1E+4, which is far greater than the number of cycles expected for the period of extended 

operation. The staff also reviewed NE-3222.4(d), “Vessels Not Requiring Analysis for Cyclic 

Operation,” to confirm that the fatigue analysis for theses penetrations is not required. The staff 

confirmed that a fatigue analysis is not required since the applicant met the requirements of 

NE-3222.4(d). The staff finds that the analyses will remain valid during the period of extended 

operation in accordance with 10 CFR 54.21(c)(1)(i). 

4.6.3.3 UFSAR Supplement 

The applicant provided a UFSAR supplement summary description of its TLAA evaluation of 

design cycles for the recirculation sump suction line penetrations in LRA Section A3.5.2. On the 

basis of its review of the UFSAR supplement, the staff concludes that the summary description 
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of the applicant's actions to address design cycles for the recirculation sump suction line 

penetrations are adequate. 

4.6.3.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(i), for design cycles for the recirculation sump suction line penetrations, that 

the existing analysis remains valid for the period of extended operation. The staff also 

concludes that the UFSAR supplement contains an appropriate summary description of the 

TLAA evaluation, as required by 10 CFR 54.21(d). 

4.7 Other Plant-Specific Time-Limited Aging Analyses

4.7.1 Load Cycle Limits of Cranes, Lifts, and Fuel Handling Equipment Designed to 

Crane Manufacturers Association of America Standard-70 

4.7.1.1 Summary of Technical Information in the Application 

In the LRA Section 4.7.1, the applicant provided a list of lifting machines to Crane 

Manufacturers Association of America (CMMA) standard 70 as follows. 

4.7.1.1.1 Cranes 

Containment Building Polar Crane. The applicant stated that the polar crane is designed to 

CMAA-70, Class A, with 225-ton main and 35-ton auxiliary hoists. The applicant also stated 

that the crane has three operational requirements: SG construction, plant operation, and SG 

removal. 

Cask Handling Crane. The applicant stated that the cask handling crane is an indoor electrical 

overhead traveling bridge crane with a single-failure-proof trolley. The main hoist is rated at 

150 tons, and the auxiliary hoist is rated at 15 tons. The applicant also stated that the 

cask-handling crane currently meets CMAA-70, service level A standards. 

SAFLIFTTM Strongback Canister Hoist. The applicant stated that the SAFLIFTTM strongback 

canister hoist is a combined 125-ton lift beam plus 50-ton single-failure-proof canister hoist. 

The applicant also stated that the SAFLIFTTM strongback canister hoist is designed to CMAA-70 

class C (2000), NUREG-0554 (1979), and NUREG-0612 Appendix C (1980) standards. 

New Fuel Handling Crane. The applicant stated that the new fuel handling crane is a CMAA-70 

service level C, 10-ton bridge crane. It is also used to perform activities associated with spent 

fuel reconstitution and re-caging. 

4.7.1.1.2 Fuel and Control Element Assembly Handling Machines 

Spent Fuel Handling Machine. The applicant stated that the spent fuel handling machine 

transfers fuel between the new fuel elevator, the transfer system, the spent fuel storage racks, 

and the spent fuel storage canister in the cask-loading pit. The applicant also stated that the 

specification requires design for 60,000 cycles of full speed hoist operation and 30,000 cycles of 

bridge and trolley operation. The hook capacity is 2,000 pounds. 

Refueling Machine. The applicant stated that the refueling machine moves fuel assemblies in 

and out of the core and between the core and the transfer system. The applicant also stated 

that the specification requires design for 60,000 cycles of full speed hoist operation and 

30,000 cycles of bridge and trolley operation. The hook load is limited to 2,600 pounds over 

“fuel only regions” and 1,600 pounds over “fuel plus hoist-box regions.” 

Control Element Assembly (CEA) Change Platform. The applicant stated that the CEA change 

platform is used to move the CEAs within the upper guide structure or between the upper guide 

structure and the CEA elevator. The applicant also stated that the specification requires design 
Time-Limited Aging Analyses 

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for 30,000 cycles of full speed operation. The hook capacity is 2,000 pounds. The CEA change 

platform is not expected to do any over-capacity lifts during its lifetime. 

Fuel Transfer System (i.e., Upenders, Trolley). The applicant stated that the fuel transfer 

system moves the fuel between the containment building and the fuel building through the 

transfer tube. The applicant also stated that the specification requires design for 10,000 cycles 

of operation, where one cycle consists of the transport and handling operations associated with 

the exchange of fuel assemblies between the fuel handling and containment buildings. The fuel 

transfer components are not expected to do any over-capacity transfers during their lifetime. 

New Fuel Elevator. The applicant stated that the new fuel elevator is used to introduce new fuel 

into the spent fuel pool so that it can be moved to the transfer system by the spent fuel-handling 

machine. The applicant also stated that the specification requires design for 20,000 cycles of 

operation, where one cycle is defined as one complete up and down movement of the elevator. 

The capacity is 2,000 pounds. The new fuel elevator is not expected to do any over-capacity 

lifts during its lifetime. 

CEA Elevator. The applicant stated that the CEA elevator is used to introduce new CEAs into 

the refueling pool and may be used to hold the spent CEAs while they are being disassembled 

for disposal. The applicant also stated that the specification requires design for 10,000 cycles of 

operation. The capacity is 2,000 pounds. The CEA elevator is not expected to do any 

over-capacity lifts during its lifetime. 

4.7.1.2 Staff Evaluation 

The staff reviewed LRA Section 4.7.1 to verify, pursuant to 10 CFR 54.21(c)(1)(i), that the 

analyses remain valid for the period of extended operation as follows. 

Polar Crane. The overhead crane in the containment (225-ton/35-ton) for reactor servicing 

operations is of the polar configuration and is seated on a girder bracketed off the containment 

wall. The polar crane is designed to CMAA-70, class A requirement. The crane, therefore, was 

designed to 100,000 maximum-rated load cycles for a 40-year life. 

The number of maximum rated load cycles for the polar crane originally projected for 40 years 

was 243. The number of maximum rated cycles for a 60-year life, based on 40 refueling 

outages, is 390. This is fewer than the 100,000 permissible cycles and, therefore, is 

acceptable. 

Cask Handling Crane. The cask handling crane is an indoor electrical overhead traveling bridge 

crane with a single failure proof trolley. The cask handling crane currently meets CMAA-70, 

service level A requirements. The crane, therefore, was designed to 100,000 maximum-rated 

load cycles for a 40-year life. 

The number of maximum rated load cycles for the cast handling crane originally projected for 

40 years was 864. The number of maximum rated cycles for a 60-year life, based on 

40 refueling outages, is 1,296. This is fewer than the 100,000 permissible cycles and, therefore, 

is acceptable. 

SAFLIFTTM Strongback Canister Hoist. The SAFLIFTTM strongback canister hoist is a combined 

125-ton lift beam plus 50-ton single-failure-proof canister hoist. The SAFLIFTTM strongback 

canister hoist is designed to CMAA-70 class C (2000), NUREG-0554 (1979), and NUREG-0612 

Appendix C (1980) standards. The SAFLIFTTM strongback canister hoist currently meets 

CMAA-70, service level C requirement. The hoist, therefore, was designed to 

500,000 maximum-rated load cycles for a 40-year life. 

The number of maximum rated load cycles for the hoist originally projected for 40 years was 

2,565. The number of maximum rated cycles for a 60-year life, based on 40 refueling outages, 

is 3,848. This is fewer than the 500,000 permissible cycles and, therefore, is acceptable. 
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New Fuel Handling Crane. The new fuel handling crane (10-ton) currently meets CMAA-70, 

service level C requirement. The new fuel handling crane, therefore, was designed to 

500,000 maximum-rated load cycles for a 40-year life. 

The number of maximum rated load cycles for the new fuel handling crane originally projected 

for 40 years was 13,770. The number of maximum rated cycles for a 60-year life, based on 

40 refueling outages, is 20,655. This is fewer than the 500,000 permissible cycles and, 

therefore, is acceptable. 

Spent Fuel Handling Machine. The spent fuel handling machine (2,000 pounds) currently meets 

CMAA-70, service level A requirements. The spent fuel handling machine, therefore, was 

designed to 100,000 maximum-rated load cycles for a 40-year life. 

The number of maximum rated load cycles for the spent fuel handling machine originally 

projected for 40 years was 43,389. The number of maximum rated cycles for a 60-year life, 

based on 40 refueling outages, is 65,084. This is fewer than the 100,000 permissible cycles 

and, therefore, is acceptable. 

Refueling Machine. The refueling machine hook load is limited to 2,600 pounds over “fuel only 

regions” and 1,600 pounds over “fuel plus hoist-box regions,” and it currently meets CMAA-70, 

service level A requirements. The refueling machine, therefore, was designed to 

100,000 maximum-rated load cycles for a 40-year life. 

The number of maximum rated load cycles for the refueling machine originally projected for 

40 years was 21,546. The number of maximum rated cycles for a 60-year life, based on 

40 refueling outages, is 32,319. This is fewer than the 100,000 permissible cycles and, 

therefore, is acceptable. 

CEA Change Platform. The hook of the CEA change platform capacity is 2,000 pounds and 

currently meets CMAA-70, service level A requirements. The refueling machine, therefore, was 

designed to 100,000 maximum-rated load cycles for a 40-year life. 

The number of maximum rated load cycles for the CEA change platform originally projected for 

40 years was 1,458. The number of maximum rated cycles for a 60-year life, based on 

40 refueling outages, is 2,187. This is fewer than the 100,000 permissible cycles and, therefore, 

is acceptable. 

Fuel Transfer System (i.e., Upenders, Trolley). The fuel transfer system moves the fuel 

between the containment building and the fuel building through the transfer tube. The fuel 

transfer system currently meets CMAA-70, service level A requirements. The fuel transfer 

system, therefore, was designed to 100,000 maximum-rated load cycles for a 40-year life. 

The number of maximum rated load cycles for fuel transfer system originally projected for 

40 years was 19,521. The number of maximum rated cycles for a 60-year life, based on 

40 refueling outages, is 29,282. This is fewer than the 100,000 permissible cycles and, 

therefore, is acceptable. 

New Fuel Elevator. The new fuel elevator (2,000 pounds) currently meets CMAA-70, service 

level A requirements. The new fuel elevator, therefore, was designed to 

100,000 maximum-rated load cycles for a 40-year life. 

The number of maximum rated load cycles for new fuel elevator originally projected for 40 years 

was 4,374. The number of maximum rated cycles for a 60-year life, based on 40 refueling 

outages, is 6,562. This is fewer than the 100,000 permissible cycles and, therefore, is 

acceptable. 
Time-Limited Aging Analyses 

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CEA Elevator. The CEA elevator (2,000 pounds) currently meets CMAA-70, service level A 

requirements. The CEA elevator, therefore, was designed to 100,000 maximum-rated load 

cycles for a 40-year life. 

The number of maximum rated load cycles for CEA elevator originally projected for 40 years 

was 729. The number of maximum rated cycles for a 60-year life, based on 40 refueling 

outages, is 1,094. This is fewer than the 100,000 permissible cycles and, therefore, is 

acceptable. 

4.7.1.3 Updated Final Safety Analysis Report Supplement 

The applicant supplied an UFSAR supplement summary description of its TLAA evaluation of 

load cycle limits of cranes, lifts, and fuel handling equipment to CMAA-70 in LRA 

Section A3.6.1. Based on its review of the UFSAR supplement, the staff concludes that the 

summary description of the applicant’s actions to address crane load cycles is adequate. 

4.7.1.4 Conclusion 

Based on its review, as discussed above, the staff concludes that the applicant has 

demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that for load-cycle limits of cranes, lifts, and 

fuel handling equipment to CMAA-70, the analyses remain valid for the period of extended 

operation. The staff also concludes that the UFSAR supplement contains an appropriate 

summary description of the TLAA evaluation, as required by 10 CFR 54.21(d). 

4.7.2 Absence of Time-Limited Aging Analyses for Metal Corrosion Allowances and 

Corrosion Effects 

The staff reviewed LRA Section 4.7.2 to verify that the metal corrosion allowances analysis is 

not a TLAA. The staff’s evaluation is found in SER Section 4.1.3.1.1. 

4.7.3 Inservice Flaw Growth Analyses that Demonstrate Structural Stability for 40 Years 

4.7.3.1 Summary of Technical Information in the Application 

Defects discovered by ISI or component failures may be repaired or replaced to restore the 

basis of the original design analysis, may be repaired or replaced to a different configuration, or 

may be analyzed to confirm that the as-found condition is acceptable. For ASME components, 

ASME Code Section XI controls these activities. A flaw analysis of a Class 1 component 

usually requires a fatigue crack growth analysis, which is a TLAA if it qualifies the component for 

the plant design life. A thorough review of the PVNGS licensing basis, supported by interviews 

with plant staff familiar with the history of Class 1 components, found the following TLAA 

evaluations of indications discovered during ISIs: 

 A linear elastic fracture mechanics fatigue crack growth analysis of indications in a Unit 2 

pressurizer support skirt-forging weld as discussed in Section 4.3.2.4 and similar 

evaluations of postulated (rather than actual) initial defects 

 Crack growth and fracture mechanics stability analyses of postulated defects in original 

heater sleeve attachment welds remaining in the pressurizer lower heads following 

heater sleeve replacements as discussed in Section 4.3.2.4 

 Fatigue crack growth and fracture mechanics stability analyses in support of pressurizer 

nozzle overlays as discussed in Section 4.3.2.4 

 Fatigue crack growth and fracture mechanics stability analyses in support of hot leg 

surge and shutdown cooling nozzle weld overlays as discussed in Section 4.3.2.7 
Time-Limited Aging Analyses 

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 Fatigue crack growth assessments and fracture mechanics stability analyses in support 

of the LBB evaluation, but no TLAAs (Section 4.3.2.15) 

 Fatigue crack growth and fracture mechanics stability analyses of half-nozzle repairs to 

alloy 600 materials in reactor coolant hot legs as discussed in Section 4.7.4 

4.7.3.2 Staff Evaluation 

The staff’s evaluation for Sections 4.3.2.4, 4.3.2.7, 4.3.2.15, and 4.7.4 can be found in the 

corresponding sections of this SE. 

4.7.3.3 Updated Final Safety Analysis Report Supplement 

The UFSAR supplement for Sections 4.3.2.4, 4.3.2.7, and 4.7.4 can be found in the 

corresponding sections in the staff’s SE. 

4.7.3.4 Conclusion 

The staff's conclusions on these fatigue analyses are found in SER Sections 4.3.2.4, 4.3.2.7, 

4.3.2.15 and 4.7.4. 

4.7.4 Fatigue Crack Growth and Fracture Mechanics Stability Analyses of Half-Nozzle 

Repairs to Alloy 600 Material in Reactor Coolant Hot Legs and Supporting 

Corrosion Analyses 

4.7.4.1 Summary of Technical Information in the Application 

The applicant stated that for the half-nozzle repair of the Alloy 600 nozzles in the hot leg, the 

staff authorized a RR for the flaw removal and successive inspection requirements of the 

1992 edition and addenda of the ASME Code Section XI, IWA-3300 and IWB-2420 for the 

alternative half-nozzle method used to repair Alloy 600 small-bore nozzles in the hot leg. 

LRA Section 4.7.4 states that as part of the RR, the applicant was required to perform a fatigue 

crack growth calculation, flaw stability analysis, and corrosion analysis. The applicant 

recognized, however, that the RR permitting these repairs was granted only through the fourth 

10-year inspection interval, and must, therefore, be extended for the period of extended 

operation. The safety determination supporting this ASME Code exemption is also supported 

by a commitment to track time at cold shutdown conditions, which must also be continued for 

the period of extended operation. 

The corrosion analysis in the hot leg piping walls exposed by the repairs, depends on time at 

cold shutdown. The original LRA Section 4.7.4 concluded that the corrosion analysis is not a 

TLAA since the analysis was extended beyond 60 years. As evaluated below, LRA Amendment 

19 changed the evaluation to a TLAA, to be dispositioned per 10 CFR 54.21(c)(1)(i), that the 

analysis remains valid for the period of extended operation. 

Fatigue crack growth and flaw stability analyses of nozzle remnants and welds left in the hot leg 

depend on the number of heatup, cooldown, and OBE cycles assumed for a 40-year life. These 

analyses are, therefore, TLAAs. The LRA dispositions these TLAAs per 10 CFR 54.21(c)(1)(iii), 

that the effects of aging on the intended function of the hot leg half-nozzle repairs will be 

managed during the period of extended operation 

4.7.4.2 Staff Evaluation 

The staff reviewed LRA Section 4.7.4 to verify, per 10 CFR 54.21(c)(1)(i) that, for the fatigue 

crack growth and flaw stability analyses of half-nozzle repairs to Alloy 600 material in reactor 

coolant hot legs, the effects of aging on the intended function will be adequately managed for 

the period of extended operation. In addition, the staff reviewed LRA Section 4.7.4 to verify that 

the corrosion analyses in support of half-nozzle repairs to the hot legs are not TLAAs. 
Time-Limited Aging Analyses 

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During the staff’s review, the staff noted that the applicant dispositioned ASME Code Section XI 

supplemental fatigue flaw growth or cycle-dependent fracture mechanics evaluations in 

accordance with 10 CFR 54.21(c)(1)(iii). The applicant proposed to use the CC activities from 

its enhanced Metal Fatigue Program to manage the effects of aging and verify the continued 

validity of these ASME Code Section XI analyses during the period of extended operation. 

The staff noted that the applicant’s proposal to use CC activities to verify the continued validity 

of these ASME Code Section XI analyses may be beyond the applicant’s CLB. The staff noted 

that TS 5.5.5 and UFSAR Section 3.9.1.1 discuss cycle tracking and counting against design 

limits and design calculations, but does not appear to discuss design transient tracking and 

counting for ASME Code Section XI supplement fatigue flaw growth or cycle dependent fracture 

mechanics evaluations. Per TS 5.5.5 and UFSAR Section 3.9.1.1, cyclic and transient 

occurrences are tracked to ensure that components are maintained within the design limits. 

However, the applicant’s CC procedure does not discuss the types of analyses this requirement 

is applicable to or the action limits and corrective actions that may be taken for these fatigue 

related or fracture mechanics evaluations. The staff noted that these corrective actions should 

be specified in the applicant’s procedures and the action limits and corrective actions should be 

associated with the specific type of analysis. 

The staff held a teleconference with the applicant on September 22, 2010, for clarification on 

how design basis transient cycle tracking and counting activities are accounted for in the CLB 

for ASME Code Section XI supplemental fatigue flaw growth or cycle dependent fracture 

mechanics evaluations. The staff also discussed the applicant's justification of the use of 

design basis transient cycle tracking and counting activities as the basis to disposition the 

ASME Code Section XI analyses in LRA Section 4.7.4 in accordance with 

10 CFR 54.21(c)(1)(iii). 

By letter dated October 13, 2010, the applicant stated that although the cycle tracking and 

counting activities of design basis transients for these evaluations are not explicitly described in 

the CLB today, the applicant recognizes the benefit of enhancing the UFSAR and the plant 

design transient tracking procedure to provide this guidance. The applicant recognized the 

importance of providing explicit procedures to assist an analyst if a design transient assumption 

or CUF limit is approached. Consequently, by letter dated October 13, 2010, the applicant 

committed (Commitment No. 60) to complete the following by November 30, 2010: 

The reactor coolant system transient and cycle tracking procedure 73ST-9RC02 

and UFSAR Section 3.9.1 will be enhanced to discuss corrective actions that 

need to be taken prior to ASME Code Section III fatigue design limits being 

exceeded and to state that corrective actions may be required for other 

fatigue-related analyses, such as certain ASME Code Section XI supplemental 

fatigue flaw growth or cycle-dependent fracture mechanics evaluations that are 

dependent on the number of occurrences of design transients. 

Based on its review, the staff finds the applicant’s clarification and Commitment No. 60 

acceptable because the applicant recognized that its CLB does not currently account for design 

basis transient cycle tracking activities for ASME Code Section XI supplemental fatigue flaw 

growth or cycle-dependent fracture mechanics evaluations and has committed to update its 

UFSAR and cycle tracking procedure to account for these evaluations and associated corrective 

actions. Further, the staff concludes that the applicant has demonstrated that the effects of 

aging will be managed for the fatigue crack growth calculation, flaw stability analysis, and 

corrosion analysis of half-nozzle repairs to Alloy 600 material in reactor coolant hot legs. 
Time-Limited Aging Analyses 

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4.7.4.2.1 Absence of Time-Limited Aging Analysis in Corrosion Analyses for Hot Leg 

Half-Nozzle Repairs 

LRA Section 4.7.4 concluded that the corrosion analyses in support of hot leg half-nozzle 

repairs are not TLAAs. By letter dated July 7, 2010, the applicant submitted LRA 

Amendment 19 which identified the corrosion analyses for hot leg half nozzle repairs as TLAAs 

and dispositioned them in accordance with 10 CFR 54.21(c)(1)(i). 

The applicant stated that in March 2004, Westinghouse Electric released a topical report 

approved by staff as WCAP-15973-P-A, “Low-Alloy Steel Component Corrosion Analysis 

Supporting Small-Diameter Alloy 600/690 Nozzle Repair/Replacement Programs, and 

calculation CN-CI-02-71, Summary of Fatigue Crack Growth Evaluation Associated with Small 

Diameter Nozzles in CEOG Plants.” These documents support half nozzle and MNSA repairs in 

CE plants. 

On March 25, 2005, the applicant submitted Relief Request RR-31 for the repair of RCS hot leg 

small-bore nozzle repair for NRC review and approval. By letter dated May 5, 2005, the staff 

authorized RR-31 (ADAMS Accession No. ML051290123). This relief request uses 

CN-CI-02-71 and WCAP-15973-P-A in support of a request for exemption from the flaw removal 

and successive inspection requirements of ASME Code Section XI (1992), Sections IWA-3300 

and IWB-2420, for the alternative half-nozzle method used for the ten Unit 2 small-bore, hot leg 

nozzles to be repaired during the spring 2005 refueling outage. WCAP-15973-P-A calculated 

corrosion rates of 1.53 mils-per-year for Alloy 600 nozzles. In response to the conditions of the 

final SE for the Westinghouse topical report, the applicant calculated that a limiting corrosion 

rate of 1.377 mils-per-year for Unit 3 would not exceed the allowable diameter until 2058, 

60 years after the repair and 10 years after the end of the period of extended operation. The 

LRA stated that this calculation is not a TLAA since it does not meet the criterion of 

10 CFR 54.3(a)(3) and is valid for the period of extended operation. The applicant stated in the 

LRA that the corrosion rate for Unit 3 is limiting for all three units and bounds the corrosion rates 

of Units 1 and 2. 

In the relief request submittal, the applicant made an ongoing commitment to track the time at 

cold shutdown conditions: 

APS commits to continue to track the time at cold shutdown conditions against 

the assumptions made in the corrosion analysis to assure that the allowable bore 

diameter is not exceeded over the life of the plant. If the analysis assumptions 

are exceeded, APS shall provide a revised analysis to the staff and provide a 

discussion on whether volumetric inspection of the area is required. 

This commitment was made because the corrosion rate at cold shutdown conditions is 

significantly higher than at operating conditions. This request was authorized by the staff, 

consistent with the APS commitment, and is valid for the second, third, and fourth 10-year 

inspection intervals. The applicant states in LRA Section 4.7.4 that an extension of this 

authorization will be required for continued relief from the ASME Code sections. 

The provisions of 10 CFR 54.3(a)(3) state that TLAAs “[i]nvolve time-limited assumptions 

defined by the current operating term, for example, 40 years.” The estimated life of 60 years 

after the repair and 10 years after the end of the extended period operation for the hot leg 

nozzles is a calculated result using the WCAP-15973-P-A corrosion methodology, not an 

assumption adopted in the methodology. Further, the WCAP states, “[t]he following 

assumptions were used in developing an overall corrosion rate for carbon and low alloy steels in 

a crevice environment and an estimate of the total corrosion for the remaining plant lifetimes...” 

This statement strongly suggested that the corrosion rate is based on test data considering 

operating experience and assumed valid for 40 years. The applicant’s July 7, 2010, response to 

RAI 4.7.5-1 amended LRA Section 4.7.4 to identify the evaluation of the corrosion analysis for 
Time-Limited Aging Analyses 

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the hot leg half-nozzle repairs as a TLAA, with a disposition in accordance with 

10 CFR 54.21(c)(1)(i), that the corrosion analysis is valid for the period of extended operation. 

 The applicant supported this disposition by citing bounding calculations that demonstrate that 

the analyses are valid beyond the period of extended operation. 

LRA Section 4.7.4 states that the applicant committed to monitoring the cold shutdown 

conditions against the assumptions made in the corrosion analysis to assure that the allowable 

bore diameter is not exceeded over the life of the plant for the second, third, and fourth 10-year 

inspection intervals. By letter dated February 14, 2010, the staff issued RAI 4.7.4-1, asking the 

applicant to discuss whether the same commitment will be implemented in the fifth and sixth 

inspection intervals. 

The applicant's March 1, 2010, response to RAI 4.7.4-1 stated that LRA Appendix A, 

Table A4-1, Commitment No. 46, documents the applicant’s commitment to continue to monitor 

the cold shutdown conditions via the current tracking method for the period of extended 

operation, that is, for the fifth and sixth inspection intervals. The staff verified that LRA 

Appendix A, Table A4-1, Commitment No. 46 provides the requirement to monitor the cold 

shutdown conditions for the period of extended operation. Therefore, the staff finds that the 

structural integrity of the repaired small-bore nozzles will be maintained during the period of 

extended operation. The staff’s concern in RAI 4.7.4-1 is resolved. 

Because the estimated repair lifetime for the hot leg nozzle repairs exceeds 60 years and the 

operational assumptions will be monitored by Commitment No. 46, the staff concludes that the 

applicant’s analysis is acceptable per 10 CFR 54.21(c)(1)(i). The staff also concludes that the 

bore diameter of the repaired nozzles will have adequate dimensions, and the bore will not be 

degraded by corrosion through the period of extended operation. 

4.7.4.2.2 Fatigue Crack Growth and Stability Analysis for Hot Leg Half-Nozzle Repairs 

Westinghouse calculation CN-CI-02-71 found that postulated defects left in remnants of the hot 

leg nozzles would not grow beyond an acceptable size, assuming 500 heatup and cooldown 

cycles and 200 OBE cycles, which are the design basis limiting cycles for a 40-year life. The 

CN-CI-02-71 fatigue crack growth and stability analysis is, therefore, identified in the LRA as a 

TLAA and dispositioned per 10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended 

function of the hot leg half-nozzle repairs will be managed during the period of extended 

operation. To manage the effects of aging for this TLAA, the applicant will carry out the 

enhanced metal fatigue program to monitor the transient cycles in the analysis during the period 

of extended operation to ensure that appropriate re-evaluation or other corrective action is 

initiated if an action limit is reached. The staff finds that the TLAA is acceptable to manage the 

crack growth and stability analysis of the half nozzle repairs of small-bore nozzles per 

10 CFR 54.21(c)(1)(iii). 

4.7.4.2.3 Extension to All Hot Leg Small-Bore Nozzles 

After reconciling the WCAP 15973-P-A topical report with the non-Westinghouse documentation 

that it had originally used as a basis, the applicant submitted Revision 1 to RR 31 in a letter 

dated August 16, 2005. RR 31, Revision 1 added the 63 previously repaired small-bore hot leg 

nozzles in all three units to those already covered in the initial RR. By letter dated 

September 12, 2006, the staff approved RR 31, Revision 1. All of the small diameter hot leg 

nozzles have been replaced. PVNGS has 27 small diameter hot leg penetrations per unit, as 

described in Section IV of RR 31, Revision 1. 

LRA Section 4.7.4, Subsection “Extension to All Hot Leg Small-Bore Nozzles,” states that the 

63 previously repaired small-bore hot leg nozzles in all three units were added to RR 31. The 

applicant also stated there are 27 small-bore hot leg penetrations per unit. If there are 

27 small-bore nozzles in each unit, the total number of small-bore nozzles in all three units 
Time-Limited Aging Analyses 

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should be 81. It is not clear whether the exact number of small-bore nozzles on the hot leg 

piping is 63 or 81. By letter dated February 14, 2010, the staff issued RAI 4.7.4-2, asking the 

applicant to provide the exact number of small-bore nozzles in the hot leg piping in each unit, 

the number of small-bore nozzles that have been repaired in each unit, and the number of 

small-bore nozzles that have not been repaired. The applicant was also asked to discuss 

whether any small-bore nozzles in hot leg piping that are not covered under RR 31 and to 

confirm that the small-bore nozzles in hot leg piping that are not covered under RR 31 were 

analyzed for TLAA criteria. 

The applicant's March 1, 2010, response to RAI 4.7.4-2 clarified and itemized the number of 

small-diameter hot leg penetrations in each unit with respect to Revisions 0 and 1 of RR 31 as 

shown below: 

8 Unit 2 nozzles repaired in 1991 via a full nozzle repair (not covered under 

 RR 31) 

10 Unit 2 nozzles repaired in 2005 under RR 31, Revision 0 

9 Unit 2 nozzles repaired under RR 31, Revision 1 

27 Unit 1 nozzles repaired under RR 31, Revision 1 

27 Unit 3 nozzles repaired under RR 31, Revision 1

81 Total 

All 81 nozzles in all three units have been either repaired or replaced. As shown above, some 

of the nozzle repairs were covered under RR 31, Revision 0, and some of them were covered 

under RR 31, Revision 1. RR 31, Revision 0, addressed 10 nozzles replaced in Unit 2 during 

the spring of 2005. RR 31, Revision 1, added the following previously repaired Alloy 600 

small-bore hot leg nozzles as follows: 

Unit 1 27 nozzles 

Unit 2 9 nozzles 

Unit 3 27 nozzles

Total 63 nozzles 

The last 63 nozzles covered by RR 31, Revision 1 were initially repaired under the Alloy 600 

replacement program, from approximately October 1999 to April 2003. The staff notes that the 

63 nozzles are part of the total 81 nozzles in all three units. 

RR 31 does not cover the eight Unit 2 nozzles repaired in 1991 by a full nozzle repair. They 

were repaired in accordance with the ASME Code. The fatigue crack growth analysis and 

corrosion analysis are not applicable for these eight nozzles because they were repaired with a 

new, full-length nozzle. LRA Section 4.3.2.7 addresses the TLAAs associated with the design 

of the eight Unit 2 full nozzle repairs. In addition, the detailed list of the nozzle and the repair 

methods are provided in the response to RAI 4.3.2.7-4 as discussed in Section 4.3.2.7.2 of 

this SE. 

The staff finds that the applicant has clarified the number of small-bore nozzles in the RCS 

primary loop piping that have been repaired. Also, the applicant has committed in Commitment 

No. 46 to monitor the bore diameter of the small-bore nozzle repairs in the RCS primary loop 

piping and to monitor cold shutdown conditions. Therefore, the repaired 81 nozzles in all 

three units will be monitored as a part of TLAA per 10 CFR 54.21(c)(1)(iii). The staff’s concerns 

in RAI 4.7.4-2 are resolved. 

4.7.4.3 Updated Final Safety Analysis Report Supplement 

The applicant provided an amended UFSAR supplement summary description of its TLAA of the 

fatigue crack growth and fracture mechanics stability analyses of half-nozzle repairs to Alloy 600 

material in reactor coolant hot legs in LRA Section A3.6.2. Based on its review of the UFSAR 
Time-Limited Aging Analyses 

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supplement in LRA Section A3.6.2, the staff concludes that the summary description of the 

applicant’s actions is adequate. 

to address the TLAA for the half-nozzle repairs to Alloy 600 material in reactor coolant hot legs 

is adequate. 

4.7.4.4 Conclusion 

Based on its review, the staff concludes that, pursuant to 10 CFR 54.21(c)(1)(i), the applicant 

has demonstrated that the TLAA associated with the corrosion analyses of hot leg half-nozzle 

repairs remain valid for the period of extended operation. Further, the staff concludes that, 

pursuant to 10 CFR 54.21(c)(1)(iii), the applicant has demonstrated that the effects of aging on 

the intended function of the hot leg half-nozzle repairs will be adequately managed for the 

period of extended operation. The UFSAR supplement contains an appropriate summary 

description of the TLAA evaluations as required by 10 CFR 54.21(d). 

4.7.5 Corrosion Analyses of Pressurizer Ferritic Materials Exposed to Reactor Coolant 

by Half-Nozzle Repairs of Pressurizer Heater Sleeve Alloy 600 Nozzles 

4.7.5.1 Summary of Technical Information in the Application 

LRA Section 4.7.5 summarizes the evaluation of the general corrosion of pressurizer ferritic 

materials exposed to reactor coolant as a result of half-nozzle repairs for all heater sleeves. 

The applicant stated that the bounding case for general corrosion in pressurizer heater sleeves 

in the WCAP-15973-P-A report, “Low Alloy Steel Component Analysis Supporting Small 

Diameter Alloy 600/690 Nozzle Repair/Replacement Program,” provided an estimated repair life 

of 194 years; therefore, the applicant stated that the analysis is valid for the period of extended 

operation. The applicant further concluded that the corrosion analysis is a TLAA. 

4.7.5.2 Staff Evaluation 

The staff’s evaluation of the general corrosion analysis supporting half-nozzle repairs of 

small-diameter Alloy 600/690 nozzles was documented in an SE, dated January 12, 2005, for 

the WCAP-15973-P-A report. The staff’s evaluation of the plant-specific application of the 

WCAP-15973-P-A report, including its corrosion analysis, to pressurizer heater sleeves was 

documented in an SE dated November 5, 2004, for Relief Request RR-29. The plant-specific 

application was approved for the second 10-year ISI interval. However, since the time period 

accepted and approved by the staff for the corrosion analysis was the second 10-year ISI 

interval, applicability of the WCAP-15973-P-A report to the extended period of operation has not 

been established. Further, the original version of LRA Section 4.7.5 concluded that the 

corrosion analysis is not a TLAA. The staff issued RAI 4.7.5-1, asking the applicant to identify 

the plant-specific submittal addressing general corrosion in support of the half-nozzle repairs 

installed in the pressurizer heater sleeves. 

The applicant’s response to RAI 4.7.5-1, dated March 1 and May 21, 2010, provided 

plant-specific operating data and calculations, demonstrating that the WCAP-15973-P-A 

corrosion results are applicable for the period of extended operation. To ensure that the 

operation at the period of extended operation will be consistent with the current operating data, 

the applicant committed (Commitment No. 46) to continue “the cold shutdown time monitoring 

program [using the current tracking method]” for the period of extended operation. Since the 

estimated repair lifetimes for the pressurizer heater sleeve nozzles is bounded by the generic 

194 years by a significant margin and the operation assumptions will be monitored by 

Commitment No. 46, the staff concludes that the applicant’s analysis is acceptable. Therefore, 

the analysis meets the requirements of 10 CFR 54.21(c)(1)(i) and will ensure that the repaired 

nozzles will have adequate dimensions through the period of extended operation. 
Time-Limited Aging Analyses 

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The staff considers the WCAP-15973-P-A corrosion analysis a TLAA because assumptions 

were used in developing the overall corrosion rate for carbon and low alloy steels in a crevice 

environment to estimate the total corrosion for the remaining 40-year plant lifetime. The 

July 7, 2010, response provided an LRA revision concluding that the corrosion analysis is a 

TLAA. The staff’s concerns in RAI 4.7.5-1 are resolved. 

4.7.5.3 Updated Final Safety Analysis Report Supplement 

The applicant provided a revised UFSAR supplement summary description of its TLAA 

evaluation of the corrosion analyses of pressurizer ferritic materials exposed to reactor coolant 

by half-nozzle repairs of pressurizer heater sleeve Alloy 600 nozzles in LRA Section A.3.6.4. 

Based on its review of the UFSAR supplement, the staff concludes that the summary 

description of the applicant’s actions to address the subject is adequate. 

4.7.5.4 Conclusion 

On the basis of its review, as discussed above, the staff concludes that the applicant has 

demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that, for the general corrosion of ferritic 

materials exposed to reactor coolant as a result of half-nozzle repairs to pressurizer heater 

sleeves, the analyses remain valid for the period of extended operation. The staff also 

concludes that the UFSAR supplement contains an appropriate summary description of the 

TLAA evaluation, as required by 10 CFR 54.21(d). 

4.7.6 Absence of a Time-Limited Aging Analysis for Reactor Vessel Underclad Cracking 

Analyses 

The staff reviewed LRA Section 4.7.6 to verify that the reactor vessel underclad cracking 

analysis is not a TLAA. The staff’s evaluation is found in SER Section 4.1.3.1.2. 

4.7.7 Absence of a Time-Limited Aging Analysis for a Reactor Coolant Pump Flywheel 

Fatigue Crack Growth Analysis 

The staff reviewed LRA Section 4.7.7 to verify that the RCP flywheel fatigue crack growth 

analysis is not a TLAA. The staff’s evaluation is found in SER Section 4.1.3.1.3. 

4.7.8 Building Absolute or Differential Heave or Settlement, Including Possible Effects 

of Changes in Perched Groundwater Lens 

4.7.8.1 Summary of Technical Information in the Application 

LRA Section 4.7.8 summarizes building absolute or differential heave or settlement, including 

possible effects of changes in the perched groundwater lens. The applicant described the 

perched groundwater lens as a locally elevated region of groundwater above an impermeable 

layer, charged by irrigation before construction. An increase in the water level of this lens above 

the foundation elevations could affect stability, and a decline in the water level could 

conceivably result in building settlement that exceeds expectations. The applicant stated that 

groundwater monitoring data shows no potential for settlement due to changes in groundwater 

level. The original projections of increases in groundwater levels described in UFSAR 

Section 2.4.13.2.4.D were very conservative, and the conclusion of foundation stability remains 

valid through the period of extended operation. 

UFSAR Section 2.5.4.10.2 documents the applicant’s general analysis and evaluation of 

building heave and settlement. Settlement of major structures is monitored during the current 

license term on a frequency of five years and will continue through the life of the plant. The 

settlement surveillance is done as a part of the Structures Monitoring Program described in LRA 

Section B2.1.32. The staff’s evaluation of the program is found in SER Section 3.0.3.2.20. This 

program provides the requirements to measure settlement of each individual structure and 
Time-Limited Aging Analyses 

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differential settlement at a common point between any two adjacent structures having critical 

connections as well as containment tilt angle. The post-construction settlement acceptance 

criteria for each individual structure are as follows: 

 The post-construction settlement is less than 1.5 inches. 

 Post-construction differential settlement at a common point between any two adjacent 

structures having critical connections is less than 0.5 inch. 

 The post-construction containment tilt angle is less than 0.057 degrees. 

The applicant stated that the first action limit is 90 percent of each acceptance criterion and 

requires an increase in survey frequency and, if necessary, a remedial action. 

The applicant stated that the largest short-term, post-construction differential settlement (as of 

1984) measured between any two category I structures was 0.3 inches. LRA Table 4.7-2 

summarizes the results of 2003 settlement monitoring inspections. The results show that 

post-construction differential settlement between the Unit 2 auxiliary and radwaste buildings 

exceeds the maximum allowable 0.5 inches. The table shows that the measured 

post-construction differential settlement at Units 1 and 3 is nearly 90 percent of the maximum 

allowable value of 0.5 inches. The applicant said that the increased monitoring frequency 

verified that a significant trend of settlement or differential settlement was not occurring. The 

frequency has since been reduced to the normal frequency of five years. 

4.7.8.2 Staff Evaluation 

The staff reviewed LRA Section 4.7.8 to verify, pursuant to 10 CFR 54.21(c)(1)(i), that the 

original projection of changes in groundwater level remain valid through the period of extended 

operation. The staff also reviewed LRA Section B2.1.32 to confirm that, pursuant to 

10 CFR 54.21(c)(1)(iii), settlement of structures in the scope of license renewal will be 

adequately managed during the period of extended operation to ensure their intended functions 

are maintained consistent with the CLB. In its review of LRA Sections 4.7.8, A3.6.3, and A1.32 

and UFSAR Sections 2.4.13 and 2.5.4, the staff determined that additional information, 

described below, is needed to complete its review. 

LRA Section 4.7.8 describes the affect of perched groundwater level increase or decrease on 

foundation stability and settlement. The applicant stated that the perched groundwater levels 

will not exceed the levels assumed for building foundation designs and will, therefore, not affect 

building stability. The applicant explained that the only potential sources of significant recharge 

of the perched groundwater lens near the units are the 85-acre and 45-acre reservoirs and 

noted that the reservoirs were lined in 2006 with a double liner system that should prevent any 

future recharge of the shallow aquifer from the reservoirs. The applicant also noted that the 

wells near the reservoirs have not yet shown any effects of increased leakage to the 

groundwater. 

In reviewing the above information, the staff was unclear whether the applicant credits 

monitoring of the perched groundwater level and the double liner system for evaluation of the 

TLAA in addition to settlement monitoring activities conducted in accordance with its Structures 

Monitoring Program. 

In a conference call dated February 24, 2010, the applicant clarified that the discussion on the 

perched groundwater lens level and the double liner system was provided as additional 

information. The applicant’s monitoring of the groundwater lens and the reservoirs’ double liner 

system are not credited for settlement. Only the settlement monitoring activities conducted in 

accordance with the Structures Monitoring Program are credited for managing aging of 

structural settlement during the period of extended operation. The staff found the applicant’s 

clarification acceptable because the implementation of settlement monitoring activities 
Time-Limited Aging Analyses 

 4-106 

described in the Structures Monitoring Program provides reasonable assurance that the affect 

of groundwater level increase or decrease on settlement of structures will be detected before a 

loss of an intended function. 

LRA Section 4.7.8 states that the Structures Monitoring Program monitors on 5-year intervals 

the foundation responses and ground movement of “major structures.” A review of the 

applicant’s Structures Monitoring Program showed that similar wording is included in the 

program description. The applicant did not specify, however, which structures would be 

monitored during the period of extended operation and whether the inspection frequency will be 

adjusted, as described in UFSAR Section 2.5.4.13, if post-construction settlement reaches 

90 percent of the design criteria values. As a result, the staff issued RAI 4.7.8-1 asking the 

applicant to supply a list of structures within the scope of license renewal that will be monitored 

for the effects of settlement during the period of extended operation and justify excluding any 

structure from settlement monitoring that is within the scope of license renewal. The RAI also 

asked that the applicant supply a list of structures, included in the scope of 10 CFR 54.4, that 

will be monitored on a different frequency or using different instrumentation than specified in the 

UFSAR, Section 2.5.4.13 and Table 2.5-19. 

By letter dated April 1, 2010, the applicant responded to RAI 4.7.8-1 stating that all structures 

that are within the scope of license renewal in accordance with 10 CFR 54.4(a)(1) or (2), are 

listed in LRA Table 2.2-1. The applicant further stated that the structures will be monitored for 

settlement consistent with the frequency (every five years) and instrumentation specified in 

UFSAR Section 2.5.4.13 and Table 2.5-19 during the period of extended operation. The 

five-year frequency will be maintained during the period of extended operation unless a more 

frequent monitoring periodicity is required based on inspection results. 

The applicant went on to state that the fire water pump house, the transformer foundations, and 

the station blackout (SBO) generator structures, which are in scope of license renewal pursuant 

to 10 CFR 54.4(a)(3), are not in the scope of the settlement program described in UFSAR 

Section 2.5.4.13. These structures will be visually monitored for aging effects due to settlement 

on a 10-year frequency during the period of extended operation, in accordance with the 

Structures Monitoring Program. 

The staff found the applicant’s response acceptable for the structures within the scope of 

license renewal in accordance with 10 CFR 54.4(a)(1) or (a)(2) because settlement will be 

monitored in accordance with the UFSAR requirements during the period of extended operation. 

For structures within the scope license renewal, pursuant to 10 CFR 54.4(a)(3), the staff 

questioned how visual inspections performed in accordance with the Structures Monitoring 

Program will provide the data necessary to trend settlement and differential settlement of the fire 

water pump house, the transformer foundations, and the SBO generator structures. In a 

conference call dated May 14, 2010, the applicant was asked to give more details on whether 

settlement of the fire water pump house, the transformer foundations, and the SBO generator 

structures is within the scope of this TLAA. If it is, the applicant was asked to explain how visual 

inspections conducted on a 10-year frequency in accordance with the Structures Monitoring 

Program will effectively manage the effects of settlement as required by 10 CFR 54.21(c)(1)(iii). 

By letter dated May 21, 2010, the applicant supplemented its response to RAI 4.7.8-1(b) and 

stated that the fire water pump house, the transformer foundations, and the SBO generator 

structures are not within the scope of the TLAA for settlement monitoring described in UFSAR 

Section 2.5.4.13 because the structures are not incorporated by reference in UFSAR 

Section 2.5.4.13. Therefore, they do not meet the criterion of 10 CFR 54.3(a)(6). The staff finds 

the applicant’s response acceptable because settlement of these structures does not meet 

TLAA criterion 10 CFR 54.3(a)(6). The staff’s concerns in RAI 4.7.8-1 are resolved. 
Time-Limited Aging Analyses 

 4-107 

LRA Section 4.7.8, Table 4.7-2 provides the 2003 summary results of the settlement monitoring 

program. The results show that the measured containment building tilt angle and the measured 

post-construction settlement are less than the maximum allowable values; however, the 

measured post-construction differential settlement of 0.8748 inches between the Unit 2 auxiliary 

and the radwaste buildings exceeds the maximum allowable value of 0.5 inches. In addition, 

the post construction differential settlement of Units 1 and 3 between the auxiliary building and 

the radwaste building is about 90 percent of the maximum allowable value of 0.5 inches. By 

letter dated March 2, 2010, the staff issued RAI 4.7.8-2 asking the applicant to provide 1998 and 

2008 settlement data for locations provided in the Table 4.7-2 with the 2003 results. In addition, 

the staff asked the applicant to describe the corrective actions taken to address the affect of 

exceeding the maximum allowable post-construction differential settlement on Unit 2 structures 

and critical piping. 

By letter dated April 1, 2010, the applicant provided 1997 and 2010 post-construction settlement 

and post-construction differential settlement summary results in response to RAI 4.7.8-2. The 

applicant stated the 1998 settlement measurements were taken in 1997, and the 2008 

measurements were taken in 2010 as permitted by an established 25-percent grace period for 

the five-year frequency. 

The staff reviewed the tabulated 1997, 2003, and 2010 settlement measurement data and 

observed that Units 1, 2, and 3 post-construction settlement continues to show a slightly 

increasing trend. However, the measured post-construction total settlement remains below the 

maximum allowable limit of 1.5 inches. The 2010 Unit 1 measured post-construction settlement 

of 1.3524 inches exceeds the action limit of 1.35 inches established in UFSAR Section 2.5.4.13. 

As a result, the applicant increased the inspection frequency to one-month intervals, as 

specified in UFSAR Section 2.5.4.13. The staff’s review of the data noted no significant 

changes in total post-construction differential settlement between 1997 and 2010. The 

measured differential settlement remains below the maximum allowable limit of 0.5 inches, 

except between the Unit 2 auxiliary and radwaste buildings. The applicant stated that corrective 

actions were taken as required by UFSAR Section 2.5.4.13 as a result of exceeding the 

maximum allowable limit. The staff finds the applicant’s response acceptable because the 

1997, 2003, and 2010 settlement monitoring data support the conclusion that the ongoing 

settlement and differential settlement show no significant trend and that most of the differential 

settlement between the auxiliary and the radwaste buildings occurred before 1997. The staff’s 

concern in RAI 4.7.8-2 is resolved. 

Based on its review of LRA Section 4.7.8, the staff finds the analyses for groundwater affect on 

post-construction heave, settlement, and differential settlement, described in the UFSAR 

Section 2.5.4.10.2, remain valid for the period of extended operation in accordance with 10 CFR 

54.21(c)(i). The staff also finds that the applicant’s use of the Structure Monitoring AMP 

provides assurance that the provisions of UFSAR Section 2.5.4.10.2, 2.5.4.11, and 2.5.4.13.1 

will be extended through the period of extended operation. The staff concludes that the 

applicant’s commitment to continue monitoring the effects of heave and settlement on structures 

and differential settlement between structures in the vicinity of critical connections will provide 

assurance that the affects of heave and settlement and differential settlement will be adequately 

managed for the period of extended operation in accordance with 10 CFR 54.21(c)(iii). 

4.7.8.3 Updated Final Safety Analysis Report Supplement 

The applicant provided an UFSAR supplement summary description of its TLAA of building 

absolute or differential heave or settlement, including possible effects of changes in perched 

groundwater lens in LRA Section A3.6.3. LRA Section A1.32 provides the summary of the 

settlement monitoring AMP. Based on its review of the UFSAR supplement, the staff concludes 

that the summary description of the applicant’s actions to address building absolute or 
Time-Limited Aging Analyses 

 4-108 

differential heave or settlement, including possible effects in perched groundwater lens is 

adequate. 

4.7.8.4 Conclusion 

Based on its review, the staff concludes, pursuant to 10 CFR 54.21(c)(1)(i), that the analyses for 

groundwater affect on post-construction heave, settlement, and differential settlement will 

remain valid for the period of extended operation. Further, the staff concludes, pursuant to 

10 CFR 54.21(c)(1)(iii), the applicant will adequately manage the effects of heave and 

settlement and differential settlement for the period of extended operation. The staff also 

concludes that the UFSAR supplement contains an appropriate summary description of this 

TLAA evaluation for the period of extended operation, in accordance with the requirements 

of 10 CFR 54.21(d). 

4.8 Absence of Time-Limited Aging Analyses Supporting Title 10, Part 50.12, 

Exemptions, of the Code of Federal Regulations 

As required by 10 CFR 54.21(c)(2), the applicant must list all exemptions granted in accordance 

with 10 CFR 50.12 based on TLAAs. The staff’s evaluation is found in SER Section 4.1.3. 

4.9 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 concludes that the applicant has provided a sufficient list of TLAAs, 

as defined in 10 CFR 54.3. The applicant has demonstrated that: (1) the TLAAs will remain 

valid for the period of extended operation, as required by 10 CFR 54.21(c)(1)(i); (2) the TLAAs 

have been projected to the end of the period of extended operation, as required by 

10 CFR 54.21(c)(1)(ii); or (3) that the effects of aging on intended function(s) 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 finds that the supplement contains 

descriptions of the TLAAs sufficient to satisfy the requirements of 10 CFR 54.21(d). In addition, 

the staff concludes, as required by 10 CFR 54.21(c)(2), that no plant-specific, TLAA-based 

exemptions are in effect. 

With regard to these matters, the staff concludes that there is reasonable assurance that the 

activities authorized by the renewed licenses will continue to be carried out in accordance with 

the CLB. In addition, any changes made to the CLB, in order to comply with 10 CFR 54.29(a), 

will be in accordance with the Atomic Energy Act of 1954, as amended, and NRC regulations. 
 5-1 

5.0 REVIEW BY THE ADVISORY COMMITTEE 

ON REACTOR SAFEGUARDS 

The NRC staff issued its safety evaluation report (SER) with open items related to the renewal 

of the operating license for Palo Verde Nuclear Generating Station, Units 1, 2, and 3 (PVNGS) 

on August 8, 2010. On September 8, 2010, the applicant presented its license renewal 

application, and the staff presented its review findings to the ACRS Plant License Renewal 

Subcommittee. The staff reviewed the applicant’s comments on the SER and completed its 

review of the license renewal application. The staff’s evaluation is documented in an SER that 

was issued by letter dated January 11, 2011. 

During the 580th meeting of the ACRS, February 10-12, 2011, the ACRS completed its review 

of the PVNGS license renewal application and the NRC staff’s SER. The ACRS documented its 

findings in a letter to the Commission dated March 1, 2011. A copy of this letter is provided on 

the following pages of this SER Section. 
UNITED STATES 

NUCLEAR REGULATORY COMMISSION 

ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 

WASHINGTON, DC 20555 - 0001 

March 1, 2011 

The Honorable Gregory B. Jaczko 

Chairman 

U.S. Nuclear Regulatory Commission 

Washington, D.C. 20555-0001 

SUBJECT: REPORT ON THE SAFETY ASPECTS OF THE LICENSE RENEWAL 

APPLICATION FOR THE PALO VERDE NUCLEAR GENERATING STATION 

Dear Chairman Jaczko: 

During the 580th meeting of the Advisory Committee on Reactor Safeguards (ACRS), February 

10-12, 2011, we completed our review of the license renewal application (LRA) for the Palo 

Verde Nuclear Generating Station, Units 1, 2, and 3 (PVNGS) and the final Safety Evaluation 

Report (SER) prepared by the NRC staff. Our Plant License Renewal subcommittee also 

reviewed this matter during its meeting on September 8, 2010. During these reviews, we met 

with representatives of the NRC staff, Arizona Public Service Company (APS or the applicant), 

and a member of the public. We also had the benefit of the documents referenced. This report 

fulfills the requirement of 10 CFR 54.25 that the ACRS review and report on all license renewal 

applications. 

CONCLUSION AND RECOMMENDATION 

1. The programs established and committed to by the applicant to manage age-related 

degradation provide reasonable assurance that the PVNGS units can be operated in 

accordance with their licensing bases for the period of extended operation without undue 

risk to the health and safety of the public. 

2. The application for the renewal of the operating licenses of the PVNGS units should be 

approved. 

BACKGROUND AND DISCUSSION 

PVNGS is located approximately 26 miles west of Phoenix, Arizona. The site consists of three 

pressurized water reactors of Combustion Engineering (CE) design with dry ambient 

containments. Each of the PVNGS units utilizes a System 80 nuclear steam supply system 

provided by CE. Each unit operates at a licensed power output of 3,990 megawatt-thermal. 

APS requested renewal of the PVNGS licenses for 20 years beyond the current license terms, 

 5-2

 
which expire on June 1, 2025 (Unit 1), April 24, 2026 (Unit 2), and November 25, 2027 (Unit 3). 

In the final SER, the staff documented their review of the license renewal application and other 

information submitted by the applicant or obtained during three staff audits and a two-week 

inspection conducted at the plant site. The staff reviewed the completeness of the applicant’s 

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

license renewal; the integrated plant assessment process; the applicant’s identification of the 

plausible aging mechanisms associated with passive, long-lived components; the adequacy of 

the applicant’s Aging Management Programs (AMPs); and the identification and assessment of 

time-limited aging analyses (TLAAs) requiring review. 

The applicant identified the SSCs that fall within the scope of license renewal and performed an 

aging management review for these SSCs. The applicant will implement 40 AMPs for license 

renewal. These include 29 existing programs and 11 new programs. Of the existing programs, 

nine AMPs are consistent with guidance in Revision 1 of the Generic Aging Lessons Learned 

(GALL) Report, five are consistent with exceptions, ten are consistent with enhancements, four 

are consistent with both enhancements and exceptions, and one is plant-specific. We reviewed 

the plant-specific programs and the AMP exceptions to the GALL Report. 

The applicant identified the systems and components requiring TLAAs and reevaluated them for 

the period of extended operation. The staff concluded that the applicant has provided an 

acceptable list of TLAAs, as defined in 10 CFR 54.3. Furthermore, the staff concluded that in all 

cases the applicant has met the requirements for TLAAs specified in 10 CFR 54.3. We concur 

with the staff’s conclusions that the TLAAs have been properly identified and that the required 

criteria will be met for the period of extended operation. 

The staff conducted three audits and one inspection at PVNGS. The audits verified the 

appropriateness of the aging management review, scoping and screening methodology, and 

associated AMPs. The inspection examined the scoping and screening of non-safety related 

SSCs and verified the adequacy of the guidance, documentation, and implementation of 

selected AMPs. The audit and inspection teams also performed independent examinations of 

PVNGS condition reports to confirm that plant-specific operating experience was addressed 

during the AMP development and implementation processes. Based on the audits and 

inspections, the staff concluded in the final SER that the proposed activities will adequately 

manage the aging of SSCs identified in the application and that the intended functions of these 

SSCs will be maintained during the period of extended operation. We agree with these 

conclusions. 

Following issuance of the draft SER with open items, the applicant submitted additional 

commitments that expand the scope and/or the means to detect aging effects in several license 

renewal programs. Among the most significant are those summarized below. 

In response to issues identified during the staff’s review of the Enhanced Fatigue Aging 

Management Program, the applicant improved the originally proposed program to track the 

number of occurrences for comparison to the plant’s design basis transients. 

 5-3
The applicant provided a summary of licensing and design information in the LRA and modified 

its Technical Specifications (TS) to include an administrative program that provides controls to 

assure that components are maintained within design limits. The staff concluded that the 

applicant’s Component Cycle and Transient Limit Program will be properly described in the 

applicable Updated Final Safety Analysis Report and TS sections. 

The staff has identified industry operating experience which indicates that power cables 

energized to 480V and higher can experience failures where extended exposure to moisture is a 

contributing factor. The Inaccessible Medium Voltage Cable Program described in Revision 1 of 

the GALL Report does not recommend testing for inaccessible cables energized to less than 

2kV and does not require testing of inaccessible cables that are not normally energized. The 

applicant has addressed the staff’s concerns by expanding the scope of the Medium Voltage 

Power Cable Program to include all inaccessible 480V to 2kV power cables, whether energized 

or not. This expanded scope of cable monitoring is consistent with Revision 2 of the GALL 

Report. 

The staff has concluded that external visual inspections do not provide adequate assurance that 

cracks are not present at the internal radius of socket welds in Class 1 small bore piping 

systems. There are currently no approved industry standard methods or qualified techniques to 

perform volumetric examinations of these welds. The applicant has experienced cracking in two 

small bore socket welds. In addition to visual inspections, the applicant will enhance the OneTime Inspection Program by committing to perform volumetric examinations of 10 percent of the 

Class 1 socket welds, up to a maximum of 25 welds for each unit (75 total), prior to the start of 

the period of extended operation. The applicant will use ultrasonic testing techniques. 

The staff has noted a number of recent industry events involving leakage from buried and 

underground piping and tanks within the scope of license renewal. Buried steel piping is 

coated, and recent inspections of excavated fire protection and diesel generator fuel oil piping 

demonstrate that coatings are in very good condition, with appropriate backfill. The applicant 

has committed to continue to periodically inspect components in soil. The applicant will 

maintain the availability of cathodic protection of the buried portions of the in-scope buried 

piping at least 90 percent of the time. Surveys of cathodic protection, consistent with guidance 

from the National Association of Corrosion Engineers, will be conducted at least annually during 

the period of extended operation. Visual inspections of in scope piping in a soil environment will 

be performed each 10 year period starting 10 years prior to the period of extended operation. 

At least two inspections of stainless steel piping will be conducted at each unit for piping that is 

not cathodically protected. The staff has concluded that with these enhancements, the 

proposed programs will adequately monitor and manage the aging of buried piping and tanks. 

We agree with the staff that there are no issues related to the matters described in 10 CFR 

54.29(a)(1) and (a)(2) that preclude renewal of the operating licenses for PVNGS Units 1, 2, and 

3. The programs established and committed to by the applicant provide reasonable assurance 

that PVNGS can be operated in accordance with their current licensing bases for the period of 

extended operation without undue risk to the health and safety of the public. The APS 

application for renewal of the operating licenses for the PVNGS units should be approved. 

 5-4 

 
Harold B. Ray did not participate in the Committee’s deliberations regarding this matter. 

Sincerely, 

/RA/ 

Said Abdel-Khalik 

Chairman 

REFERENCES 

1. U.S. Nuclear Regulatory Commission, “Safety Evaluation Report Related to the License 

Renewal of Palo Verde Nuclear Generating Station Units 1, 2, and 3,” dated August 

2010 (ML102210072) 

2. Palo Verde Nuclear Generating Station, Units 1, 2 and 3 - License Renewal Application, 

Part 1 of 3, dated December 11, 2008 (ML083510612) 

3. Palo Verde Nuclear Generating Station, Units 1, 2 and 3 - License Renewal Application, 

Part 2 of 3, dated December 11, 2008 (ML083510614) 

4. Palo Verde Nuclear Generating Station, Units 1, 2 and 3 - License Renewal Application, 

Part 3 of 3, dated December 11, 2008 (ML083510615) 

5. NRC Letter, “Audit Report Regarding the Palo Verde Nuclear Generating Station, Units 

1, 2, and 3 License Renewal Application (TAC NOS. ME0254, ME0255, ME0256), dated 

April 7, 2010 (ML100221296) 

6. NRC Letter, “Palo Verde Nuclear Generating Station-NRC License Renewal Inspection 

Report 05000528/2010007; 05000529/2010007; 05000530/2010007,” dated April 29, 

2010 (ML101190585) 

7. NRC Letter, “Scoping and Screening Audit Report for the Palo Verde Nuclear 

Generating Station, Units 1, 2, and 3, License Renewal Application (TAC NOS. ME0254, 

ME0255, and ME0256),” dated July 13, 2010 (ML101740217) 

8. U.S. Nuclear Regulatory Commission, “Safety Evaluation Report Related to the License 

Renewal of Palo Verde Nuclear Generating Station Units 1, 2, and 3,” dated January 11, 

2011 (ML110110411) 

9. Comments from a Member of the Public, dated February 7, 2011 (ML110480377) 

 5-5
 6-1 

6.0 CONCLUSION 

The U.S. Nuclear Regulatory Commission staff (the staff) reviewed the license renewal 

application (LRA) for Palo Verde Nuclear Generating Station in accordance with NRC 

regulations and NUREG-1800, Revision 1, “Standard Review Plan for Review of License 

Renewal Applications for Nuclear Power Plants,” dated September 2005. Title 10, 

Section 54.29 of the Code of Federal Regulations (10 CFR 54.29) sets the standards for 

issuance of a renewed license. 

On the basis of its review of the LRA, the staff determines that the requirements of 10 

CFR 54.29(a) have been met. 

The staff notes that the requirements of 10 CFR 51, Subpart A, will be documented in a plant 

specific supplement to NUREG-1437, “Generic Environmental Impact Statement for License 

Renewal of Nuclear Plants (GEIS).” 

 A-1 

APPENDIX A 

Palo Verde Nuclear Generating Station Units 1, 2, and 3 License 

Renewal Commitments 

During the review of the Palo Verde Nuclear Generating Station, Units 1, 2, and 3 (PVNGS), 

license renewal application (LRA) by the U.S. Nuclear Regulatory Commission (NRC) staff (the 

staff), Arizona Public Service Company (the applicant) made commitments related to aging 

management programs to manage aging effects for structures, systems and components. The 

following table lists these commitments along with the implementation schedules and sources 

for each commitment. 

Table A-1. Palo Verde Nuclear Generating Station License Renewal Commitments 

Item 

Number Commitment 

License Renewal 

Application Section 

Implementation 

Schedule 

1 The summary descriptions of aging management 

programs, time-limited aging analyses, and license 

renewal commitments contained in LRA Appendix A, 

“Updated Final Safety Analysis Supplement,” as required 

by 10 CFR 54.21(d), will be incorporated in the Updated 

Final Safety Analysis Report for PVNGS Units 1, 2, and 3 

in the next update required by 10 CFR 50.71(e) following 

the issuance of the renewed operating licenses. 

A0 The next 10 CFR 

50.71(e) Updated 

Final Safety 

Analysis Report 

update, following 

issuance of the 

renewed 

operating 

licenses 

2 Existing Quality Assurance Program is credited for license 

renewal. 

A1

B1.3 Summary 

Descriptions of Aging 

Management 

Ongoing

3 Existing ASME Section XI Inservice Inspection,

Subsections IWB, IWC, and IWD Program is credited for 

license renewal. 

A1.1

B2.1.1 ASME Section 

XI Inservice Inspection, 

Subsections IWB, IWC, 

and IWD 

Ongoing

4 Existing Water Chemistry Program is credited for license 

renewal. 

A1.2 

B2.1.2 Water Chemistry 

Ongoing

5 Existing Reactor Head Closure Studs Program is credited 

for license renewal. 

A1.3 

B2.1.3 Reactor Head 

Closure Studs 

Ongoing

6 Existing Boric Acid Corrosion Program is credited for 

license renewal. 

A1.4

B2.1.4 Boric Acid 

Corrosion 

Ongoing

7 Existing Nickel-Alloy Penetration Nozzles Welded to the 

Upper Reactor Vessel Closure Heads of Pressurized 

Water Reactors Program is credited for license renewal. 

A1.5 

B2.1.5 Nickel-Alloy 

Penetration Nozzles 

Welded to the Upper 

Reactor Vessel Closure 

Heads of Pressurized 

Water Reactors 

Ongoing

8 Existing Flow-Accelerated Corrosion Program is credited 

for license renewal. 

A1.6 

B2.1.6 FlowOngoing
Appendix A 

 A-2 

Item 

Number Commitment 

License Renewal 

Application Section 

Implementation 

Schedule 

Accelerated Corrosion 

9 Existing Bolting Integrity Program is credited for license 

renewal. 

A1.7

B2.1.7 Bolting Integrity 

Ongoing

10 Existing Steam Generator Tube Integrity Program is 

credited for license renewal. 

A1.8

B2.1.8 Steam 

Generator Tube 

Integrity 

Ongoing

11 Existing Open-Cycle Cooling Water System Program is 

credited for license renewal, AND 

Prior to the period of extended operation, the program will 

be enhanced to clarify guidance in the conduct of piping 

inspections using NDE techniques and related acceptance 

criteria. 

A1.9 

B2.1.9 Open-Cycle 

Cooling Water System 

Prior to the period 

of extended 

operation1

12 Existing Closed-Cycle Cooling Water System Program is 

credited for license renewal, AND 

Prior to the period of extended operation, procedures will 

be enhanced to incorporate the guidance of EPRI 

TR-107396 with respect to water chemistry control for 

frequency of sampling and analysis, normal operating 

limits, action level concentrations, and times for 

implementing corrective actions upon attainment of action 

levels. 

A1.10

B2.1.10 Closed-Cycle 

Cooling Water System 

Prior to the period 

of extended 

operation1

. 

13 Existing Inspection of Overhead Heavy Load and Light 

Load (Related to Refueling) Handling Systems Program is 

credited for license renewal, AND 

Prior to the period of extended operation, procedures will 

be enhanced to inspect for loss of material due to 

corrosion or rail wear. 

A1.11

B2.1.11 Inspection Of 

Overhead Heavy Load 

and Light Load (Related 

to Refueling) Handling 

Systems 

Prior to the period 

of extended 

operation1

. 

14 Existing Fire Protection Program is credited for license 

renewal, AND 

Prior to the period of extended operation procedures will 

be enhanced to perform the testing of the electro-thermal 

links and functional testing of the halon and CO2 dampers 

every 18 months or at the frequency specified in the 

current licensing basis in effect upon entry into the period 

of extended operation. 

A1.12

B2.1.12 Fire Protection 

Prior to the period 

of extended 

operation1

. 

15 Existing Fire Water System Program is credited for license 

renewal, AND 

Prior to the period of extended operation, the following 

enhancements will be implemented: 

 Specific procedures will be enhanced to include review 

and approval requirements under the Nuclear 

Administrative Technical Manual (NATM). 

 Procedures will be enhanced to be consistent with the 

current code of record or NFPA 25, 2002 Edition. 

 Procedures will be enhanced to field service test a 

representative sample or replace sprinklers prior to 

50 years in service and test thereafter every 10 years to 

ensure that signs of degradation are detected in a timely 

manner. 

 Procedures will be enhanced to be consistent with 

NFPA 25, Sections 7.3.2.1, 7.3.2.2, 7.3.2.3, and 7.3.2.4. 

A1.13

B2.1.13 Fire Water 

System 

Prior to the period 

of extended 

operation1

. 
 Appendix A 

 A-3 

Item 

Number Commitment 

License Renewal 

Application Section 

Implementation 

Schedule 

16 Existing Fuel Oil Chemistry Program is credited for license 

renewal, AND 

Prior to the period of extended operation: 

 Procedures will be enhanced to extend the scope of the 

program to include the station blackout generator 

(SBOG) fuel oil storage tank and SBOG skid fuel tanks. 

 Procedures will be enhanced to include ten-year periodic 

draining, cleaning, and inspections on the diesel-driven 

fire pump day tanks, the SBOG fuel oil storage tank, and 

SBOG skid fuel tanks. 

 Ultrasonic testing (UT) or pulsed eddy current (PEC) 

thickness examination will be conducted to detect 

corrosion-related wall thinning if degradation is found 

during the visual inspections and once on the tank 

bottoms for the EDG fuel oil storage tanks, EDG fuel oil 

day tanks, diesel-driven fire pump day tanks, SBOG fuel 

oil storage tank, and SBOG skid fuel tanks. The onetime 

UT or PEC examination on the tank bottoms will be 

performed before the period of extended operation. 

A1.14

B2.1.14 Fuel Oil 

Chemistry 

Prior to the period 

of extended 

operation1

. 

17 Existing Reactor Vessel Surveillance Program is credited 

for license renewal, AND 

Prior to the period of extended operation: 

 The schedule will be revised to withdraw the next 

capsule at the equivalent clad-base metal exposure of 

approximately 54 effective full-power year (EFPY) 

expected for the 60-year period of operation, and to 

withdraw remaining standby capsules at equivalent cladbase metal exposures not exceeding the 72 EFPY 

expected for a possible 80-year second period of 

extended operation. This withdrawal schedule is in 

accordance with NUREG-1801, Section XI.M31, item 6, 

and with the ASTM E 185-82 criterion which states that 

capsules may be removed when the capsule neutron 

fluence is between one and two times the limiting fluence 

calculated for the vessel at the end of expected life. This 

schedule change must be approved by the NRC, as 

required by 10 CFR 50, Appendix H. 

 If left in the reactor beyond the presently-scheduled 

withdrawal, the next scheduled surveillance capsule in 

each unit will reach a clad-base metal 54 EFPY 

equivalent at about 40 actual operating EFPY (40, 39, 

and 42 actual EFPY in Units 1, 2, and 3, respectively). 

 Procedures will be enhanced to identify the withdrawal of 

the remaining standby capsules at 72 EFPY, at about 50 

to 54 actual operating EFPY, near the end of the 

extended licensed operating period. The need to 

monitor vessel fluence following removal of the 

remaining standby capsules, and ex-vessel or in-vessel 

methods, will be addressed prior to removing the 

remaining capsules. 

A1.15

B2.1.15 Reactor Vessel 

Surveillance 

Prior to the period 

of extended 

operation1

. 

18 The One-Time Inspection Program conducts one-time 

inspections of plant system piping and components to 

verify the effectiveness of the Water Chemistry Program 

(A1.2), Fuel Oil Chemistry Program (A1.14), and 

Lubricating Oil Analysis Program (A1.23). The aging 

effects to be evaluated by the One-Time Inspection 

A1.16

B2.1.16 One-Time 

Inspection 

Within the ten 

year period prior 

to the period of 

extended 

operation1

. 
Appendix A 

 A-4 

Item 

Number Commitment 

License Renewal 

Application Section 

Implementation 

Schedule 

Program are loss of material, cracking, and reduction of 

heat transfer. 

19 The Selective Leaching of Materials Program is a new 

program that will be implemented prior to the period of 

extended operation. Industry and plant-specific operating 

experience will be evaluated in the development and 

implementation of this program. 

The Selective Leaching of Materials Program includes a 

one-time inspection (visual and/or mechanical methods) of 

a selected sample of components' internal surfaces to 

determine whether loss of material due to selective 

leaching is occurring. A sample size of 20 percent of the 

population, up to a maximum of 25 component inspections, 

will be established for each of the system material and 

environment combinations at the PVNGS site. If 

indications of selective leaching are confirmed, follow-up 

examinations or evaluations will be performed. 

A1.17 

B2.1.17 Selective 

Leaching of Materials 

Within the ten 

year period prior 

to the period of 

extended 

operation1

. 

20 The Buried Piping and Tanks Inspection Program is a new 

program that will be implemented prior to the period of 

extended operation. 

Within the ten year period prior to entering the period of 

extended operation an opportunistic or planned inspection 

of buried tanks at the PVNGS site will be performed. 

The visual inspections noted below of piping in a soil 

environment within the scope of license renewal will be 

conducted within the ten-year period prior to entering the 

period of extended operation, and during each ten year 

period after entering the period of extended operation, 

except the initial diesel generator fuel oil piping inspection 

will be performed between January 1, 2012, and 

December 31, 2015. Each inspection will: 

 select accessible locations where degradation is 

expected to be high; 

 excavate and visually inspect the circumference of the 

pipe 

 examine at least ten feet of pipe 

a. Metallic Piping not Cathodically-Protected 

At least two excavations and visual inspections of stainless 

steel piping will be conducted in each unit. Stainless steel 

piping within the scope of license renewal exists in the 

following systems: 

 Chemical and Volume Control (CH) 

 Condensate Transfer and Storage (CT) 

 Fire Protection (FP) 

b. Steel Piping Cathodically-Protected 

At least two excavations and visual inspections of 

cathodically-protected steel piping will be conducted in 

each unit. In one of the units, at least one of these 

inspections will be performed on diesel generator fuel oil 

piping. 

c. Steel Piping with Potentially Degraded Cathodic 

A1.18 

B2.1.18 Buried Piping 

and Tanks Inspection 

Perform the 

buried piping and 

tanks inspections 

within the ten 

year period prior 

to the period of 

extended 

operation1

, 

except the initial 

diesel generator 

fuel oil piping 

inspection will be 

performed 

between 1/1/12 

and 12/31/15. 

AND 

Perform the 

buried piping 

inspections 

during each ten 

year period after 

entering the 

period of 

extended 

operation. 

AND 

Implement the 

additional 

enhancements to 

the Buried Piping 

and Tanks 

Inspection 

Program prior to 

the period of 

operation1

. 
 Appendix A 

 A-5 

Item 

Number Commitment 

License Renewal 

Application Section 

Implementation 

Schedule 

Protection 

At least three excavations and visual inspections of fire 

protection steel piping with potentially degraded bonding 

straps will be conducted at the PVNGS site. 

Prior to the period of extended operation, the Buried Piping 

and Tanks Inspection Program will include provisions to: 

(1) ensure electrical power is maintained to the cathodic 

protection system for in-scope buried piping at least 90 

percent of the time (e.g., monthly verification that the 

power supply circuit breakers are closed or other 

verification that power is being provided to the system), 

and (2) ensure that the National Association of Corrosion 

Engineers cathodic protection system surveys are 

performed at least annually. 

21 The One-Time Inspection of ASME Code Class 1 

Small-Bore Piping Program is a new program that will be 

implemented prior to the period of extended operation. 

Industry and plant-specific operating experience will be 

evaluated in the development and implementation of this 

program. 

For ASME Code Class 1 small-bore piping, volumetric 

examinations on selected butt weld locations will be 

performed to detect cracking. Butt weld volumetric 

examinations will be conducted in accordance with ASME 

Section XI with acceptance criteria from Paragraph 

IWB-3000 and IWB-2430. Weld locations subject to 

volumetric examination will be selected based on the 

guidelines provided in EPRI TR-112657. Socket welds 

that fall within the weld examination sample will be 

examined following ASME Section XI Code requirements. 

At least 10 percent of the socket welds in ASME Code 

Class 1 piping that is less than four inches nominal pipe 

size and greater than or equal to one inch nominal pipe 

size will be selected per unit for ultrasonic testing 

examination, up to a maximum of 25 weld examinations. 

The sample will be selected based on risk insights and 

those welds with the potential for aging degradation. 

A1.19 

B2.1.19 One-Time 

Inspection of ASME 

Code Class 1 

Small-Bore Piping 

Within the six 

year period prior 

to the period of 

extended 

operation1

. 

22 The External Surfaces Monitoring Program is a new 

program that will be implemented prior to the period of 

extended operation. Industry and plant-specific operating 

experience will be evaluated in the development and 

implementation of this program. 

A1.20 

B2.1.20 External 

Surfaces Monitoring 

Program 

Prior to the period 

of extended 

operation1

. 

23 The applicant will complete the tasks described:

a. Reactor Coolant System Nickel Alloy Pressure 

Boundary Components 

Implement applicable (1) NRC Orders, Bulletins and 

Generic Letters associated with nickel alloys and (2) 

staff-accepted industry guidelines, (3) participate in the 

industry initiatives, such as owners group programs and 

the EPRI Materials Reliability Program, for managing aging 

effects associated with nickel alloys, (4) upon completion 

of these programs, but not less than 24 months before 

entering the period of extended operation, APS will submit 

an inspection plan for reactor coolant system nickel alloy 

pressure boundary components to the NRC for review and 

approval, and 

A1.21

B2.1.21 Reactor 

Coolant System 

Supplement 

3.1.2.2.16.2 Pressurizer 

Spray Head Cracking 

Not less than 24 

months prior to 

the period of 

extended 

operation1

. 
Appendix A 

 A-6 

Item 

Number Commitment 

License Renewal 

Application Section 

Implementation 

Schedule 

b. Reactor Vessel Internals

(1) Participate in the industry programs for investigating 

and managing aging effects on reactor internals; (2) 

evaluate and implement the results of the industry 

programs as applicable to the reactor internals; and (3) 

upon completion of these programs, but not less than 24 

months before entering the period of extended operation, 

APS will submit an inspection plan for reactor internals to 

the NRC for review and approval. 

c. Pressurizer Spray Heads 

Comply with applicable NRC Orders and implement 

applicable (1) Bulletins and Generic Letters, and (2) 

staff-accepted industry guidelines. 

24 The Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program is a new 

program that will be implemented prior to the period of 

extended operation. Industry and plant-specific operating 

experience will be evaluated in the development and 

implementation of this program. 

A1.22

B2.1.22 Inspection of 

Internal Surfaces in 

Miscellaneous Piping 

and Ducting 

Components 

Prior to the period 

of extended 

operation1

. 

25 Existing Lubricating Oil Analysis Program is credited for 

license renewal. 

A1.23

B2.1.23 Lubricating Oil 

Analysis 

Ongoing

26 The Electrical Cables and Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements 

Program is a new program that will be implemented prior 

to the period of extended operation. Industry and 

plant-specific operating experience will be evaluated in the 

development and implementation of this program. 

A1.24

B2.1.24 Electrical 

Cables and 

Connections Not 

Subject to 10 CFR 

50.49 Environmental 

Qualification 

Requirements 

Prior to the period 

of extended 

operation1

. 

27 Existing Electrical Cables And Connections Not Subject To 

10 CFR 50.49 Environmental Qualification Requirements 

Used In Instrumentation Circuits Program is credited for 

license renewal , AND 

Prior to the period of extended operation: 

 Procedures will be enhanced to identify license renewal 

scope, require cable testing of ex-core neutron 

monitoring cables, require an evaluation of the 

calibration results for non-EQ area radiation monitors, 

and require acceptance criteria for cable testing be 

established based on the type of cable and type of test 

performed. 

A1.25

B2.1.25 Electrical 

Cables and 

Connections Not 

Subject to 10 CFR 

50.49 Environmental 

Qualification 

Requirements Used in 

Instrumentation Circuits 

Prior to the period 

of extended 

operation1

. 

28 The Inaccessible Medium Voltage Cables Not Subject to 

10 CFR 50.49 EQ Requirements Program is credited for 

license renewal, AND 

Prior to the period of extended operation procedures will 

be enhanced to: 

 Extend the scope of the program to include low voltage 

(480V and above) non-EQ inaccessible power cables 

and associated manholes. 

 Perform the cable inspections on at least an annual 

frequency and perform the cable testing on a six year 

A1.26

B2.1.26 Inaccessible 

Medium Voltage Cables 

Not Subject to 10 CFR 

50.49 Environmental 

Qualification 

Requirements 

Prior to the period 

of extended 

operation1

. 
 Appendix A 

 A-7 

Item 

Number Commitment 

License Renewal 

Application Section 

Implementation 

Schedule 

frequency. 

29 Existing ASME Section XI, Subsection IWE Program is 

credited for license renewal. 

A1.27 

B2.1.27 ASME Section 

XI, Subsection IWE 

Ongoing

30 Existing ASME Section XI, Subsection IWL Program is 

credited for license renewal. 

A1.28 

B2.1.28 ASME Section 

XI, Subsection IWL 

Ongoing

31 Existing ASME Section XI, Subsection IWF Program is 

credited for license renewal. 

A1.29 

B2.1.29 ASME Section 

XI, Subsection IWF 

Ongoing

32 Existing 10 CFR 50, Appendix J Program is credited for 

license renewal. 

A1.30 

B2.1.30 10 CFR 50, 

Appendix J 

Ongoing

33 Existing Masonry Wall Program is credited for license 

renewal, AND 

Prior to the period of extended operation, procedures will 

be enhanced to specify ACI 349.3R-96 as the reference for 

qualification of personnel to inspect structures under the 

Masonry Wall Program, which is part of the Structures 

Monitoring Program. 

A1.31

B2.1.31 Masonry Wall 

Program 

Prior to the period 

of extended 

operation1

. 

34 Existing Structures Monitoring Program is credited for 

license renewal, AND 

Prior to the period of extended operation: 

 The Structures Monitoring Program will be enhanced to 

specify ACI 349.3R-96 as the reference for qualification 

of personnel to inspect structures under the Structures 

Monitoring Program. 

 For structures within the scope of license renewal, the 

Structures Monitoring Program will be enhanced to 

establish the frequency of inspection for each unit at a 5 

year interval, with the exception of exterior surfaces of 

the following nonsafety-related structures, below-grade 

structures, and structures within a controlled interior 

environment, which will be inspected at an interval of 10 

years: 

– Fire Pump House (Yard Structures) 

– Radwaste Building 

– Station Blackout Generator Structures 

– Turbine Building 

– Non-Safety Related Tank Foundations and Shells 

– Non-Safety Related Transformer Foundations and 

Electrical Structures 

 The Structures Monitoring Program will be enhanced to 

quantify the acceptance criteria and critical parameters 

for monitoring degradation, and to provide guidance for 

identifying unacceptable conditions requiring further 

technical evaluation or corrective action. Procedures will 

also be enhanced to incorporate applicable industry 

codes, standards and guidelines (e.g., ACI 349.3R-96, 

A1.32

B2.1.32 Structures 

Monitoring Program 

Prior to the period 

of extended 

operation1

. 
Appendix A 

 A-8 

Item 

Number Commitment 

License Renewal 

Application Section 

Implementation 

Schedule 

ANSI/ASCE 11-90, etc.) for acceptance criteria.

35 Existing Regulatory Guide 1.127, Inspection Of 

Water-Control Structures Associated With Nuclear Power 

Plants Program is credited for license renewal, AND 

Prior to the period of extended operation, procedures will 

be enhanced to specify that the essential spray ponds 

inspections include concrete below the water level. 

A1.33

B2.1.33 RG 1.127, 

Inspection of 

Water-Control 

Structures Associated 

with Nuclear Power 

Plants 

Prior to the period 

of extended 

operation1

. 

36 Existing Nickel Alloy Aging Management Program is 

credited for license renewal. 

A1.34 

B2.1.34 Nickel Alloy 

Aging Management 

Program 

Ongoing

37 The Electrical Cable Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements 

Program is a new program that will be implemented prior 

to the period of extended operation. Industry and 

plant-specific operating experience will be evaluated in the 

development and implementation of this program. 

A1.35

B2.1.35 Electrical Cable 

Connections Not 

Subject to 10 CFR 

50.49 Environmental 

Qualification 

Requirements 

Prior to the period 

of extended 

operation1

. 

38 The Metal Enclosed Bus Program is a new program and 

will be completed before the period of extended operation 

and once every 10 years thereafter. Industry and 

plant-specific operating experience will be evaluated in the 

development and implementation of this program. 

A1.36

B2.1.36 Metal Enclosed 

Bus 

Prior to the period 

of extended 

operation and 

once every ten 

years thereafter. 

39 No later than two years prior to the period of extended 

operation, the following enhancements will be 

implemented 

 Cumulative usage factor (CUF) tracking will be 

implemented for NUREG/CR-6260 locations not 

monitored by cycle counting (CC) (the reactor vessel 

shell and lower head (juncture) location will be monitored 

by CC). For PVNGS locations identified in 

NUREG/CR-6260 and monitored by CUF, fatigue usage 

factor action limits will be required for including effects of 

the reactor coolant environment. 

 The Metal Fatigue of Reactor Coolant Pressure 

Boundary Program will be enhanced to include a 

computerized program to track and manage both CC 

and fatigue usage factor. FatiguePro® will be used for 

CC and cycle-based fatigue monitoring methods. 

FatiguePro® is an EPRI-licensed product. 

 The enhanced Metal Fatigue of Reactor Coolant 

Pressure Boundary Program will monitor plant transients 

as required by PVNGS Technical Specification 5.5.5. 

CUFs will be calculated for a subset of ASME III Class 1 

reactor coolant pressure boundary vessel and piping 

locations and component locations with Class 1 

analyses. The following methods will be used: 

– The Metal Fatigue of Reactor Coolant Pressure 

Boundary Program will be enhanced to use 

cycle-based fatigue and stress-based fatigue CUF 

calculations to monitor fatigue. FatiguePro® will be 

used for CC and cycle-based fatigue monitoring 

4.3.1 Fatigue Aging 

Management Program 

A2.1 

B3.1 Metal Fatigue of 

Reactor Coolant 

Pressure Boundary 

No later than two 

years prior to the 

period of 

extended 

operation1

. 
 Appendix A 

 A-9 

Item 

Number Commitment 

License Renewal 

Application Section 

Implementation 

Schedule 

methods. FatiguePro® is an EPRI-licensed product.

– The stress-based fatigue method will use a fatigue 

monitoring software program that incorporates a 

three-dimensional, six-component stress tensor 

method meeting ASME III NB-3200 requirements. 

 The enhanced Metal Fatigue of Reactor Coolant 

Pressure Boundary Program will provide action limits on 

cycles and on CUF that will initiate corrective actions 

before the licensing basis limits on fatigue effects at any 

location are exceeded. 

– In order to ensure sufficient cycle count margin to 

accommodate occurrence of a low-probability 

transient, corrective actions must be taken before the 

remaining number of allowable occurrences for any 

specified transient becomes less than 1.0. 

– CUF action limits will be established to require 

corrective action when the calculated CUF (from 

cycle-based or stress-based monitoring) for any 

monitored location is projected to reach 1.0 within the 

next two or three operating cycles. In order to ensure 

sufficient margin to accommodate occurrence of a 

low-probability transient, corrective actions will be 

taken while there is still sufficient margin to 

accommodate at least one occurrence of the 

worst-case design transient event (i.e., with the highest 

fatigue usage per event cycle). 

40 Existing Environmental Qualification Program is credited 

for license renewal, AND 

Maintaining qualification through the extended license 

renewal period requires that existing EQ evaluations be 

re-evaluated. 

A2.2

B3.2 Environmental 

Qualification (EQ) of 

Electrical Components 

Prior to the period 

of extended 

operation1

. 

41 Existing Concrete Containment Tendon Prestress Program

is credited for license renewal, AND 

 The program will be enhanced to continue to compare 

regression analysis trend lines of the individual lift-off 

values of tendons surveyed to date, in each of the 

vertical and hoop tendon groups, with the minimum 

required value (MRV) and predicted lower limit (PLL) for 

each tendon group, to the end of the licensed operating 

period, and to take appropriate corrective actions if 

future values indicated by the regression analysis trend 

line drop below the PLL or MRV. The regression 

analyses will be updated for tendons of the affected unit 

and for a combined data set of all three units following 

each inspection of an individual unit. 

 Prior to the period of extended operation, procedures will 

be enhanced to require an update of the regression 

analysis for each tendon group of each unit, and of the 

joint regression of data from all three units, after every 

tendon surveillance. The documents will invoke and 

describe regression analysis methods used to construct 

the lift-off trend lines, including the use of individual 

tendon data in accordance with Information Notice (IN) 

99-10, “Degradation of Prestressing Tendon Systems in 

Prestressed Concrete Containments.” 

A2.3

B3.3 Concrete 

Containment Tendon 

Prestress 

4.5 Concrete 

Containment Tendon 

Prestress 

Prior to the period 

of extended 

operation1

. 
Appendix A 

 A-10 

Item 

Number Commitment 

License Renewal 

Application Section 

Implementation 

Schedule 

 The Tendon Integrity test procedure will be revised to 

extend the list of surveillance tendons to include random 

samples for the year 45 and 55 surveillances. 

42 The applicant will confirm the reactor coolant system 

pressure-temperature limits basis for 54 EFPY prior to 

operation beyond 32 EFPY and will update documents in 

accordance with the provisions of 10 CFR 50.59. (RCTSAI 

3246939) 

A3.1.3 PressureTemperature Limits Prior to operation 

beyond 32 

EFPY1

. 

43 Completed 

44 Completed 

45 See Item No. 46 

46 An extension of In-Service Inspection Relief Request 31, 

Revision 1 authorization will be requested for the period of 

extended operation, supported by a continuation of the 

cold shutdown time monitoring program. 

4.7.4 Fatigue Crack 

Growth and Fracture 

Mechanics Stability 

Analyses of Half-Nozzle 

Repairs to Alloy 600 

Material in Reactor 

Coolant Hot Legs; 

Absence of a TLAA for 

Supporting Corrosion 

Analyses 

Prior to the period 

of extended 

operation1

. 

47 Deleted (Staff note: this was in the PVNGS Environmental 

Report) 

48 Deleted (Staff note: this was in the PVNGS Environmental 

Report) 

49 Deleted (Staff note: this was in the PVNGS Environmental 

Report) 

50 The Fuse Holder Program is a new program that will be

implemented prior to the period of extended operation and 

once every 10 years thereafter. Industry and plant-specific 

operating experience will be evaluated in the development 

and implementation of this program. 

A1.37

B2.1.37 

Fuse Holder 

Prior to the period 

of extended 

operation and 

once every 10 

years thereafter. 

51 Completed 

52 Deleted (Staff note: this was in the PVNGS Environmental 

Report) 

53 Completed 

54 Completed 

55 Completed 

56 The spray pond wall rework/repair methods are currently 

being determined, and the rework/repair is planned to 

begin in 2011. As Unit 1 spray ponds have the most 

degradation, work is planned to start there, followed by 

Units 2 and 3. It is expected that the work will be 

completed in all three units in 2015. 

PVNGS letter dated 

June 21, 2010 

12/31/2015

57 No later than two years prior to the period of extended 

operation, APS will confirm the conservatism of the Fen

value of 1.49 using the methods specified in 

NUREG/CR-6909, and will use the Fen calculated using the 

NUREG/CR-6909 methods if it is more conservative than 

the 1.49 value. 

PVNGS letter dated 

June 29, 2010 

No later than two 

years prior to the 

period of extended 

operation1

. 
 Appendix A 

 A-11 

Item 

Number Commitment 

License Renewal 

Application Section 

Implementation 

Schedule 

58 No later than two years prior to the period of extended 

operation, APS will perform a reanalysis of the pressurizer 

heater penetrations to consider EAF effects using the 

formulas and methodology given in NUREG/CR-6909. 

PVNGS letter dated 

June 29, 2010 

No later than two 

years prior to the 

period of extended 

operation1

. 

59 As documented in CRAI 3337611, Engineering Study 

13-MS-B089, “Cavitation in Safety Injection System,” APS 

identified 26 components and associated piping in each 

PVNGS unit potentially susceptible to cavitation under 

design basis maximum flow conditions. One location in 

each unit, the HPSI recirculation piping downstream of 

throttle valve JSIBUV0667, has been confirmed to be 

susceptible to cavitation erosion, and a 7.5-year 

time-based replacement schedule described below has 

been established. All of the remaining 25 locations 

identified as potentially susceptible to cavitation in Unit 2, 

20 of the locations in Unit 1, and 15 of the locations in Unit 

3 have been inspected by ultrasonic testing (UT) and 

demonstrated no degradation. The remaining five 

locations in Unit 1 are scheduled to be inspected in the 

Unit 1 fall 2011 refueling outage. Of the remaining ten 

locations in Unit 3, five will be inspected in the Unit 3 fall 

2010 outage and five will be inspected in the Unit 3 spring 

2012 outage. Therefore, the inspections in all three units 

will be completed no later than June 30, 2012. If any of 

the remaining components and associated piping is found 

to be susceptible to cavitation or a form of flow-related 

degradation, it will be incorporated into a replacement plan 

similar to that for the HPSI recirculation piping downstream 

of throttle valve JSIBUV0667. 

PVNGS letter dated 

July 30, 2010 

6/30/2012

60 The reactor coolant system transient and cycle tracking 

procedure 73ST-9RC02 and UFSAR Section 3.9.1 will be 

enhanced to discuss corrective actions that need to be 

taken prior to ASME Section III fatigue design limits being 

exceeded and to state that corrective actions may be 

required for other fatigue-related analyses, such as certain 

ASME Section XI supplemental fatigue flaw growth or 

cycle-dependent fracture mechanics evaluations that are 

dependent on the number of occurrences of design 

transients. 

PVNGS letter dated 

October 13, 2010 

11/30/2010

61 The applicant will perform one of the following three 

resolution options: 

1. Perform an inspection of each steam generator at 

PVNGS to assess the condition of the divider plate bar 

welds in all units and the divider plate bars in Unit 2. The 

examination technique(s) will be capable of detecting 

PWSCC in the divider plate bar welds in all units, and in 

the accessible surfaces of the divider plate bars in Unit 2. 

OR 

2. Perform an analytical evaluation of the steam generator 

divider plate bar welds in all units, and the divider plate 

bars in Unit 2, in order to establish a technical basis which 

concludes that the SG reactor coolant system pressure 

boundary is adequately maintained with the presence of 

steam generator divider plate bar weld cracking. 

OR 

3. If results of industry and NRC studies and operating 

PVNGS letter dated 

November 23, 2010 

as modified by letters 

dated 

February 25, 2011 

and March 17, 2011 

If Option (1) is 

selected, it will be 

completed for each 

SG in each unit 

during an SG tube 

eddy-current 

inspection outage 

between 20 and 25 

calendar years of 

SG operation. 

If Option (2) or 

Option (3) is 

selected, it will be 

completed prior to 

9/1/2023. 
Appendix A 

 A-12 

Item 

Number Commitment 

License Renewal 

Application Section 

Implementation 

Schedule 

experience document that potential failure of the SG 

reactor coolant system pressure boundary due to PWSCC 

cracking of SG divider plate bar welds and the divider plate 

bars in Unit 2 is not a credible concern, this commitment 

will be revised to reflect that conclusion. 

62 The applicant will perform one of the following two 

resolution options: 

1. Perform a one-time inspection of a representative 

number of tube-to-tubesheet welds in each steam 

generator to determine if PWSCC cracking is present. If 

weld cracking is identified: 

The condition will be resolved through repair or 

engineering evaluation to justify continued service, as 

appropriate. 

An ongoing monitoring program will be established to 

perform routine tube-to-tubesheet weld inspections for the 

remaining life of the steam generators. 

OR 

2. Perform an analytical evaluation of the steam generator 

tube-to-tubesheet welds in order to: 

Establish a technical basis which concludes that the 

structural integrity of the steam generator 

tube-to-tubesheet interface is adequately maintained with 

the presence of tube-to-tubesheet weld cracking. 

Establish a technical basis which concludes that the steam 

generator tube-to-tubesheet welds are not required to 

perform a reactor coolant pressure boundary function. 

PVNGS letter dated 

November 23, 2010 

If Option (1) is 

selected, it will be 

completed for each 

SG in each unit 

during an SG tube 

eddy-current 

inspection outage 

between 20 and 25 

calendar years of 

SG operation. 

If Option (2) is 

selected, it will be 

completed prior to 

9/1/2023. 

63 No later than two years prior to the period of extended 

operation, the applicant will confirm that: 

The plant-specific components listed in LRA Table 4.3-11 

(except the pressurizer surge line pressurizer elbow) are 

bounding for the generic NUREG/CR-6260 locations and 

the additional location (pressurizer heater penetrations). If 

locations are found that are not bounded by the Table 

4.3-11 components, APS will perform new analyses as 

necessary to bound such locations. 

AND 

The LRA Table 4.3-11 locations selected for 

environmentally assisted fatigue analyses consist of the 

most limiting CUF locations for the plant (beyond the 

generic EAF locations identified in the NUREG/CR-6260 

guidance). If the Table 4.3-11 locations are not bounding, 

APS will perform an environmentally assisted fatigue 

analysis for the additional CUF locations not bounded by 

the Table 4.3-11 locations. If the component with the most 

limiting CUF is composed of nickel alloy, the methodology 

used to perform the environmentally-assisted fatigue 

calculation for nickel alloy will be consistent with 

NUREG/CR-6909. 

PVNGS letter dated 

December 3, 2010 

No later than two 

years prior to the 

period of extended 

operation. 

(1) “Prior to period of extended operation,” “prior to operation beyond 32 EFPY,” and “prior to the end of the current licensed 

operating period,” is prior to the following PVNGS Operating License expiration dates: Unit 1: June 1, 2025; Unit 2: April 24, 2026; 

Unit 3: November 25, 2027. 
 

 B-1 

APPENDIX B 

Chronology 

This appendix lists chronologically the routine licensing correspondence between the U.S. 

Nuclear Regulatory Commission (NRC) staff (the staff) and Arizona Public Service Company 

(APS) (the applicant). This appendix also lists other correspondence on the staff’s review of the 

Palo Verde Nuclear Generating Station (PVNGS), Units 1, 2, and 3 License Renewal 

Application (LRA) under Docket Nos. 50-528, 50-529, and 50-530. The date shown in the date 

column is the date the correspondence was issued and may differ from the actual date of 

the event. 

Date Subject 

12/11/2008 Palo Verde Nuclear Generating Station, Units 1, 2 and 3 - License Renewal Application - Cover 

Letter (ML083510611) 

12/11/2008 Palo Verde Nuclear Generating Station, Units 1, 2 and 3 - License Renewal Application, Part 1 of 3 

(ML083510612) 

12/11/2008 Palo Verde Nuclear Generating Station, Units 1, 2 and 3 - License Renewal Application, Part 2 of 3 

(ML083510614) 

12/11/2008 Palo Verde Nuclear Generating Station, Units 1, 2 and 3 - License Renewal Application, Part 3 of 3 

(ML083510615) 

12/23/2008 Letter from NRC to APS, 12/18/2008, Summary of Public Meeting with Arizona Public Service 

Company (ML083580225) 

12/24/2008 Press Release-08-234, “NRC Announces Availability of License Renewal Application For Palo 

Verde Nuclear Generating Station” (ML083590238) 

1/12/2009 Letter from NRC to APS, Notice of Receipt and Availability of the License Renewal Application for 

the Palo Verde Nuclear Generating Station Units 1,2, and 3 (ML083530426) 

2/13/2009 Letter from NRC to APS, Review Status Of The License Renewal Application For The Palo Verde 

Nuclear Generating Station (ML090360279) 

2/25/2009 Letter from APS to NRC, PVNGS, Units 1, 2, and 3, Letter Regarding Plan to Resolve Deficiency in 

the PVNGS License Renewal Application (ML090750614) 

4/14/2009 PVNGS, Units 1, 2, and 3, Supplement 1 to LRA (ML091130221)

4/15/2009 Summary of telephone conference call held between NRC and APS, 1/30/2009, pertaining to the 

PVNGS, Units 1, 2, and 3, LRA (ML090830031) 

5/8/2009 PVNGS, Units 1, 2, and 3, Errata to Supplement 1 to LRA (ML092600288) 

5/11/2009 Letter from NRC to APS, Determination of Acceptability and Sufficiency for Docketing, Proposed 

Review Schedule, and Opportunity for a Hearing Regarding the Application from Arizona Public 

Service Co for Renewal of the OL for the PVNGS, Units 1–3 (ML091130106) 

5/11/2009 Federal Register Notice, NRC Notice of Acceptance for Docketing of the Application and Notice of 

Opportunity for Hearing Regarding Renewal of Facility Operating License No's. NPF-41, NPF-51, 

and NPF-74 for an Additional 20-Year Period Arizona Public Service Co. PVNGS, Units 1,2, 3 

(ML091130187) 

5/20/2009 Press Release-09-088, “NRC Announces Opportunity to Request Hearing on License Renewal 

Application for Palo Verde Nuclear Generating Station” (ML091400201) 

6/17/2009 Summary of telephone conference call between NRC and APS, 6/9/2009, pertaining to the 

PVNGS, Units 1, 2, and 3, LRA (ML091620276) 

6/26/2009 Letter from APS to NRC, PVNGS, Units 1, 2, and 3, License Renewal Application Online Reference 

Portal (ML091880425) 
Appendix B 

 B-2 

Date Subject 

7/23/2009 Letter from Greater Phoenix Chamber of Commerce to Chairman Jaczko, NRC, LTR-09-0380, Ltr. 

Todd Sanders re: NRC's License Renewal Process for the Palo Verde Nuclear Generating Station 

(ML092110612) 

7/30/2009 Letter from Strategic Teaming & Resource Sharing (STARS) to NRC, Strategic Teaming and 

Resource Sharing Schedule for STARS License Renewal Applications (ML092120185) 

8/11/2009 Letter from NRC to APS, Request for Additional Information for the Review of Palo Verde Nuclear 

Generating Station, Units 1, 2, and 3, License Renewal Application (ML092180443) 

8/14/2009 Summary of telephone conference call held between NRC and APS, 8/3/2009, pertaining to the 

PVNGS, Units 1, 2, and 3 LRA (ML092230427) 

8/25/2009 Letter from NRC to APS, Request for Additional Information for the Review of Palo Verde Nuclear 

Generating Station, Units 1, 2, and 3, License Renewal Application (ML092380318) 

9/10/2009 Letter from APS to NRC, PVNGS, Units 1, 2, and 3, Response to Request for Additional 

Information Regarding License Renewal Application (ML092610068) 

9/16/2009 Letter from NRC to APS, Safety Project Manager Change for the License Renewal Project for Palo 

Verde Nuclear Generating Station, Units 1, 2, and 3 (TAC Nos. ME0261-ME0266) (ML092430084) 

9/30/2009 Summary of telephone conference call between NRC and APS, 9/3/2009, to discuss a draft request 

for additional information (RAI) for PVNGS, Units 1, 2, and 3, LRA (ML092470463) 

10/14/2009 PVNGS, Units 1, 2, and 3, Amendment No. 1 to LRA, Revised Environmental Report, Figure 3-2,

and Table 4-2, for the Hassayampa No. 3 Transmission Line (ML092950484) 

11/2/2009 Letter from NRC to APS, Request for Additional Information for the Review of Palo Verde Nuclear 

Generating Station, Units 1, 2, and 3, License Renewal Application (ML092790315) 

11/2/2009 Summary of telephone conference call held between NRC and APS, 10/1/2009, concerning a draft 

RAI pertaining to the PVNGS (ML092800015) 

11/3/2009 Summary of telephone conference call held between NRC and APS, 9/16/2009, pertaining to the 

PVNGS, Units 1, 2, and 3, LRA (ML092750130) 

11/3/2009 Letter from NRC to APS, Request for Additional Information for the Review of Palo Verde Nuclear 

Generating Station, Units 1, 2, and 3, License Renewal Application (ML092750237) 

11/12/2009 Summary of telephone conference call held between NRC and APS, 10/13/2009, concerning draft 

RAIs pertaining to the PVNGS, Units 1, 2, and 3, LRA (ML092890006) 

11/12/2009 Letter from NRC to APS, Request for Additional Information for the Review of Palo Verde Nuclear 

Generating Station, Units 1, 2, and 3, License Renewal Application (ML092890011) 

11/13/2009 Letter from NRC to APS, Request for Additional Information for the Review of Palo Verde Nuclear 

Generating Station, Units 1, 2, and 3, License Renewal Application (ML093090057) 

11/18/2009 Letter from NRC to APS, Plan for the Aging Management Program Audit Regarding the Palo Verde 

Nuclear Generating Station, Units 1, 2, & 3 License Renewal Application Review (TAC Nos. 

ME0254, ME0255, ME0256) (ML093090246) 

12/3/2009 Letter from NRC to APS, Request for Additional Information for the Review of Palo Verde Nuclear 

Generating Station, Units 1, 2, and 3, License Renewal Application (ML093080557) 

12/3/2009 Summary of telephone conference call held between NRC and APS, 10/22/2009, concerning a 

draft RAI pertaining to the PVNGS, Units 1, 2, and 3, LRA (ML093170428) 

12/4/2009 Letter from NRC to APS, Request for Additional Information for the Review of Palo Verde Nuclear 

Generating Station, Units 1, 2, and 3, License Renewal Application (ML093200413) 

12/7/2009 PVNGS, Units 1, 2, and 3, Submittal of annual update to the LRA and LRA, Amendment No. 3 

(ML093500101) 

12/11/2009 Letter from APS to NRC, PVNGS, Units 1, 2, and 3, Response to Request for Additional 

Information Regarding License Renewal Application (ML093631562) 

12/17/2009 Letter from APS to NRC, PVNGS, Units 1, 2, and 3, Response to Request for Additional 

Information Regarding License Renewal Application (ML093631139) 
 Appendix B 

 B-3 

Date Subject 

12/18/2009 Letter from APS to NRC, PVNGS, Units 1, 2, and 3, Response to Request for Additional 

Information Regarding License Renewal Application (ML093640043) 

12/21/2009 Letter from APS to NRC, PVNGS, Units 1, 2, and 3, Response to Request for Additional 

Information Regarding License Renewal Application (ML100040067) 

12/23/2009 Letter from NRC to APS, Request for Additional Information for the Review of Palo Verde Nuclear 

Generating Station, Units 1, 2, and 3, License Renewal Application (ML093380051) 

12/23/2009 Letter from NRC to APS, Request for Additional Information for the Review of Palo Verde Nuclear 

Generating Station, Units 1, 2, and 3, License Renewal Application (ML093650157) 

12/29/2009 Letter from NRC to APS, Request for Additional Information for the Review of Palo Verde Nuclear 

Generating Station, Units 1, 2, and 3, License Renewal Application (ML093490830) 

1/14/2010 Letter from NRC to APS, Request for Additional Information for the Review of Palo Verde Nuclear 

Generating Station, Units 1, 2, and 3, License Renewal Application (ML093290298) 

1/18/2010 Letter from APS to NRC, PVNGS, Units 1, 2, and 3, Response to Request for Additional 

Information Regarding License Renewal Application (ML100260951) 

1/22/2010 Summary of telephone conference call held between NRC and APS, 1/14/2010, concerning draft 

RAIs pertaining to the PVNGS, Units 1, 2, and 3 LRA (ML100141784) 

1/28/2010 Letter from NRC to APS, Request for Additional Information for the Review of Palo Verde Nuclear 

Generating Station, Units 1, 2, and 3, License Renewal Application (ML100150378) 

2/5/2010 Letter from APS to NRC, PVNGS, Units 1, 2, and 3, Response to Request for Additional 

Information Regarding License Renewal Application (ML100490056) 

2/12/2010 Summary of telephone conference call held between NRC and APS, 1/13/2010, concerning draft 

RAIs pertaining to the PVNGS, Units 1, 2, and 3, LRA (ML100140898) 

2/16/2010 Summary of telephone conference call between NRC and APS, 1/12/2010, concerning draft RAIs 

pertaining to the PVNGS, Units 1 and 2, and 3, LRA (ML100131215) 

2/19/2010 Letter from NRC to APS, Request for Additional Information for the Review of Palo Verde Nuclear 

Generating Station, Units 1, 2, and 3, License Renewal Application (ML100270069) 

2/19/2010 Summary of telephone conference call held between NRC and APS, 1/28/2010, concerning draft 

RAIs pertaining to the PVNGS, Units 1, 2, and 3, LRA (ML100320041) 

2/19/2010 Letter from APS to NRC, PVNGS, Units 1, 2, and 3, Response to Request for Additional 

Information Regarding License Renewal Application (ML100610604) 

2/19/2010 Letter from NRC to APS, Palo Verde, Unit 1, Notification of Inspection (IR 05000528-10-002) and 

Request for Information (ML100502137) 

3/1/2010 Letter from APS to NRC, PVNGS, Units 1, 2, and 3, Response to Request for Additional 

Information Regarding License Renewal Application (ML100680517) 

3/1/2010 Letter from APS to NRC, PVNGS, Units 1, 2, and 3, Response to Request for Additional 

Information Regarding License Renewal Application (ML100680518) 

3/2/2010 Letter from NRC to APS, Request for Additional Information for the Review of Palo Verde Nuclear 

Generating Station, Units 1, 2, and 3, License Renewal Application (ML100360296) 

3/12/2010 Summary of telephone conference call held between NRC and APS, 1/8/2010, concerning 

containment coatings pertaining to the PVNGS, Units 1, 2, and 3, LRA (ML100150618) 

3/12/2010 Summary of telephone conference call held between NRC and APS, 2/24/2010, concerning draft 

RAIs pertaining to the PVNGS, Units 1, 2, and 3, LRA (ML100610216) 

3/15/2010 Summary of telephone conference call held between NRC and APS, 3/10/2010, concerning the 

PVNGS, Units 1, 2, and 3 LRA (ML100700618) 

3/24/2010 Letter from APS to NRC, PVNGS, Units 1, 2, and 3, Response to Request for Additional 

Information Regarding License Renewal Application (ML100920055) 

4/1/2010 Letter from APS to NRC, PVNGS, Units 1, 2, and 3, Response to Request for Additional 

Information Regarding License Renewal Application (ML101050045) 
Appendix B 

 B-4 

Date Subject 

4/2/2010 Letter from APS to NRC, PVNGS, Units 1, 2, and 3, Response to Request for Additional 

Information Regarding License Renewal Application (ML101050015) 

4/7/2010 Letter NRC to APS, Audit Report Regarding the Palo Verde Nuclear Generating Station, Units 1, 2, 

and 3, License Renewal Application (TAC Nos. ME0254, ME0255, ME0256) (ML100221296) 

4/8/2010 Letter from NRC to APS, Request for Additional Information for the Review of Palo Verde Nuclear 

Generating Station, Units 1, 2, and 3, License Renewal Application (ML100960367) 

4/20/2010 Notice of public working meeting with APS, 5/6/2010, to discuss issues related to the PVNGS LRA

(ML100980482) 

4/20/2010 Letter from NRC to APS, 3/30/2010, Summary of Meeting With Arizona Public Service Company to 

Discuss Inspection Results for License Renewal Inspection of Nonsafety-related Scoping & 

Selected Aging Management Programs Conducted Onsite in February 2010 & Documented in 

IR-10-007 (ML101110595) 

4/27/2010 Summary of telephone conference call between NRC and APS, 4/9/2010, concerning draft RAIs

pertaining to the PVNGS, Units 1, 2, and 3, LRA (ML101060640) 

4/28/2010 Letter from NRC to APS, Request for Additional Information for the Review of Palo Verde Nuclear 

Generating Station, Units 1, 2, and 3, License Renewal Application (ML101160357) 

4/28/2010 Letter from APS to NRC, PVNGS, Units 1, 2, and 3, Supplemental Response to Request for 

Additional Information Regarding License Renewal Application (ML101320262) 

4/29/2010 NRC Inspection Reports; IR 05000528-10-007, 05000529-10-007, 05000530-10-007; 2/1/2010–

2/26/2010; PVNGS; Scoping of Nonsafety-Related Affecting Safety-Related Systems and Review 

of License Renewal Aging Management Programs (ML101190585) 

4/29/2010 Letter APS to NRC, PVNGS, Units 1, 2, and 3, Response to Request for Additional Information 

Regarding License Renewal Application (ML101310227) 

5/7/10 Letter from APS to NRC, PVNGS, Units 1, 2, and 3, Commitment to Incorporate in the Updated 

Final Safety Analysis Report a Requirement to Periodically Assess the Containment Building 

Interior Coating System (ML101390211) 

5/21/2010 Letter from APS to NRC, PVNGS, Units 1, 2, and 3, Response to Request for Additional 

Information Regarding License Renewal Application (ML101540063) 

5/28/2010 Letter from APS to NRC, PVNGS, Units 1, 2, and 3, License Renewal Application Amendment 

No. 16 (ML101600451) 

6/2/2010 Summary of telephone conference call held between NRC and APS, 4/13/2010, concerning draft 

RAIs pertaining to the PVNGS, Units 1, 2, and 3, LRA (ML101330252) 

6/2/2010 Summary of telephone conference call held between NRC and APS, 4/23/2010, concerning the 

PVNGS, Units 1, 2, and 3, LRA (ML101330286) 

6/2/2010 Letter from NRC to APS, Request for Additional Information for the Review of Palo Verde Nuclear 

Generating Station, Units 1, 2, and 3, License Renewal Application (ML101340100) 

6/2/2010 Summary of telephone conference call held between NRC and APS, 4/12/2010, concerning the 

PVNGS, Units 1, 2, and 3, LRA (ML101340666) 

6/2/2010 Summary of telephone conference call held between NRC and APS, 5/14/2010, concerning the 

PVNGS, Units 1, 2, and 3, LRA (ML101340704) 

6/2/2010 Summary of telephone conference call held between NRC and APS, 4/14/2010, concerning draft 

RAIs pertaining to the PVNGS, Units 1, 2, and 3, LRA (ML101340788) 

6/21/2010 PVNGS, Units 1, 2, and 3, Responses to follow-up RAIs regarding buried piping, elastomers, 

compressed air, containment liner, spray ponds, and supports for the review of the PVNGS 

(ML101820185) 

6/25/2010 Summary of telephone conference calls held between NRC and APS, 5/20/2010 and 6/9/2010,

concerning draft RAIs pertaining to the PVNGS, Units 1, 2, and 3, LRA (ML101600547) 

6/25/2010 Summary of public meeting held between NRC and APS, 5/6/2010, concerning the metal fatigue 

review pertaining to the PVNGS, Units 1, 2, and 3, LRA (ML101340802) 
 Appendix B 

 B-5 

Date Subject 

6/29/2010 PVNGS; Units 1, 2, and 3; Docket Nos. STN 50-528, 50-529, and 50-530; 6/2/2010; Response to 

Request for Additional Information Regarding Metal Fatigue for the Review of the PVNGS License 

Renewal Application, and License Renewal Application Amendment No. 18 (ML101880278) 

7/6/2010 Summary of telephone conference calls held between NRC and APS concerning a draft RAI

associated with aging management of the compressed air system related to the PVNGS, Units 1, 2, 

and 3, LRA (ML101370289) 

7/7/2010 PVNGS; Units 1, 2, and 3; Docket Nos. STN 50-528, 50-529, and 50-530; Supplemental Response 

to Request for Additional Information Regarding Time Limited Aging Analysis for the Review of the 

PVNGS License Renewal Application, and License Renewal Application Amendment No. 19 

(ML101970058) 

7/13/2010 Scoping and Screening Audit Report for the PVNGS, Units 1, 2, and 3, LRA (ML101740217)

7/14/2010 Summary of telephone conference calls held between NRC and APS concerning a draft RAI 

pertaining to the PVNGS, Units 1, 2, and 3, LRA (ML101340829) 

7/19/2010 Summary of telephone conference calls held between NRC and APS concerning a draft RAI 

pertaining to the PVNGS, Units 1, 2, and 3, LRA (ML101760027) 

7/20/2010 Summary of telephone conference call held between NRC and APS, 7/8/2010, concerning a draft 

RAI pertaining to the PVNGS, Units 1, 2, and 3, LRA (ML101900058) 

7/21/2010 Palo Verde Nuclear Generating Station (PVNGS), Units 1,2, and 3, Docket Nos. STN 50-528, 

50-529 and 50-530, Updated License Renewal Application Commitment List, and License Renewal 

Application Amendment No. 20 (ML102100096) 

7/21/2010 RAI for the review of PVNGS, Units 1, 2, and 3, LRA (ML101890891)

7/23/2010 Summary of telephone conference call held between NRC and APS, 6/17/2010, concerning a draft 

RAI pertaining to the PVNGS, Units 1, 2, and 3, LRA (ML101730331) 

7/30/2010 Palo Verde, Units 1, 2 & 3 - Responses to Follow-Up Request for Additional Information Regarding 

Small Bore Piping Socket Welds and Other Items for the Review of the PVNGS License Renewal 

Application, and License Renewal Application Amendment No. 21 (ML102240166) 

8/5/2010 PVNGS - Follow-up of License Renewal Unresolved Item - Inspection Report 05000528, 

05000529, 05000530/2010010 (ML102190239) 

8/6/2010 PVNGS License Renewal - Safety Evaluation Report with Open Items (ML102210072) 

8/6/2010 PVNGS - Transmittal letter to Arizona Public Service Company with Safety Evaluation Report with 

Open Items (ML102150416) 

8/9/2010 Transmittal Letter to Advisory Committee on Reactor Safeguards Review of the PVNGS, Units 1, 2, 

and 3, LRA - SER with Open Items (ML102130350) 

8/12/2010 PVNGS, Units 1, 2, and 3, Response to the July 21, 2010, Request for Additional Information 

Regarding Metal Fatigue for the Review of the PVNGS License Renewal Application, and License 

Renewal Application Amendment No. 22 (ML102360335) 

8/27/2010 PVNGS, Units 1, 2, and 3, Revised Commitment Date to Drain the Spray Chemical Addition Tanks, 

and License Renewal Application Amendment No. 23 (ML102510187) 

9/3/2010 PVNGS, Units 1, 2, and 3, Supplemental Responses to Request for Additional Information

Regarding Small Bore Piping Socket Welds and Cavitation Erosion Related to the PVNGS License 

Renewal Application (ML102571399) 

9/8/2010 Transcript of Advisory Committee on Reactor Safeguards Plant License Renewal Subcommittee, 

PVNGS, Units 1, 2, and 3, on September 8, 2010 in Rockville, MD, pages 1-156 (ML102590478) 

9/15/2010 PVNGS, Units 1, 2 and 3 - Supplemental Responses to Request for Additional Information 

Regarding Small Bore Piping Socket Welds and Cavitation Erosion License Renewal Application 

(ML102571399) 

9/17/2010 PVNGS, Units 1, 2 and 3 - Annual Update to License Renewal Application, and LRA Amendment 

No. 24 (ML102730057) 

9/27/2010 RAI for the review of PVNGS, Units 1, 2, and 3, LRA (ML102560022)
Appendix B 

 B-6 

Date Subject 

9/29/2010 PVNGS, Units 1, 2 and 3 - Comments on the Safety Evaluation Report with Open Items Related to 

License Renewal (ML102810502) 

10/5/2010 Summary of telephone conference call held between NRC and APS, 8/31/2010, concerning a draft 

RAI pertaining to the PVNGS, Units 1, 2, and 3, LRA (ML102430338) 

10/7/2010 Summary of telephone conference call held between NRC and APS, 9/22/2010, concerning a draft 

RAI pertaining to the PVNGS, Units 1, 2, and 3, LRA (ML102660130) 

10/13/2010 PVNGS, Units 1, 2 and 3 - Responses to Requests for Additional Information for the Review of the 

PVNGS License Renewal Application (LRA), and LRA Amendment No. 25 (ML102930032) 

10/15/2010 Summary of telephone conference call held between NRC and APS, 7/8/2010, concerning a draft 

RAI pertaining to the PVNGS, Units 1, 2, and 3, LRA (ML101940142) 

10/15/2010 Summary of telephone conference call held between NRC and APS, 7/21/2010, concerning a draft 

RAI pertaining to the PVNGS, Units 1, 2, and 3, LRA (ML102030500) 

10/15/2010 Summary of telephone conference call held between NRC and APS, 9/22/2010, concerning a draft 

RAI pertaining to the PVNGS, Units 1, 2, and 3, LRA (ML102660067) 

10/18/2010 Summary of telephone conference call held between NRC and APS, 6/16/2010, concerning a draft 

RAI pertaining to the PVNGS, Units 1, 2, and 3, LRA (ML101740110) 

11/10/2010 PVNGS, Units 1, 2, and 3, Response to Draft Request for Additional Information for the Review of 

License Renewal Application and LRA Amendment No. 26 (ML103280058) 

11/16/2010 Summary of telephone conference calls held between NRC and APS, 10/22/2010 and 11/3/2010, 

concerning a Draft RAI pertaining to the PVNGS, Units 1, 2, and 3, LRA (ML102990530) 

11/16/2010 Summary of telephone conference call held between NRC and APS, 10/28/2010, concerning a 

Draft Follow-up RAI pertaining to the PVNGS, Units 1, 2, and 3, LRA (ML103010523) 

11/23/2010 PVNGS, Units 1, 2, and 3, Response to Draft Request for Additional Information for the Review of 

License Renewal Application and LRA Amendment No. 27 (ML103420101) 

12/3/2010 PVNGS, Units 1, 2, and 3, Response to Draft Request for Additional Information for the Review of 

License Renewal Application and LRA Amendment No. 28 (ML103490138) 

12/6/2010 Summary of telephone conference call held between NRC and APS, 11/19/2010, concerning a 

Draft Follow-up RAI pertaining to the PVNGS, Units 1, 2, and 3, LRA (ML103280174) 

12/16/2010 PVNGS, Units 1, 2, and 3, Correction to License Renewal Application Section B2.1.10, 

Closed-Cycle Cooling Water System (ML103630422) 

1/7/2011 PVNGS, Units 1, 2, and 3, Region IV Administrator License Renewal Recommendation Letter 

(ML110100400) 

1/11/2011 Summary of telephone conference call held between NRC and APS, 1/11/2011, concerning an RAI 

response pertaining to the PVNGS, Units 1, 2, and 3, LRA (ML110070256) 

1/26/2011 Update to License Renewal Application (LRA) Section A3/2/1/5, LRA Amendment No. 29 

(ML110350035) 

2/25/2011 PVNGS, Units 1, 2, and 3, Correction to Response to Request for Additional Information for the 

Review of the PVNGS License Renewal Application (LRA), and LRA Amendment No. 30 

(ML110670168) 

3/1/2011 Letter to the Honorable Gregory B. Jaczko, Chairman, from Said Abdel-Khalik, ACRS Chairman, 

dated March 1, 2011, Subject: Report on the Safety Aspects of the License Renewal Application 

for the Palo Verde Nuclear Generating Station (ML110700690) 

3/4/2011 PVNGS, Units 1, 2, and 3, Correction of Typographical Error in Safety Evaluation Report Realted to 

License Renewal (TAC Nos. ME0254, ME0255, and ME0256) (ML110490540) 

3/17/2011 PVNGS, Units 1, 2, and 3, Clarification to Response to Request for Additional Information for the 

Review of the PVNGS License Renewal Application (LRA), and LRA Amendment No. 31 

(ML110880072) 

 
 

 
 

 C-1 

APPENDIX C 

Principal Contributors 

This appendix lists the principal contributors for the development of this safety evaluation report 

and their areas of responsibility. 

Name Responsibility 

A. Hiser Management Oversight

A. Klein Management Oversight

A. Johnson Reviewer—Reactor Systems and Mechanical

A. Paulson Reviewer—Mechanical

A. Sheikh Reviewer—Structural

A. Ulses Management Oversight

A. Wong Reviewer—Mechanical

B. Fu Reviewer—Reactor Systems

B. Holian Management Oversight

B. Lehman Reviewer—Structural

B. Parks Reviewer—Reactor Systems

B. Rogers Reviewer—Scoping and Screening Methodology

C. Ng Reviewer—Reactor Systems

C. Doutt Reviewer—Electrical

D. Alley Reviewer—Mechanical

D. Hoang Reviewer—Structural

D. Nguyen Reviewer—Aging Management Programs and Electrical

D. Pelton Management Oversight

D. Wrona Management Oversight

E. Smith Reviewer—Scoping and Screening Methodology

E. Wong Reviewer—Chemical

G. Casto Management Oversight

G. Cranston Management Oversight

G. Shukla Management Oversight

H. Ashar Reviewer—Structural

J. Bettle Reviewer—Mechanical

J. Collins Reviewer—Reactor Systems

J. Davis Reviewer—Aging Management Programs 

J. Dozier Management Oversight

J. Gavula Reviewer—Mechanical

J. Medoff Reviewer—Reactor Systems

J. Robinson Reviewer—Mechanical

J. Rowley Project Management
Appendix C 

 C-2 

Name Responsibility 

J. Shea Reviewer—Scoping and Screening Methodology

J. Tsao Reviewer—Reactor Systems

L. Banic Reviewer—Reactor Systems

L. Regner Senior Project Management

M. Kichline Reviewer—Mechanical

M. Mitchell Management Oversight

N. Iqbal Reviewer—Fire Protection

O. Yee Reviewer—Mechanical

R. Auluck Management Oversight

R. Dennig Management Oversight

R. Sun Reviewer—Mechanical

S. Lee Management Oversight

S. Min Reviewer—Reactor Systems

S. Sheng Reviewer—Reactor Systems

W. Smith Reviewer—Mechanical

W. Holston Reviewer—Mechanical

Contractors 

Advanced Technologies and Laboratories International, Inc. 

J. Davis Reviewer—Reactor Systems

W. Jackson Reviewer—Reactor Systems

E. Patel Reviewer—Reactor Systems

W. Pavanich Reviewer—Reactor Systems

Center for Nuclear Waste Regulatory Analysis 

K. Axler Reviewer—Mechanical

K. Chiang Reviewer—Reactor Systems

T. Mintz Reviewer—Mechanical

R. Kazban Reviewer—Reactor Systems

E. Trillo Reviewer—Mechanical

Oak Ridge National Laboratory 

D. Naus Reviewer—Structural

 
 

 D-1 

APPENDIX D 

References 

This appendix lists the references used throughout this safety evaluation report for review of the 

license renewal application for the Palo Verde Nuclear Generating Station, Units 1, 2, and 3. 

References 

10 CFR Part 50, “Domestic Licensing of Production and Utilization Facilities” 

10 CFR Part 54, “Requirements for Renewal of Operating Licenses for Nuclear Power Plants” 

10 CFR Part 100, “Reactor Site Criteria” 

American Concrete Institute (ACI), 201, “Durability of Concrete” 

ACI, 201.2R, “Guide to Durable Concrete” 

ACI, 211.1, “Standard Practice for Selecting Proportions for Normal, Heavyweight, and Mass 

Concrete” 

ACI, 318, “Building Code Requirements for Structural Concrete” 

ACI, 349, “Code Requirements for Nuclear Safety-Related Concrete Structures” 

American National Standards Institute (ANSI), B31.1, “Power Piping” 

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

Section III, “Rules for Construction of Nuclear Power Plant Components” 

ASME Boiler and Pressure Vessel Code, Section XI, “Rules for Inservice Inspection of Nuclear 

Power Plant Components” 

ASME Code, Section XI, Appendix G, “Fracture Toughness Criteria for Protection Against 

Failure” 

ASME Code, Case N-512, “Assessment of Reactor Vessels with Low Upper-Shelf Charpy 

Impact Energy Levels” 

American Society for Metals (ASM), “Metals Handbook® Desk Edition,” 1985 

American Society for Testing Materials (ASTM), Special Technical Publication 1005, “Distillate 

Fuel: Contamination, Storage and Handling” 

ASTM, C 33, “Standard Specification for Concrete Aggregates” 

ASTM, D 96, “Standard Test Method for Water and Sediment in Crude Oil by Centrifuge Method 

(Field Procedure)” 

ASTM, E 185, “Standard Practice for Design of Surveillance Programs for Light-Water 

Moderated Nuclear Power Reactor Vessels” 

ASTM, C 227, “Standard Test Method for Potential Alkali Reactivity of Cement-Aggregate 

Combinations (Mortar-Bar Method)” 

ASTM, C 289, “Standard Test Method for Potential Alkali-Silica Reactivity of Aggregates 

(Chemical Method)” 

ASTM, C 295, “Standard Guide for Petrographic Examination of Aggregates for Concrete” 

ASTM, D 445, “Standard Test Method for Kinematic Viscosity of Transparent and Opaque 

Liquids” 
Appendix D 

 D-2 

ASTM, D 975, “Standard Practice for Manual Sampling of Petroleum and Petroleum Products” 

ASTM, D 1796, “Standard Practice for Manual Sampling of Petroleum and Petroleum Products” 

ASTM, D 2276, “Standard Test Method for Particulate Contaminant in Aviation Fuel by Line 

Sampling” 

ASTM, D 2709, “Standard Practice for Manual Sampling of Petroleum and Petroleum Products” 

ASTM, D 4057, “Standard Practice for Manual Sampling of Petroleum and Petroleum Products” 

ASTM, D 4378, “Standard Practice for In-Service Monitoring of Mineral Turbine Oils for Steam 

and Gas Turbines” 

ASTM, D 4951, “Standard Test Method for Determination of Additive Elements in Lubricating 

Oils by Inductively Coupled Plasma Atomic Emission Spectrometry” 

ASTM, D 6217, “Standard Test Method for Particulate Contamination in Middle Distillate Fuels 

by Laboratory Filtration” 

ASTM, D 6224, “Standard Practice for In-Service Monitoring of Lubricating Oil for Auxiliary 

Power Plant Equipment” 

ASTM, D 6595, “Determination of Wear Metals and Contaminants in Used Lubricating Oils or 

Used Hydraulic Fluids by Rotating Disc Electrode Atomic Emissions Spectroscopy” 

Bauer, Scott A., Arizona Public Service Company (APS), letter to U.S. Nuclear Regulatory 

Commission (NRC), “Palo Verde Nuclear Generating Station Unit 2, Reactor Vessel Material 

Surveillance Capsule at 230°,” 102-05457-SAB/TNW/RJR, Docket 50-529, April 4, 2006 

(Agencywide Document Access and Management System (ADAMS) Accession 

Number ML061040590) 

Booser, R.E., “CRC Handbook of Lubrication,” CRC Press, Inc., Volumes 1 and 2, 1983 

Combustion Engineering (CE), Letter LD-83-053, A. E. Scherer to Darrell G. Eisenhut, NRC 

Docket No. STN 50-470F, “Basis for Design of Plant Without Pipe Whip Restraints,” 

June 14, 1983 (ADAMS Public Legacy Library Accession No. 8306200254). 

CE, Letter LD-83-108, A. E. Scherer to Darrell G. Eisenhut, NRC Docket No. STN 50-470F, 

“Basis for Design of Plant Without Pipe Whip Restraints,” December 23, 1983 (ADAMS Public 

Legacy Library Accession No. 8312300117) With enclosed, Leak Before Break Evaluation of the 

Main Loop Piping of a CE Reactor Coolant System, Revision 1, November 1983 

CE, Letter LD-83-053, A. E. Scherer to Darrell G. Eisenhut, NRC Docket No. STN 50-470F, 

“Basis for Design of Plant Without Pipe Whip Restraints,” June 14, 1983 (ADAMS Public Legacy 

Library Accession No. 8306200254) 

CE, Letter to A. E. Scherer, “CESSAR System 80 Safety Evaluation Report (NUREG-0852) 

Removal of Pipe Whip Restraints,” October 11, 1984 (ADAMS Public Legacy Library Accession 

No. 8410240182) 

“Cooper-Bessemer Model KSV Emergency Diesel Generator Lubricating Oil and Jacket Water 

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Electric Power Research Institute (EPRI), EPRI No. CS-4555, “Guidelines for Maintaining 

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EPRI, NP-4916, “Lubrication Guide,” January 1987 

EPRI, NP-5067, “Good Bolting Practices, A Reference Manual for Nuclear Power Plant 

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Threaded Fasteners,” 1990 
 Appendix D 

 D-3 

EPRI, NP-5769, “Degradation and Failure of Bolting in Nuclear Power Plants,” Volumes 1 and 2, 

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EPRI, Technical Report (TR)-104213 “Bolted Joint Maintenance and Application Guide,” 

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EPRI, TR-107396, “Closed Cooling water chemistry Guideline,” October 31, 1997 

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January 16, 2001 

EPRI TR-1008224, “PWR Secondary Water Chemistry Guidelines,” Revision 6, 

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EPRI, TR-1016456, “Recommendations for an Effective Program to Control the Degradation of 

Buried Pipe,” December 2008 

“Evaluation of Reactor Pressure Vessels with Charpy Upper-Shelf Energy Less than 50 Ft-Lb,” 

Draft Guide (DG)-1023, September 1993 

Generic Letter (GL) 86-10, “Implementation of Fire Protection Requirements,” April 24, 1986 

GL 88-05, “Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in 

PWR plants,” March 17, 1988 

GL 89-08, “Erosion/Corrosion-Induced Pipe Wall Thinning,” May 2, 1989 

GL 89-13, “Service Water System Problems Affecting Safety-Related Equipment,” July 18, 1989 

GL 92-01, “Reactor Vessel Structural Integrity,” February 28, 1992 

GL 2004-02, “Potential Impact of Debris Blockage on Emergency Recirculation during Design 

Basis Accidents at Pressurized-Water Reactors,” September 13, 2004 

GL 2007-01, “Inaccessible or Underground Power Cable Failures that Disable Accident 

Mitigation Systems or Cause Plant Transients,” February 7, 2007 

International Organization for Standardization (ISO), ISO 4406, “Hydraulic Fluid Power - Fluids - 

Method for Coding the Level of Contamination by Solid Particles - Second Edition” 

Letter from Christopher I. Grimes, NRC, to Douglas J. Walters, NEI, License Renewal Issue 

No. 98-0030, “Thermal Aging Embrittlement Of Cast Austenitic Stainless Steel Components,” 

May 19, 2000 (ML003717179) 

Letter from David B. Matthews, NRC, to Messrs. Alan Nelson and David Lochbaum, “Staff 

Guidance on Scoping of Equipment Relied on to Meet the Requirements of the Station Blackout 

Rule (10 CFR 50.63) for License Renewal (10 CFR 54.4(a)(3)),” April 1, 2002 

Letter from Pao-Tsin Kuo, NRC, to Messrs. Alan Nelson and David Lochbaum, “Standardized 

Format for License Renewal Applications,” April 7, 2003 

License Renewal Interim Staff Guidance (LR-ISG)-2007-02, “Changes to Generic Aging Lesson 

Learned (GALL) Report Aging Management Program (AMP) XI.E6, ‘Electrical Cable 

Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements,” issued 

for public comment by letter dated August 29, 2007 (ML072420437) 

Metals Handbook, Ninth Edition, Vol. 13, Metals Park, Ohio, 1987 

National Academy of Sciences (NAS), 1638, “Cleanliness Requirements of Parts Used in 

Hydraulic Systems,” August 2001 
Appendix D 

 D-4 

National Fire Protection Association (NFPA), “NFPA 25, Standard for the Inspection, Testing, 

and Maintenance of Water-Based Fire Protection Systems,” 1998 and 2002 editions 

“Notice of availability of the final ISG LR ISG-2007-02,” Federal Register, December 23, 2009 

(74 FR 68287) 

Nuclear Administrative Technical Manual (NATM) 

Nuclear Energy Institute (NEI), “NUMARC 93-01, Rev. 2, Industry Guideline for Monitoring the 

Effectiveness of Maintenance of Nuclear Power Plants,” April 1996 

NEI, TR 95-10, Revision 6, “Industry Guideline for Implementing the Requirements of 

10 CFR Part 54 - The License Renewal Rule,” June 2005. 

NEI, TR 97-06, “Steam Generator Program Guidelines” 

NEI, TR 07-07, “Industry Ground Water Protection Initiative, Final Guidance Document,” 

August 2007 

Nuclear Management and Resources Council, Letter to W.H. Rasin, “Safety Assessment of 

WCAP-13587, Revision 1, ‘Reactor Vessel Upper Shelf Energy Bounding Evaluation for 

Westinghouse Pressurized Water Reactors,’ September 1993,” April 21, 1994 (ADAMS Public 

Legacy Library Accession No. 9405060287) 

NRC, Branch Technical Position (BTP) APCSB 9.5-1, “Guidelines for Fire Protection for Nuclear 

Power Plants” 

NRC, BTP IQMB-1, “Quality Assurance for Aging Management Programs” 

NRC, BTP RLSB-1, “Aging Management Review – Generic” 

NRC, Bulletin 02-01, “Reactor Pressure Vessel Head Degradation and Reactor Coolant 

Pressure Boundary Integrity,” March 18, 2002 

NRC, Bulletin 02-02, “Reactor Pressure Vessel Head and Vessel Head Penetration Nozzle 

Inspection Programs,” August 9, 2002 

NRC, Bulletin 03-02, “Leakage from Reactor Pressure Vessel Lower Head Penetrations and 

Reactor Coolant Pressure Boundary Integrity,” August 21, 2003 

NRC, Bulletin 80-11, “Masonry Wall Design,” May 8, 1980 

NRC, Bulletin 88-02, “Rapidly Propagating Fatigue Cracks in Steam Generator Tubes,” 

February 5, 1988 

NRC, Bulletin 88-08, “Thermal Stresses in Piping Connected to Reactor Cooling Systems,” 

June 22, 1988 

NRC, Bulletin 88-09, “Thermal Stresses in Piping Connected to Reactor Cooling Systems,” 

July 26, 1988 

NRC, Bulletin 88-11, “Pressurizer Surge Line Thermal Stratification,” December 20, 1988 

NRC, Information Notice (IN) 00-14, “Non-Vital Bus Fault Leads to Fire and Loss of Offsite 

Power,” September 27, 2000 

NRC, IN 02-12, “Submerged Safety-Related Electrical Cables,” April 21, 2002 

NRC, IN 09-04, “Age-Related Constant Support Degradation”, February 18, 2004 

NRC, IN 87-67, “Lessons Learned from Regional Inspections of Licensee Actions in Response 

to IE Bulletin 80-11,” December 31, 1987 

NRC, IN 89-53, “Rupture of Extraction Steam Line on High Pressure Turbine,” June 13, 1989 
 Appendix D 

 D-5 

NRC, IN 89-64: “Electrical Bus Bar Failures,” September 7, 1989 

NRC, IN 90-04, “Cracking of the Upper Shell-to-Transition Cone Girth Welds in Steam 

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NRC, IN 91-19, “Steam Generator Feedwater Distribution Piping Damage,” March 12, 1991 

NRC, IN 94-59, “Accelerated Dealloying of Cast Aluminum-Bronze Valves Caused by 

Microbiologically Induced Corrosion,” August 17, 1994 

NRC, IN 94-63, “Boric Acid Corrosion of Charging Pump Casing Caused by Cladding Cracks,” 

August 30, 1994 

NRC, IN 97-11, “Cement Erosion From Containment Subfoundations at Nuclear Power Plants,” 

March 21, 1997 

NRC, IN 97-84, “Rupture in Extraction Steam Piping as a Result of Flow-Accelerated 

Corrosion,” December 11, 1997 

NRC, IN 99-10, “Degradation of Prestressing Tendon Systems in Prestressed Concrete 

Containments,” April 13, 1999 

Nuclear Safety Analysis Center (NSAC)-202L-R2, “Recommendations for an Effective 

Flow-Accelerated Corrosion Program,” April 1999 

NSAC-202L-R3, “Recommendations for an Effective Flow Accelerated Corrosion Program,” 

December 2006 

NUREG/CR-6260, “Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear 

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NUREG/CR-6583, “Effects of LWR Coolant Environments on Fatigue Design Curves of Carbon 

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NUREG-0138, “Staff Discussion of Fifteen Technical Issues Listed in Attachment to 

November 3, 1976 Memorandum from Director, NRR to NRR Staff,” November 1976. 

NUREG-0313, “Technical Report on Material Selection & Processing GL For BWR Coolant 

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Power Plant,” May 2004 
Appendix D 

 D-6 

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Unit 1 Reactor Vessel Radiation Surveillance Program,” February 2005 
 Appendix D 

 D-7 

WCAP-16449-NP, “Analysis of Capsule 230° from Arizona Public Service Company Palo Verde 

Unit 3 Reactor Vessel Radiation Surveillance Program,” August 2005 

WCAP-16524-NP, “Analysis of Capsule 230° from Arizona Public Service Company Palo Verde 

Unit 2 Reactor Vessel Radiation Surveillance Program,” February 2006 
 
BIBLIOGRAPHIC DATA SHEET

(See instructions on the reverse)

NRC FORM 335

(12-2010)

NRCMD 3.7

U.S. NUCLEAR REGULATORY COMMISSION 1. REPORT NUMBER

 (Assigned by NRC, Add Vol., Supp., Rev.,

 and Addendum Numbers, if any.)

NUREG-1961

3. DATE REPORT PUBLISHED

MONTH

April

YEAR

2011

4. FIN OR GRANT NUMBER

2. TITLE AND SUBTITLE

Safety Evaluation Report Related to the License Renewal of the Palo Verde Nuclear Generating

Station, Units 1, 2, and 3

5. AUTHOR(S)

Lisa M. Regner

6. TYPE OF REPORT

7. PERIOD COVERED (Inclusive Dates)

8. PERFORMING ORGANIZATION - NAME AND ADDRESS (If NRC, provide Division, Office or Region, U.S. Nuclear Regulatory Commission, and mailing address; if contractor,

Division of License Renewal

9. SPONSORING ORGANIZATION - NAME AND ADDRESS (If NRC, type "Same as above"; if contractor, provide NRC Division, Office or Region, U.S. Nuclear Regulatory Commission, 

Same as above

provide name and mailing address.)

and mailing address.)

10. SUPPLEMENTARY NOTES

11. ABSTRACT (200 words or less)

This safety evaluation report (SER) documents the technical review of the Palo Verde Nuclear Generating Station, Units 1, 2,

and 3 (PVNGS), license renewal application (LRA) by the U.S. Nuclear Regulatory Commission (NRC) staff. By letter dated

December 11, 2008, as supplemented by letter dated April 14, 2009, Arizona Public Service Company (the applicant) submitted

the LRA in accordance with Title 10 of the Code of Federal Regulations, Part 54 "Requirements for the Renewal of Operating

Licenses for Nuclear Power Plants." The applicant requested renewal of the PVNGS operating licenses NPF-41 (Unit 1),

NPF-51 (Unit 2), and NPF-74 (Unit 3), for a period of 20 years beyond the current expiration dates of midnight on June 1, 2025,

April 24, 2026, and November 25, 2027, respectively.

On August 6, 2010, the NRC staff issued an SER with Open Item Related to the License Renewal of Palo Verde Nuclear

Generating Station, Units 1, 2, and 3, in which one open item and five confirmatory items were identified as needing further

review. This SER presents the status of the staff's review of information submitted through March 17, 2011, the cutoff date for

consideration in the SER. The open and confirmatory items identified in the SER with Open Item were resolved before the staff

made its final determination. SER Sections 1.5 and 1.6 summarize these open and confirmatory items. SER Section 6.0

provides the staff's final conclusion of the LRA review.

12. KEY WORDS/DESCRIPTORS (List words or phrases that will assist researchers in locating the report.)

Palo Verde Nuclear Generating Station, Units 1, 2, and 3

Arizona Public Service Company

License Renewal

Nuclear Power Plant

10 CFR Part 54

Docket Nos. 50-528, 50-529, 50-530

Aging Management 

Scoping and Screening

Time-Limited Aging Analysis

14. SECURITY CLASSIFICATION

13. AVAILABILITY STATEMENT

unlimited

(This Page)

unclassified

(This Report)

unclassified

15. NUMBER OF PAGES

16. PRICE

NRC FORM 335 (12-2010)

Office of Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001